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Annual
report
2021
The premier energy infrastructure company
in North America, now and in the future.
About
TC Energy
Delivering the energy people need, every day.
Safely. Innovatively. 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 liquids pipelines, along with power
generation and storage facilities, wherever life happens
— we’re there. Guided by our core values of safety,
innovation, responsibility, collaboration and integrity,
our 7,300 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.
Land acknowledgement
Embedded in the lands on which TC Energy operates are
the histories, cultures and traditions of Indigenous groups
across North America. TC Energy thanks the original
inhabitants of these lands — generations past, present
and future — for sharing your homelands with us.
Our vision
To be North America’s premier energy infrastructure
company, now and in the future.
Our sustainability and
ESG commitments
Safe, reliable and sustainable operations are foundational in
everything we do — in our culture, with Indigenous groups,
landowners, stakeholder engagements and partnerships,
and in our decision-making. It starts with strong core values.
We uphold these values in our commitments to protect our
planet, create shared prosperity and empower people.
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
at TCEnergy.com/ESG.
Forward-looking information
These pages contain certain forward-looking information.
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, refer to
TC Energy’s 2021 Annual Report filed with Canadian securities
regulators, the U.S. Securities and Exchange Commission and
available at TCEnergy.com
Three complementary
energy infrastructure businesses
Natural Gas
Pipelines
Liquids
Pipelines
Power and
Storage
25 per cent
of North America’s demand
Natural gas plays a critical role in the
global energy transition. It is a reliable,
high-efficiency energy source that
is displacing coal-fired power while
backstopping the intermittency of
renewable power sources.
Our 93,300-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.
3.3+ billion
barrels delivered
Our 4,900-kilometre (3,000-mile)
liquids pipeline system connects
growing continental oil supplies to key
markets and refineries. The Keystone
Pipeline System, our largest liquids
pipeline asset, 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.
Crude oil is expected to remain an
important part of the fuel mix for
decades to come. Our assets are
favourably located in proximity to
production regions that are expected
to remain stable and relevant through
2050 — and our established footprint,
stretching from Alberta to the Gulf
Coast, provides access to offshore
markets. To enhance sustainability, we
aim to reduce the current level of GHG
emissions on our liquids pipelines by 99
per cent by 2025.
4 million+
homes powered
We own or have interests in seven
power generation facilities with
combined capacity of approximately
4,300 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.
As renewable electricity demand
grows across North America, new
hydro, solar, wind and energy storage
capacity will be needed to meet
growing demand and support a
shift in the energy mix. TC Energy
is well positioned to capture these
opportunities given our 20+ years
of experience in the power business
and the multiple projects and
opportunities we have underway.
TC Energy Annual report 2021
| 1
Delivering our
energy future
A message from François and Siim
2 | TC Energy Annual report 2021
In 2021, TC Energy made great strides toward our
vision of being the premier energy infrastructure
company in North America, now and in the
future. As COVID-19 affected lives across the
continent, society’s need for reliable energy did
not waver. Demand for our services remained
strong, our people worked hard and innovated,
and our company continued to grow.
Once again, we maximized the value of our $100
billion asset base and delivered solid results for
our shareholders by:
Generating comparable earnings of
approximately $4.2 billion or $4.27 per
common share1
Producing comparable funds generated from
operations of $7.4 billion1
Placing $4.1 billion of assets into service while
advancing our $24 billion secured
capital program
Strong focus on ESG
In the last year, we also saw increasing momentum
in the world’s push to decarbonize energy systems
and stakeholders’ growing expectations around ESG
matters. This aligns well with our longstanding track
record of fostering a corporate culture founded in
strong core values.
In 2021, we formally added innovation to
our existing values of safety, responsibility,
collaboration and integrity. Innovation is a dynamic
concept within our organization and is particularly
relevant as we navigate the evolution of the energy
industry. We also:
Developed a roadmap to reduce our GHG
emissions intensity by 30 per cent by 2030
and position the company to achieve net zero
emissions from operations by 2050
Published our Indigenous Reconciliation
Action Plan, progressed our goals for partnering
with Indigenous groups and provided our
Board of Directors with Indigenous cultural
awareness training
Directed more than $27 million to foster shared
prosperity in our communities
Promoted diversity of thought, opinion and
perspectives by publishing and implementing
our new Inclusion and Diversity Action Plan
Expanded our ability to measure ESG
performance by introducing new targets aligned
to our 10 sustainability commitments
In 2021, we also further prioritized health and safety
by expanding our conversations to encompass
psychological safety and mental health — issues
which have risen to the surface in society during the
last two years.
We are so grateful for our people, who consistently
invest the care and attention required to ensure
that safe, reliable and sustainable operations are
foundational in everything we do.
1 Comparable earnings, Comparable earnings per share and Comparable funds generated from operations are non-GAAP measures and do not have any standardized meaning under U.S. GAAP and therefore
may not be comparable to similar measures presented by other entities. The most directly comparable U.S. GAAP measures are Net income attributable to common shares, Net income per common share and
Net cash provided by operations, respectively. Refer to the About this document – Non-GAAP measures section of our 2021 Annual MD&A (incorporated by reference herein) for more information and a
reconciliation to the U.S. GAAP equivalents.
TC Energy Annual report 2021
| 3
Complementary businesses position
company for growth
commodity-price and volume-throughput volatility,
aligned with energy demand forecasts and well positioned
to embrace energy transition opportunities.
As we look to the future, TC Energy’s asset map showcases
the company’s unique value proposition. Our well-
connected network of North American assets generates
sustainable returns across five business lines and three
geographies. We move natural gas and oil from some of
the continent’s lowest-cost supply basins to its highest-
demand markets, and we own seven power generation
facilities producing 75 per cent emission-less electricity.
Within North America, TC Energy is uniquely situated at
the intersection of molecules and electrons.
Last year we placed $4.1 billion of assets into service and
sanctioned $7 billion in new projects. These projects will
modernize and expand our base businesses which will be
used and useful for decades to come.
Our assets will also play a role in energy transition by
enabling new technologies to develop and flourish to help
our customers achieve their targeted emission reductions.
This was demonstrated last year as we progressed numerous
energy transition growth initiatives, including opportunities
in renewables, hydrogen, and carbon capture, utilization
and storage (CCUS). As we grow each business, we do so
strategically and with close consideration of the changing
global context.
We have dedicated a considerable amount of time and
effort to expanding our stakeholder engagement and
energy transition capabilities. This increased focus showed
us that we can expect to identify executable lower-
carbon opportunities that align with our established risk
preferences and return expectations.
You can read more about the scope, performance and
growth strategies we intend to employ across our business
in our 2021 Management’s discussion and analysis, and
the steps we are taking in our roadmap to 2050 in
the Supporting decarbonization with partnerships and
innovation section.
Solid performance
For the past 21 years, we have delivered an average
annual total shareholder return of 12 per cent, and our
business continues to perform very well. With a breadth of
services that is approximately 95 per cent rate regulated
or long-term contracted, we are largely insulated from
For the year ended December 31, 2021, we produced
comparable earnings of $4.27 per common share and
comparable funds generated from operations of
$7.4 billion, reflecting the continued strong demand for
our services, new assets placed into service and our focus
on operational excellence.
Given their confidence in the strength of our financial
performance and future, in February 2022 our Board
of Directors increased our quarterly common share
dividend for the twenty-second consecutive year to
$3.60 per share on an annualized basis, an increase of
approximately 3.4 per cent.
Looking forward, as demand grows and technology
evolves, TC Energy is poised to play a vital role in the
energy transition currently unfolding. We are confident
in our ability to deliver sustainable shareholder returns by
capturing investment opportunities that will arise with
increased demand for energy and the move to a lower-
carbon future.
Funding our growth
Between now and 2026 we expect to largely self-fund our
current capital program and anticipated dividend payments
through our substantial internally generated cash flow.
Based on our $24 billion secured capital program and
ongoing maintenance capital, we have a line of sight to
average annual comparable EBITDA2 growth of five per cent.
Further to this, our expected comparable EBITDA profile
through 2026 will be familiar to shareholders, with
approximately 95 per cent generated by regulated and long-
term contracted assets. Through that timeframe we also
expect to enhance our solid credit profile and achieve our
targeted credit metrics.
From capital-light revenue enhancements or cost savings
and system expansions, extensions and modernizations, to a
wide range of energy transition opportunities that meet our
risk/return preferences, we expect our current comparable
EBITDA growth outlook will be enhanced over time.
As always, we will allocate capital in a manner that aims to
maximize growth in earnings, cash flow and dividends per
share and delivers superior long-term shareholder returns.
2 Comparable EBITDA is a non-GAAP measure and does not have any standardized meaning under U.S. GAAP and therefore may not be comparable to similar measures presented by other entities. The most directly
comparable U.S. GAAP measure is Segmented earnings. Refer to the About this document – Non-GAAP measures section of our 2021 Annual MD&A (incorporated by reference herein) for more information and a
reconciliation to the U.S. GAAP equivalent.
4 | TC Energy Annual report 2021
Unparalleled network opens
growth opportunities
Our world-class footprint provides an unparalleled base from which
we will grow and evolve toward a lower-carbon energy future.
Including recoverable maintenance capital, we expect to sanction
$5+ billion of new projects annually through the next decade.
1. IDENTIFYING EFFICIENCIES
Improving the return on our invested
capital through innovation and cost reductions.
2. IN-CORRIDOR GROWTH
Making ongoing investments in expansions,
extensions and modernization programs on our
existing natural gas and liquids infrastructure.
3. LIQUEFIED NATURAL GAS (LNG)
Connecting North American natural gas
supplies to coastlines, enabling LNG to
reach growing global markets —
and offsetting higher emission
fuels such as coal.
4. RENEWABLE POWER
AND STORAGE
Developing wind, solar and
large-scale energy storage —
including solutions to power our own
pipeline network with renewables.
5. FURTHER ENERGY SYSTEM
DECARBONIZATION
Leveraging our world-class footprint,
strong relationships and complementary
capabilities to explore the broad
development of renewable natural gas,
hydrogen, and CCUS solutions.
TC Energy Annual report 2021
| 5
We would also like to extend a special thank you to
Messers. D. Michael G. Stewart, Stephan Cretier
and Randy Limbacher who are retiring from the
Board this April. Mike joined the Board in 2006
and, during his tenure, served as Chair of the
Health, Safety and Environment Committee and
the Governance Committee. Stephan and Randy
joined our Board in 2017 and 2018, respectively,
and they, along with Mike, contributed their
business acumen and unwavering commitment
to upholding TC Energy's values in a manner that
truly served the company and its shareholders
well. We thank Mike, Stephan and Randy for their
many years of service and wish them the best in
their future endeavors.
When you consider TC Energy’s long-term and
predictable cashflows, extensive growth plan, deep-
seated technical capabilities and commitment to
innovate and originate with a focus on ESG, our company
is in a very enviable position. Looking to the future, we
will balance discipline and creativity as we embrace the
vast opportunity set before us. We are grateful for our
people, our management team and our Board for their
unwavering commitment to excellence every day.
To our valued shareholders, thank you for your
continued support.
Sincerely,
François Poirier
President and
CEO
Siim A. Vanaselja
Chair of
the Board
Bright team, bright future
None of this would be possible without our team of 7,300
dedicated and talented people who quietly and reliably
deliver much-needed energy continent-wide. Through
increasingly complex and sometimes challenging times,
they adapt, respond and demonstrate their resilience
every day.
Leading these efforts is an unmatched senior management
team with the complementary talents, grit and innovative
mindsets that differentiate TC Energy and will drive our
continued success. Under the steadfast governance of
our Board of Directors, this management team produces
ongoing results consistent with TC Energy’s long history of
delivering solid returns.
As part of our ongoing Board succession process, we are
pleased to welcome Mr. William D. Johnson to the Board.
Appointed in June 2021, Bill brings strong leadership skills
and decades of experience in the utilities and energy
sector. He has been an invaluable addition to the Board,
and we look forward to his continuing contributions in the
years to come.
6 | TC Energy Annual report 2021
Supporting decarbonization with
partnerships and innovation
EXPLORING OTHER LOW-CARBON PROJECTS
WITH OUR PARTNERS
Signed agreements with both Nikola Corporation
and Hyzon Motors to explore the co-development of
hydrogen hubs in the U.S. and Canada
Announced an agreement with Irving Oil focused on
decarbonizing current assets and deploying emerging
technologies to reduce overall emissions
Announced plans with Pembina Pipeline Corporation to
jointly develop the Alberta Carbon Grid, a world-scale
CCUS system
In 2021 we also became a founding member of the
Emerging Fuels Institute, established by the Pipeline
Research Council International. And, as a signatory to the
Methane Guiding Principles (MGP), we hosted a Methane
Masterclass virtual workshop, targeted to Canadian utility
and oil and gas companies, as part of the MGP 2021 Global
Outreach Program.
Our energy transition strategy includes
reducing our GHG emissions while
simultaneously taking advantage of
the growth opportunities presented by
low-carbon fuels and infrastructure.
Our existing assets will remain essential to future energy
systems and create a sustainable competitive advantage.
We are building collaborative partnerships within industry
to further explore and develop commercially viable
decarbonization projects. Here are some highlights of our
progress in 2021.
MODERNIZING OUR EXISTING SYSTEMS
AND ASSETS
Sanctioned the VR and WR projects which will reduce
emissions, increase throughput and improve the
reliability of certain compressor stations on our
Columbia Gas and ANR pipeline systems in the U.S.
DECARBONIZING OUR ENERGY CONSUMPTION
Launched a request for proposal process to identify
renewable energy sources to power the U.S. portion
of the Keystone Pipeline System
DEVELOPING RENEWABLE ENERGY AND
STORAGE SOLUTIONS
Executed a 15-year power purchase agreement
for 100 per cent of the output from the
297-megawatt Sharp Hills Wind Farm in Alberta
with EDP Renewables
Reached an agreement with the Department
of National Defence to advance
development of the proposed world-class
Ontario Pumped Storage Project
TC Energy Annual report 2021
| 7
Financial
highlights
12%
average annual shareholder
return since 2000
Comparable earnings per common share3
(dollars)
Net income per common share (dollars)
Comparable EBITDA3 (millions of dollars)
2019
2020
2021
4.14
4.20
4.27
2019
2020
2021
4.28
4.74
2019
2020
2021
1.87
9,366
9,351
9,382
Comparable earnings3 (millions of dollars)
Net income attributable to common shares
(millions of dollars)
Total segmented earnings
(millions of dollars)
2019
2020
2021
3,851
3,945
4,153
2019
2020
2021
1,815
3,976
4,457
2019
2020
2021
6,585
6,773
4,059
Dividends declared per common share
(dollars)
Comparable funds generated from
operations3 (millions of dollars)
Net cash provided by operations
(millions of dollars)
2019
2020
2021
3.00
3.24
3.48
2019
2020
2021
7,117
7,385
7,406
2019
2020
2021
7,082
7,058
6,890
Track record of dividend growth
Common share price — Toronto Stock Exchange
$4.00
$3.50
$3.00
$2.50
$2.00
$1.50
$1.00
$0.50
$0.00
$80
$70
$60
$50
$40
$30
$20
$10
$0
2000
2022E
2000
2021
3 Non-GAAP measures which do not have any standardized meanings as prescribed by U.S. generally accepted accounting principles (GAAP) and therefore may not be comparable to similar measures presented by other entities. Refer to
the About this document – Non-GAAP measures section of our 2021 Annual MD&A (incorporated by reference herein) for more information and a reconciliation to the U.S. GAAP equivalents.
8 | TC Energy Annual report 2021
Management's discussion and analysis
February 14, 2022
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, 2021.
This MD&A should also be read in conjunction with our December 31, 2021 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
• 2021 Financial highlights
• Outlook
• Capital program
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
14
15
16
19
27
28
34
42
46
51
55
65
75
81
93
93
105
106
107
108
109
110
120
TC Energy Management's discussion and analysis 2021 | 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 120. All information is as of February 14, 2022
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, including acquisitions
• 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
• statements related to our GHG emissions reduction goals
• expected outcomes with respect to legal proceedings, including arbitration and insurance claims
• 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
• realization of expected benefits from acquisitions, divestitures and energy transition
• 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 2021
Risks and uncertainties
• realization of expected benefits from acquisitions and divestitures
• 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, including those specific to the Keystone XL
pipeline project
• competition in the businesses in which we operate
• unexpected or unusual weather
• acts of civil disobedience
• cyber security and technological developments
• ESG related risks
• impact of energy transition on our business
• 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 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.
TC Energy Management's discussion and analysis 2021 | 11
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. Discussions throughout this MD&A on the factors impacting comparable earnings and
comparable earnings before interest, taxes, depreciation and amortization (comparable EBITDA) are consistent with the factors
that impact net income attributable to common shares and segmented earnings, respectively, except where noted otherwise.
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 in reporting comparable measures 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, valuation allowances and adjustments resulting from changes in legislation and enacted tax rates
• certain fair-value adjustments relating to risk management activities
• legal, contractual and bankruptcy settlements
• impairment of goodwill, plant, property and equipment, investments and other assets
• acquisition and integration costs
• restructuring costs.
We exclude from comparable measures the unrealized gains and losses from changes in the fair value of derivatives related to
financial and commodity price risk management activities. 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 from comparable measures 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
comparable earnings per common share
funds generated from operations
comparable funds generated from operations
GAAP measure
segmented earnings
segmented earnings
net income attributable to common shares
net income per common share
net cash provided by operations
net cash provided by operations
Comparable EBITDA and comparable EBIT
Comparable EBITDA 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 earnings before interest and taxes
(comparable EBIT) 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.
12 | TC Energy Management's discussion and analysis 2021
Comparable earnings and comparable earnings per common share
Comparable earnings represents earnings 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 (working
capital). The components of changes in working capital are disclosed in Note 27, Changes in operating working capital, of our
2021 Consolidated financial statements. We believe funds generated from operations 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 ability of our businesses.
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.
TC Energy Management's discussion and analysis 2021 | 13
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.
14 | TC Energy Management's discussion and analysis 2021
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
Canadian Natural Gas Pipelines
U.S. Natural Gas Pipelines
Mexico Natural Gas Pipelines
Liquids Pipelines
Power and Storage
Corporate
year ended December 31
(millions of $)
Total revenues by segment
Canadian Natural Gas Pipelines
U.S. Natural Gas Pipelines
Mexico Natural Gas Pipelines
Liquids Pipelines
Power and Storage
year ended December 31
(millions of $)
Comparable EBITDA by segment1
Canadian Natural Gas Pipelines
U.S. Natural Gas Pipelines
Mexico Natural Gas Pipelines
Liquids Pipelines
Power and Storage
Corporate
2021
2020
25,213
45,502
7,547
14,951
6,563
4,442
22,852
43,217
7,215
16,744
5,062
5,210
104,218
100,300
2021
2020
4,519
5,233
605
2,306
724
4,469
5,031
716
2,371
412
13,387
12,999
2021
2020
2,675
3,856
666
1,526
683
(24)
9,382
2,566
3,638
786
1,700
677
(16)
9,351
1
For further information on the reconciliation of segmented earnings to comparable EBITDA, refer to the Financial results sections for each business segment.
TC Energy Management's discussion and analysis 2021 | 15
OUR STRATEGY
Our vision is to be the premier energy infrastructure company in North America today and in the future, focused on transporting
and delivering the energy people need every day. Our goal is to develop and build a portfolio of infrastructure assets that will
enable us to prosper irrespective of the pace and direction of energy transition.
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. Our long-term strategy is driven by several key beliefs:
• natural gas will continue to play a pivotal role in North America's energy future
• crude oil will remain an important part of the fuel mix
• the need for renewables along with reliable, on-demand energy sources to support grid stability will grow significantly
• the value of existing infrastructure assets will become more valuable given the challenges to develop new greenfield,
linear-energy infrastructure, in particular, pipelines.
These beliefs drive our capital allocation framework and we will seek to intentionally migrate our portfolio composition over
time.
Allocation of comparable EBITDA1
year ended December 31
Comparable EBITDA by segment
Canadian Natural Gas Pipelines
U.S. Natural Gas Pipelines
Mexico Natural Gas Pipelines
Liquids Pipelines
Power and Storage
2021
29%
41%
7%
16%
7%
100%
1
Refer to Note 4, Segmented information, of our 2021 Consolidated financial statements for an allocation of segmented earnings by business segment.
Future investments will alter our business mix as energy transition unfolds with the following anticipated shifts in capital
allocation:
• Power and Storage weighting in our portfolio is expected to grow
• Natural Gas Pipelines will continue to attract capital
• Liquids Pipelines investment will be targeted and tied to maximizing the value of our asset base
• Measured investment in new technology without taking significant commodity price or volumetric risk.
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.
16 | TC Energy Management's discussion and analysis 2021
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 approximately $24 billion in secured
projects. As well, our noted projects under development are, or are expected to be, largely commercially supported. These investments
will contribute to incremental earnings and cash flows as they are placed in service
• Our existing extensive footprint offers significant in-corridor growth opportunities. This includes possible future opportunities to deploy
low-emissions infrastructure technologies such as renewables, hydrogen and carbon capture, which will help reduce our and our
customers' carbon footprint and also supports extending the longevity of our existing assets
• We continue to develop projects and manage construction risk in a disciplined manner that maximizes capital efficiency 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 a project's early stages
• We will advance selected opportunities, including energy transition growth initiatives, 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 enables 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.
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 through:
• 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. Our portfolio of assets support transporting both molecules and
electrons, providing us flexibility to allocate capital towards electrification or other emerging low-carbon technologies in
support of any energy transition scenario
TC Energy Management's discussion and analysis 2021 | 17
• 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. The 2021 Report on Sustainability builds on our commitment to establishing clear metrics and
targets for 10 sustainability commitments from last year. We have also committed to reduce GHG emissions intensity from our
operations by 30 per cent by 2030 and position us to achieve zero emissions from our operations, on a net basis, by 2050
• 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:
Financial strength and flexibility
• Rely on internally-generated cash flows, existing debt capacity, partnerships and portfolio management to finance new initiatives. Reserve
common equity issuances for transformational opportunities.
Known and acceptable project risks
• 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 our 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.
18 | TC Energy Management's discussion and analysis 2021
2021 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 22 and 82 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)
2021
2020
2019
Income
Revenues
Net income attributable to common shares
per common share – basic
Comparable EBITDA1
Comparable earnings
per common share
Cash flows
Net cash provided by operations
Comparable funds generated from operations
Capital spending2
Proceeds from sales of assets, net of transaction costs
Balance sheet3
Total assets
Long-term debt, including current portion
Junior subordinated notes
Redeemable non-controlling interest4
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
13,387
12,999
13,255
1,815
$1.87
9,382
4,153
$4.27
6,890
7,406
7,134
35
104,218
38,661
8,939
—
3,487
125
29,784
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
$3.48
$3.24
$3.00
973
981
940
940
929
938
1
2
3
4
Additional information on Segmented earnings, the most directly comparable GAAP measure, can be found on page 20.
Includes Capital expenditures, Capital projects in development and Contributions to equity investments. Refer to Note 4, Segmented information, of our 2021
Consolidated financial statements for the financial statement line items that comprise total capital spending.
As at December 31.
At December 31, 2020, redeemable non-controlling interest was classified in mezzanine equity and subsequently repurchased in 2021.
TC Energy Management's discussion and analysis 2021 | 19
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 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
2021
1,449
3,071
557
(1,600)
628
(46)
4,059
(2,360)
267
200
2,166
(120)
2,046
(91)
1,955
(140)
1,815
$1.87
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
$4.74
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
$4.28
Net income attributable to common shares in 2021 was $1.8 billion or $1.87 per share (2020 – $4.5 billion or $4.74 per share;
2019 – $4.0 billion or $4.28 per share), a decrease of $2.6 billion or $2.87 per share compared to the same period in 2020
primarily due to the $2.1 billion after-tax asset impairment of the Keystone XL pipeline project, net of expected contractual
recoveries and other contractual and legal obligations recorded in 2021. The decrease in Net income per common share in 2021
also reflects the impact of common shares issued for the acquisition of the remaining ownership interests in TC PipeLines, LP. The
increase in Net income per common share in 2020 of $0.46 per share compared to 2019 reflected higher net income in 2020 and
the dilutive impact of common shares issued under our DRP in 2019.
The following specific items were recognized in Net income attributable to common shares and were excluded from comparable
earnings:
2021
• a $2.1 billion after-tax asset impairment charge, net of expected contractual recoveries and other contractual and legal
obligations, related to the termination of the Keystone XL pipeline project following the January 20, 2021 revocation of the
Presidential Permit. Refer to the Liquids Pipelines – Significant events section for additional information
• a $48 million after-tax expense with respect to transition payments incurred as part of the Voluntary Retirement Program
(VRP)
• preservation and storage costs for Keystone XL pipeline project assets of $37 million after tax, which could not be accrued as
part of the Keystone XL asset impairment charge, as well as interest expense on the Keystone XL project-level credit facility
prior to its termination
• an after-tax gain of $19 million related to the sale of the remaining interest in Northern Courier
• a $7 million after-tax recovery primarily related to certain costs from the IESO associated with the Ontario natural gas-fired
power plants sold in April 2020.
20 | TC Energy Management's discussion and analysis 2021
The Keystone XL pipeline project asset impairment charge does not reflect offsetting amounts with respect to the Government
of Alberta's investment in Keystone XL nor their repayment of the project's guaranteed credit facility without recourse to
TC Energy, both of which were accounted for within the Consolidated statement of equity in 2021 and served to reduce our net
financial impact from the Keystone XL pipeline project termination. Refer to the Liquids Pipelines – Significant events section for
additional information.
2020
• an after-tax loss of $283 million related to the Ontario natural gas-fired power plants sold in April 2020. The total after-tax loss
on this transaction to the end of 2020 was $477 million including losses accrued in 2019 upon classification of the assets as
held for sale
• 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)
• an income tax valuation allowance release of $299 million following our reassessment of deferred tax assets that were deemed
more likely than not to be realized in 2020
• an additional $18 million income tax recovery related to state income taxes on the sale of certain Columbia Midstream assets.
2019
• an after-tax gain of $115 million related to the sale of an 85 per cent equity interest in Northern Courier
• an after-tax loss of $194 million related to the Ontario natural gas-fired power plant assets held for sale
• an income tax valuation allowance release of $195 million related to certain prior years' U.S. income 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 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 RRA
• an after-tax loss of $6 million related to the sale of the remainder of our U.S. Northeast power marketing contracts.
Refer to the Financial results sections 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 2021 | 21
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):
Keystone XL asset impairment charge and other
Voluntary Retirement Program
Keystone XL preservation and other
Gain on sale of Northern Courier
(Gain)/loss on sale of Ontario natural gas-fired power plants
Gain on partial sale of Coastal GasLink LP
Income tax valuation allowance releases
(Gain)/loss on sale of Columbia Midstream assets
Gain on sale of Coolidge generating station
Alberta corporate income tax rate reduction
U.S. Northeast power marketing contracts
Risk management activities1
Comparable earnings
Net income per common share
Keystone XL asset impairment charge and other
Voluntary Retirement Program
Keystone XL preservation and other
Gain on sale of Northern Courier
(Gain)/loss on sale of Ontario natural gas-fired power plants
Gain on partial sale of Coastal GasLink LP
Income tax valuation allowance releases
(Gain)/loss on sale of Columbia Midstream assets
Gain on sale of Coolidge generating station
Alberta corporate income tax rate reduction
U.S. Northeast power marketing contracts
Risk management activities
Comparable earnings per common share
1
year ended December 31
(millions of $)
U.S. Natural Gas Pipelines
Liquids Pipelines
Canadian Power
U.S. Power
Natural Gas Storage
Foreign exchange
Income taxes attributable to risk management activities
Total unrealized (losses)/gains from risk management activities
22 | TC Energy Management's discussion and analysis 2021
2021
1,815
2,134
48
37
(19)
(7)
—
—
—
—
—
—
145
4,153
$1.87
2.19
0.05
0.04
(0.02)
(0.01)
—
—
—
—
—
—
0.15
$4.27
2020
4,457
—
—
—
—
283
(402)
(299)
(18)
—
—
—
(76)
3,945
$4.74
—
—
—
—
0.30
(0.43)
(0.32)
(0.02)
—
—
—
(0.07)
$4.20
2019
3,976
—
—
—
(115)
194
—
(195)
152
(54)
(32)
6
(81)
3,851
$4.28
—
—
—
(0.12)
0.21
—
(0.21)
0.16
(0.06)
(0.03)
0.01
(0.10)
$4.14
2021
2020
2019
6
(3)
12
—
(6)
(203)
49
(145)
—
(9)
(2)
—
(13)
126
(26)
76
—
(72)
—
(52)
(11)
245
(29)
81
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
Financial results sections for each business segment.
year ended December 31
(millions of $, except per share amounts)
2021
2020
2019
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 included in comparable earnings
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
2,675
3,856
666
1,526
683
(24)
9,382
(2,522)
(2,354)
267
444
(833)
(91)
(140)
4,153
$4.27
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
Comparable EBITDA – 2021 versus 2020
Comparable EBITDA in 2021 increased by $31 million compared to 2020 primarily due to the net result of the following:
• increased earnings in U.S. Natural Gas Pipelines from higher Columbia Gas transportation rates effective February 1, 2021 as a
result of the subsequently uncontested rate case settlement, improved earnings across our U.S. Natural Gas Pipelines assets
following the cold weather events of 2021 impacting many of the U.S. markets in which we operate, increased earnings from
our mineral rights business and increased capitalization of pipeline integrity costs, partially offset by higher property taxes
• higher comparable EBITDA from Canadian Natural Gas Pipelines largely as a result of the impact of increased flow-through
depreciation and income taxes along with higher rate-base earnings on the NGTL System, full-year recognition of Coastal
GasLink development fee revenue and higher Canadian Mainline incentive earnings and flow-through income taxes, partially
offset by lower flow-through depreciation and financial charges
• consistent Power and Storage results mainly attributable to increased Canadian Power earnings primarily due to higher
realized margins in 2021, contributions from trading activities and a full of year of earnings from our MacKay River
cogeneration facility following its return to service in May 2020, partially offset by the sale of our Ontario natural gas-fired
power plants in April 2020 and decreased earnings at Bruce Power in 2021 due to lower volumes resulting from greater
planned outage days and higher operating expenses
• decreased earnings from Liquids Pipelines attributable to lower volumes on the U.S. Gulf Coast section of the Keystone Pipeline
System, partially offset by increased contributions from liquids marketing activities reflecting higher margins and volumes
• lower contribution from Mexico Natural Gas Pipelines mainly due to US$55 million of fees recognized in 2020 associated with
the successful completion of the Sur de Texas pipeline
• foreign exchange impact of a weaker U.S. dollar on the Canadian dollar equivalent segmented earnings in our
U.S. dollar-denominated operations. As detailed on page 25, U.S. dollar-denominated comparable EBITDA of US$4.6 billion
increased by US$226 million compared to 2020; however, this was translated at 1.25 in 2021 versus 1.34 in 2020. Refer to the
Foreign exchange discussion below for additional information.
TC Energy Management's discussion and analysis 2021 | 23
While the weakening of the U.S. dollar in 2021 compared to 2020 had a considerable negative impact on 2021 comparable
EBITDA, the corresponding impact on comparable earnings was not significant due to offsetting natural and economic hedges.
Refer to the Foreign exchange discussion below for additional information.
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 in January 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 in April 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
• 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 2020
related to fees associated with our successful completion of the Sur de Texas pipeline
• 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 segmented earnings in our
U.S. dollar-denominated operations. As detailed on page 25, U.S. dollar-denominated comparable EBITDA of US$4.3 billion
decreased by US$174 million compared to 2019; however, this was translated at 1.34 in 2020 versus 1.33 in 2019. Refer to the
Foreign exchange discussion below for additional information.
Due to the flow-through treatment of certain expenses, including income taxes, financial charges and depreciation in our
Canadian rate-regulated pipelines, changes in these expenses impact our comparable EBITDA despite having no significant effect
on net income.
Comparable earnings – 2021 versus 2020
Comparable earnings in 2021 were $208 million or $0.07 per common share higher than in 2020, and were primarily the net
result of:
• changes in comparable EBITDA described above
• higher Interest income and other mainly attributable to realized gains in 2021 compared to realized losses in 2020 on
derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income
• decreased Non-controlling interests following the March 3, 2021 acquisition of all outstanding common units of
TC PipeLines, LP not beneficially owned by TC Energy
• lower Depreciation and amortization on our U.S. dollar-denominated assets primarily as a result of the weaker U.S. dollar and
in Canadian Natural Gas Pipelines due to one section of the Canadian Mainline being fully depreciated in 2021
• higher Income tax expense mainly due to increased pre-tax earnings and higher flow-through income taxes on our Canadian
rate-regulated pipelines
• higher Interest expense primarily due to lower capitalized interest as a result of its cessation for the Keystone XL pipeline
project following the revocation of the Presidential Permit on January 20, 2021, the change to equity accounting for our
Coastal GasLink investment upon the sale of a 65 per cent interest in Coastal GasLink LP and the completion of the Napanee
power plant in 2020, partially offset by the foreign exchange impact from a weaker U.S. dollar on translation of
U.S. dollar-denominated interest
• lower AFUDC, predominantly due to the suspension of recording AFUDC on the Villa de Reyes project effective January 1, 2021
as a result of ongoing project delays, partially offset by the NGTL System and U.S. natural gas pipeline expansion projects.
24 | TC Energy Management's discussion and analysis 2021
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 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 expansion projects 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 and amortization largely in Canadian Natural Gas Pipelines and U.S. Natural Gas Pipelines reflecting new
assets placed in service. In Canadian Natural Gas Pipelines, as it is fully recovered in tolls on a flow-through basis, it has no
significant impact on comparable earnings.
Comparable earnings per share reflects the impact of common shares issued for the acquisition of the remaining ownership
interests in TC PipeLines, LP on March 3, 2021 and under our DRP in 2019. Refer to the Financial condition section for further
information on common share issuances.
Foreign exchange
Certain of our businesses generate all or most of their earnings in U.S. dollars and, since we report our financial results in
Canadian dollars, changes in the value of the U.S. dollar against the Canadian dollar directly affect our comparable EBITDA and
may also impact comparable earnings. As our U.S. dollar-denominated operations continue to grow, this exposure increases.
A portion of the U.S. dollar-denominated comparable EBITDA exposure is naturally offset by U.S. dollar-denominated amounts
below comparable EBITDA within Depreciation and amortization, Interest expense and other income statement line items. The
balance of the exposure is actively managed on a rolling forward basis up to three years using foreign exchange derivatives;
however, the natural exposure beyond that period remains. Despite the significant change in the average exchange rate in 2021
compared to 2020, the net impact of U.S. dollar movements on comparable earnings over this period, after considering natural
offsets and economic hedges, was not significant.
The components of our financial results denominated in U.S. dollars are set out in the table below, including our U.S. and Mexico
Natural Gas Pipelines operations along with the majority of our Liquids Pipelines business. Comparable EBITDA is a non-GAAP
measure.
Pre-tax U.S. dollar-denominated income and expense items
year ended December 31
(millions of US$)
Comparable EBITDA
U.S. Natural Gas Pipelines
Mexico Natural Gas Pipelines1
U.S. Liquids Pipelines
Depreciation and amortization
Interest on long-term debt and junior subordinated notes
Capitalized interest on capital expenditures
Allowance for funds used during construction
Non-controlling interests and other
Average exchange rate – U.S. to Canadian dollars
2021
2020
2019
3,075
602
884
4,561
(911)
(1,259)
10
101
(76)
2,426
1.25
2,714
666
955
4,335
(877)
(1,302)
131
182
(248)
2,221
1.34
2,623
568
1,318
4,509
(847)
(1,326)
34
205
(233)
2,342
1.33
1
Excludes interest expense on our inter-affiliate loan with Sur de Texas which is fully offset in Interest income and other.
TC Energy Management's discussion and analysis 2021 | 25
Cash flows
Net cash provided by operations of $6.9 billion in 2021 was two per cent lower than 2020 due to lower funds generated from
operations, partially offset by the amount and timing of working capital changes. Comparable funds generated from operations
of $7.4 billion in 2021 was consistent with 2020 and reflected higher comparable earnings, partially offset by fees collected in
2020 associated with the construction of the Sur de Texas pipeline, as well as 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
2021
2,737
2,820
129
571
842
35
7,134
2020
3,608
2,785
173
1,442
834
58
8,900
2019
3,906
2,516
357
954
1,019
32
8,784
1
Capital spending includes Capital expenditures, Capital projects in development and Contributions to equity investments. Refer to Note 4, Segmented
information, of our 2021 Consolidated financial statements for the financial statement line items that comprise total capital spending.
In 2021 and 2020, we invested $7.1 billion and $8.9 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 2021 and
2020 included contributions of $1.2 billion and $0.8 billion, respectively, to our equity investments, predominantly related to
Bruce Power and Iroquois.
Proceeds from sales of assets
In 2021, we completed the sale of our remaining 15 per cent equity interest in Northern Courier for gross proceeds of $35 million.
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 $1.5 billion from the initial draw by Coastal
GasLink LP on the project-level credit facility which preceded the equity sale.
Balance sheet
We continue to maintain a solid financial position while growing our total assets by $3.9 billion in 2021. At December 31, 2021,
common shareholders' equity, including non-controlling interests, represented 35 per cent (2020 – 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 15 per cent (2020 – 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 3.4 per cent to $0.90 per common share for the
quarter ending March 31, 2022 which equates to an annual dividend of $3.60 per common share. This was the 22
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 three to five per cent.
nd
consecutive
26 | TC Energy Management's discussion and analysis 2021
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. Commencing with the dividends declared October 31, 2019,
common shares purchased under TC Energy’s DRP are acquired on the open market at 100 per cent of the weighted average
purchase price. From January 1, 2019 to October 31, 2019, common shares were issued from treasury at a discount of two per
cent to market prices over a specified period.
Cash dividends paid
year ended December 31
(millions of $)
Common shares
Preferred shares
OUTLOOK
2021
3,317
141
2020
2,987
159
2019
1,798
160
Comparable EBITDA and comparable earnings
We expect our 2022 comparable EBITDA to be modestly higher than 2021; however, our 2022 comparable earnings per common
share are expected to be consistent with 2021 largely due to the impact of a lower average foreign exchange hedge rate on our
2022 U.S. dollar-denominated earnings, as well as the following:
• growth in the NGTL System
• contributions from the Villa de Reyes pipeline expected to be placed in service
• higher AFUDC related to our Mexico natural gas pipeline projects subject to a successful resolution of the current contract
dispute
• full-year impact from assets placed in service in 2021 and new projects anticipated to be placed in service in 2022, net of
incremental depreciation expense
• lower contributions from the Keystone Pipeline System and reduced margins in the liquids marketing business
• higher Interest expense as a result of long-term debt issuances, net of maturities.
We continue to monitor developments in energy markets, our construction projects and regulatory proceedings as well as
COVID-19 for any potential impacts on the above outlook.
Consolidated capital spending and equity investments
We expect to spend approximately $6.5 billion in 2022 on growth projects, maintenance capital expenditures and contributions
to equity investments. The majority of the 2022 capital program is focused on NGTL System expansions, U.S. natural gas pipeline
projects, the Bruce Power life extension program and normal course maintenance capital expenditures. We recognize that
continued uncertainty exists on the duration of COVID-19 and the impact it could have on our construction activities and capital
expenditures; however, we do not believe such disruptions will be material to our overall 2022 capital program.
Refer to the relevant business segment and Financial condition outlook sections for additional details on expected earnings and
capital spending for 2022.
TC Energy Management's discussion and analysis 2021 | 27
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. In addition, many of these projects advance our goals to reduce our own carbon
footprint as well as that of our customers.
Our capital program consists of approximately $24 billion of secured projects which represent commercially supported,
committed projects that are either under construction or are in or preparing to commence the permitting stage.
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.
During the year ended December 31, 2021, we placed approximately $2.3 billion of Canadian and U.S. natural gas pipelines
capacity capital projects into service. In addition, approximately $1.8 billion of maintenance capital expenditures were incurred.
All projects are subject to cost and timing adjustments due to factors including weather, market conditions, route refinement,
permitting conditions, scheduling and timing of regulatory permits, as well as other potential restrictions and uncertainties,
including the ongoing impact of COVID-19. Amounts exclude capitalized interest and AFUDC, where applicable.
28 | TC Energy Management's discussion and analysis 2021
Secured projects
Estimated and incurred project costs referred to in the following table include 100 per cent of the capital expenditures related to
our wholly-owned projects and our ownership share of equity contributions to fund projects within our equity investments,
primarily Coastal GasLink and Bruce Power.
(billions of $)
Expected in-service date
Estimated project cost1
Project costs incurred
as at December 31, 2021
Canadian Natural Gas Pipelines
NGTL System2
Canadian Mainline
Coastal GasLink3
Regulated maintenance capital expenditures
U.S. Natural Gas Pipelines
Modernization III (Columbia Gas)4
Delivery market projects
Other capacity capital
Regulated maintenance capital expenditures
Mexico Natural Gas Pipelines
Villa de Reyes
Tula5
Liquids Pipelines
Other capacity capital
Recoverable maintenance capital expenditures
Power and Storage
Bruce Power – life extension6
Other
2022
2023
2024+
2022
2023
2022-2024
2022-2024
2025
2022-2025
2022-2024
2022
—
2022-2023
2022-2024
2022-2027
Non-recoverable maintenance capital expenditures7
2022-2024
Foreign exchange impact on secured projects8
Total secured projects (Cdn$)
3.3
1.8
0.5
0.2
0.2
2.1
US 1.2
US 1.5
US 1.5
US 2.0
US 1.0
US 0.8
US 0.2
0.1
4.4
0.6
21.4
2.2
23.6
1.8
0.2
—
0.1
0.2
—
US 0.2
—
US 0.9
—
US 0.9
US 0.6
US 0.1
—
1.9
—
6.9
0.7
7.6
1
2
3
4
5
6
7
8
Amounts reflect 100 per cent of costs related to wholly-owned assets as well as cash contributions to our joint-venture investments.
Estimated project costs for 2022 and 2023 include a total of $0.6 billion for Foothills related to the West Path Expansion Program.
The estimated project cost represents our share of anticipated 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 on the status
of Coastal GasLink's dispute with LNG Canada regarding the recognition of certain costs and schedule changes. Refer to Note 11, Loans receivable from affiliates,
of our 2021 Consolidated financial statements for information regarding our commitment to provide additional temporary financing, if necessary, to Coastal
GasLink under certain circumstances.
Subject to FERC approval of the Columbia Gas uncontested rate case settlement. Refer to the U.S. Natural Gas Pipelines – Significant events section for
additional information.
The East Section of the Tula pipeline is available for interruptible transportation services. We are working to procure necessary land access on the west section
of the Tula pipeline to finalize its construction. The central segment construction has been delayed due to pending Indigenous consultation processes under the
responsibility of the Secretary of Energy. Refer to the Mexico Pipelines – Significant events section for additional information.
Reflects our expected share of cash contributions for the Bruce Power Unit 6 Major Component Replacement (MCR) program, expected to be in service in 2023,
amounts to be invested under the Asset Management program through 2027 as well as the incremental uprate initiative. In addition, it includes our expected
share of cash contributions for the Unit 3 MCR, subject to IESO approval of the basis of estimate. Refer to the Power and Storage – Significant events section for
additional information.
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 1.27 at December 31, 2021.
TC Energy Management's discussion and analysis 2021 | 29
Projects under development
In addition to our secured projects, we have a portfolio of projects that we are currently pursuing which are in varying stages of
development. Projects under development have greater uncertainty with respect to timing and estimated project costs and are
subject to corporate and regulatory approvals, unless otherwise noted. Each business segment has also outlined additional areas
of focus for further ongoing business development activities and growth opportunities. As these projects are advanced, reaching
necessary milestones, they will be included in the secured projects table.
Canadian Natural Gas Pipelines
We continue to focus on optimizing the utilization and value of our existing Canadian Natural Gas Pipelines assets, including
in-corridor expansions, providing connectivity to LNG export terminals and connections to growing shale gas supplies.
Sustainability development projects will include additional compressor station electrification and waste heat capture power
generation on our systems as well as other GHG abatement initiatives.
U.S. Natural Gas Pipelines
Delivery Market Projects
Projects are in development that will replace, upgrade and modernize certain U.S. Natural Gas Pipelines facilities while reducing
emissions along portions of our pipeline systems’ principal delivery markets. The enhanced facilities are expected to improve
reliability of our systems and allow for additional contracted transportation services to address growing demand in the
U.S. Midwest and the Mid-Atlantic regions under long-term contracts while reducing direct carbon dioxide equivalent (CO2e)
emissions. Included in our secured projects are the US$0.7 billion VR Project on Columbia Gas and the US$0.8 billion WR Project
on ANR, two delivery market projects that were approved in 2021 with expected in-service dates in the second half of 2025.
Other Opportunities
We are currently pursuing a variety of projects including compression replacement while furthering the electrification of our
fleet, increasing capacity to LNG, power generation and LDCs, expanding our modernization programs and in-corridor expansion
opportunities on our existing system. These projects are expected to improve the reliability of our system with an environmental
focus on cleaner energy.
Refer to the U.S. Natural Gas Pipelines – Significant events section for additional information.
Mexico Natural Gas Pipelines
We are currently evaluating new growth projects driven by Mexico’s economic expansion and the need to connect natural gas to
new regions of the country to serve power plants, industrial demand and LNG exports and, in doing so, reduce reliance on costly,
carbon intensive fuel oil. Potential projects include a re-route of the central segment of Tula as well as a new offshore pipeline
that would connect additional natural gas supply to Southeast Mexico and capacity expansions on existing assets.
Liquids Pipelines
Grand Rapids Phase II
Regulatory approvals have been obtained for Phase II of Grand Rapids which consists of completing the 36-inch pipeline for
crude oil service and converting the 20-inch pipeline from crude oil to diluent service. Commercial support is being pursued with
prospective customers.
Terminals Projects
We continue to pursue projects associated with our terminals in Alberta and the U.S. to expand our core business and add
operational flexibility for our customers.
Other Opportunities
We remain focused on maximizing the value of our liquids assets by expanding and leveraging our existing infrastructure and
enhancing connectivity and service offerings to our customers. We are pursuing selective growth opportunities to add
incremental value to our Liquids Pipelines business and expansions that leverage available capacity on our existing infrastructure.
We remain disciplined in our approach and will position our business development activities strategically to capture
opportunities within our risk preferences.
30 | TC Energy Management's discussion and analysis 2021
Power and Storage
Bruce Power
Life Extension Program
The continuation of Bruce Power’s life extension program through to 2033 will require the investment of our proportionate share
of Major Component Replacement (MCR) program costs on Units 3, 4, 5, 7 and 8, as well as the remaining Asset Management
program costs which continue beyond 2033. This program will extend the life of Units 3 to 8 and the Bruce Power site to 2064.
The basis of estimate for the Unit 3 MCR was submitted to the IESO in December 2021 for a refurbishment outage expected to
begin in first quarter 2023. Preparation work for the Unit 4 MCR is well underway and work for Unit 5, 7 and 8 MCRs have also
begun. Future MCR investments will be subject to discrete decisions for each unit with specified off-ramps available to
Bruce Power and the IESO. We expect to spend approximately $4.8 billion for our proportionate share of the Bruce Power MCR
program costs for Units 4, 5, 7 and 8, the remaining Asset Management program costs beyond 2027, as well as the incremental
uprate initiative discussed below.
Uprate Initiative
Bruce Power recently launched Project 2030 with the goal of achieving a site peak output of 7,000 MW by 2033 in support of
climate change targets and future clean energy needs. Project 2030 will focus on continued asset optimization, innovation and
leveraging new technology, which could include integration with storage and other forms of energy, to increase the site peak
output at Bruce Power. Project 2030 is arranged in three stages with the first two stages fully approved for execution. Stage 1
started in 2019 and is expected to add 150 MW of output and Stage 2, beginning in early 2022, is targeting another 200 MW.
Both stages are expected to increase output in multiple steps ending in 2033. Stage 3 requires Stage 1 and 2 to be complete and
would enable an increase to the reactor power limit.
Development-Stage Projects
Ontario Pumped Storage
We continue to progress the development of the Ontario Pumped Storage project, an energy storage facility located near
Meaford, Ontario that would provide 1,000 MW of flexible, clean energy to Ontario’s electricity system using a process known as
pumped hydro storage.
Two key milestones on the Ontario Pumped Storage project were reached in 2021. On July 28, 2021, the Federal Minister of
National Defence granted long-term land access to the fourth Canadian Division Training Centre for development of the project
on this site. On November 11, 2021, Ontario’s Minister of Energy instructed the IESO to progress the project to Gate 2 of the
Unsolicited Proposals Process. Once in service, this project will store emission-free energy when available and provide that
energy to Ontario during periods of peak demand, thereby maximizing the value of existing emissions-free generation in the
province.
Saddlebrook Solar and Storage
We are proposing to construct and operate the Saddlebrook Solar and Storage project, a solar and energy storage solution, which
consists of a solar-generating facility located in Aldersyde, Alberta that will operate in conjunction with a battery energy storage
system.
The proposed generating facility will produce approximately 81 MW of power and the battery storage system will provide up to
40 MWh of energy storage capacity and is expected to reduce GHG emissions by approximately 115,000 tonnes per year. The
proposed project is partially funded through Emissions Reduction Alberta’s Biotechnology, Electricity and Sustainable
Transportation Challenge. We expect to make a final investment decision on the project in 2022 with the first phases of
commissioning beginning towards the end of 2022.
Canyon Creek Pumped Storage
We acquired 100 per cent ownership of the Canyon Creek pumped storage development project in 2021. Once in service, the
facility will have initial generating capacity of 75 MW, expandable through future development to 400 MW, and will utilize
existing site infrastructure from a decommissioned coal mine. The facility will provide up to 37 hours of on-demand, flexible,
clean energy and ancillary services to the Alberta electricity grid. The project has received the approval of the Alberta Utilities
Commission and the required approval of the Alberta Government for hydro projects under the Hydro Development Act.
TC Energy Management's discussion and analysis 2021 | 31
The Canyon Creek Pumped Storage project is part of a larger product offering by us, a 24-by-7 carbon-free power product in the
Province of Alberta and includes output from other projects currently under construction or being developed, thereby
positioning our customers to manage hourly power needs with cost certainty and achieve decarbonization goals by sourcing
power from emissions-free assets.
Renewable Energy Request for Information (RFI)
In 2021, we announced that we were seeking to identify potential contracts and/or investment opportunities in wind, solar and
power storage renewable energy projects. We requested up to 620 MW of wind energy projects, 300 MW of solar projects and
100 MW of energy storage projects to meet the electricity needs of the U.S. portion of the Keystone Pipeline System assets. We
also identified meaningful origination opportunities to supply renewable energy products and services to industrial and oil and
gas sectors proximate to our in-corridor demand. We received a significant number of responses to our RFI and are currently
evaluating proposals and expect to finalize contracts during the first half of 2022.
Other Opportunities
We are actively building our customer-focused origination platform across North America, providing commodity products and
energy services to help customers address the challenges of energy transition. Our existing network of assets, customers and
suppliers provide a mutual opportunity in which we can tailor solutions to meet their clean energy needs. Although we may
adopt a custom-tailored strategy for each of our partnerships, the core underpinning remains consistent, which is that every
opportunity we undertake will ultimately be driven by customer needs allowing us to complement each other’s capabilities,
diversify risk and share learnings as we navigate the energy transition.
Refer to the Power and Storage – Significant events section for additional information.
Other Energy Transition Developments
Our vision is to be the premier energy infrastructure company in North America today and in the future. That future includes
embracing the energy transition that is underway and contributing to a lower-carbon energy world. As energy transition
continues to evolve, we recognize a significant opportunity to reduce our emissions footprint, in addition to being a partner to
our customers and other industries which are also looking for low-carbon solutions. Currently, it is uncertain how the energy mix
will evolve and at what pace. We continue to observe a reliance on the existing sources of natural gas, crude oil and electricity,
for which we currently provide services to our customers.
We are targeting five focus areas to reduce the emissions intensity of our operations, while also capturing growth
opportunities that meet the energy needs of the future:
• modernize our existing system and assets
• decarbonize our energy consumption
• drive digital solutions and technologies
• leverage carbon credits and offsets
• invest in low-carbon energy and infrastructure, such as renewables along with emerging fuels and technology.
Alberta Carbon Grid (ACG)
On June 17, 2021, we announced a partnership with Pembina Pipeline Corporation to jointly develop a world-scale carbon
transportation and sequestration system which, when fully constructed, will be capable of transporting more than 20 million
tonnes of carbon dioxide annually, thereby providing opportunities to retrofit existing assets and reduce our carbon footprint. By
leveraging existing pipelines and a newly developed sequestration hub, the ACG is expected to provide an infrastructure
platform for Alberta-based industries to manage their emissions and contribute to a lower-carbon economy. Designed to be an
open-access system, the ACG would connect the Fort McMurray, Alberta Industrial Heartland and Drayton Valley regions to key
sequestration locations and delivery points across the province. We are also pursuing opportunities to leverage our existing
systems in support of hydrogen production and transportation.
32 | TC Energy Management's discussion and analysis 2021
Irving Oil Decarbonization
On August 12, 2021, we signed an MOU to explore the joint development of a series of proposed energy projects focused on
reducing GHG emissions and creating new economic opportunities in New Brunswick and Atlantic Canada. Together with
Irving Oil, we have identified a series of potential projects focused on decarbonizing existing assets and deploying emerging
technologies to reduce overall emissions over the medium and long term. The partnership’s initial focus will consider a suite of
upgrade projects at Irving Oil’s refinery in Saint John, New Brunswick, with the goal of significantly reducing emissions through
the production and use of low-carbon power generation.
Hydrogen Hubs
We have entered into two Joint Development Agreements (JDA), to support customer-driven hydrogen production for
long-haul transportation, power generation, large industrials and heating customers across the United States and Canada. The
first opportunity is a partnership with Nikola Corporation, a designer and manufacturer of zero-emission battery-electric and
hydrogen-electric vehicles and related equipment, where Nikola will be a long-term anchor customer for hydrogen production
infrastructure supporting hydrogen fueled zero-emission heavy-duty trucks. The JDA with Nikola supports co-development of
large-scale green and blue hydrogen production hubs, utilizing our power and natural gas infrastructure.
Our second customer-driven opportunity is a partnership with Hyzon Motors, a leader in fuel cell electric mobility for commercial
vehicles, to develop hydrogen production facilities focused on zero-to-negative carbon intensity hydrogen from renewable
natural gas, biogas and other sustainable sources. The facilities will be located close to demand, supporting Hyzon’s
back-to-base vehicle deployments. Our significant pipeline, storage and power assets can potentially be leveraged to lower the
cost and increase the speed of development of these hubs. This may include exploring the integration of pipeline assets to
enable hydrogen distribution and storage via pipeline and/or to deliver carbon dioxide to permanent sequestration sites to
decarbonize the hydrogen production process.
TC Energy Management's discussion and analysis 2021 | 33
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 – 88,110 km (54,748 miles)
• partially-owned natural gas pipelines – 5,184 km (3,221 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
Optimize the value of our existing natural gas pipeline systems in a safe and reliable manner, while responding to the changing
flow patterns of natural gas in North America. 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 significant 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, in Canada, the U.S. and Mexico
• connections to growing Canadian and U.S. shale gas and other supplies
• decarbonizing our energy consumption, thereby reducing overall GHG intensity.
Each of these areas plays a critical role in meeting the transportation requirements for supply of and demand for natural gas in
North America.
Our natural gas pipeline systems are enabling energy transition. Natural gas is a reliable, high-efficiency energy source that is
displacing coal-fired power while backstopping the intermittency of renewable power sources across North America. In support
of our GHG intensity reduction targets, we continue to improve operational efficiencies and factor sustainability into our
decision making around new projects, modernization, maintenance, electrification and enhanced leak detection. Further, a
growing number of renewable natural gas customers are connecting to our system. Our business provides socioeconomic
benefits as we work closely with Indigenous communities, community-based organizations, landowners and other stakeholders
in alignment with our values and sustainability commitments.
Recent highlights
Canadian Natural Gas Pipelines
• approximately $1.2 billion of projects placed into service in 2021
• received federal approval for the 2022 NGTL System Expansion Program with in-service dates anticipated in 2022
• CER approved the 2023 NGTL System Intra-Basin Expansion Program
• advanced construction of the Coastal GasLink pipeline project.
34 | TC Energy Management's discussion and analysis 2021
U.S. Natural Gas Pipelines
• placed approximately US$2.4 billion of capital projects into service including BXP on Columbia Gas and Grand Chenier XPress
on ANR
• originated an additional US$2.9 billion of growth projects including the GHG emissions-reducing Delivery Market projects on
Columbia Gas and ANR, as well as the Columbia Gas Modernization III program
• Columbia Gas uncontested rate settlement filed with FERC and GTN rate settlement approved by FERC
• ANR filed a Section 4 rate case with FERC on January 28, 2022 requesting an increase to maximum transportation rates
effective August 1, 2022, subject to refund. As the rate process progresses, we expect to engage in a collaborative process to
achieve settlement with our customers, FERC and other stakeholders
• achieved record throughput volumes on certain pipelines.
Mexico Natural Gas Pipelines
• advanced resolution of the arbitration with the CFE on the Tula and Villa de Reyes pipeline projects with the signing of an MOU
on July 30, 2021
• commenced feasibility assessments with the CFE under the MOU to jointly evaluate potential alternatives to complete the Tula
pipeline and a new offshore pipeline to connect natural gas to southeast Mexico
• continued construction of the Villa de Reyes pipeline project with phased commissioning and in-service expected in 2022
subject to timely receipt of pending authorizations and land access to critical pipeline sections
• assets performed with 100 per cent reliability and asset utilization continued to increase.
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 38 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 are well positioned to connect growing supply in northeast
British Columbia and northwest Alberta. Our 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/British Columbia
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.
TC Energy Management's discussion and analysis 2021 | 35
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.
Other U.S. Natural Gas Pipelines: We have ownership interests in eight wholly-owned or partially-owned natural gas pipelines
serving major markets in the U.S. that were previously held by our subsidiary, TC PipeLines, LP. On March 3, 2021, we completed
the acquisition of all of the outstanding common units of TC PipeLines, LP not beneficially owned by TC Energy, in exchange for
TC Energy common shares, resulting in TC PipeLines, LP becoming an indirect, wholly-owned subsidiary of TC Energy, thereby
increasing our effective ownership in the TC PipeLines, LP assets. Refer to the Corporate – Significant events section for
additional information.
Mexico Natural Gas Pipelines
Sur de Texas: This offshore pipeline transports natural gas from Texas to power and industrial markets in the eastern and central
regions of Mexico. The average volumes transported by this pipeline in 2021 supplied approximately 15 per cent of Mexico's total
natural gas imports via pipelines. 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.
TGNH System: This system is located in the central region of Mexico and is comprised of the existing 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
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 growing access to international markets via LNG exports. We expect North American
natural gas demand, including LNG exports, of approximately 121 Bcf/d by 2026, reflecting an increase of approximately 18 Bcf/d
from 2021 levels.
36 | TC Energy Management's discussion and analysis 2021
As the world shifts toward lower-emission fuel sources, further retirements of coal-fired power generation and export demand
growth over the next five to 10 years will offer growth opportunities for base-load power from natural gas-fired generation. This
expected growth in demand for natural gas, coupled with the anticipated production increases in key producing areas like WCSB,
onshore Gulf Coast, Appalachia and the Permian basin, will provide investment opportunities for pipeline infrastructure
companies to build new facilities or increase utilization of the existing footprint. Modernizing and decarbonizing our natural gas
pipeline systems will provide ongoing additional capital investment opportunities that will meet our risk preferences while
supporting our GHG intensity reduction goals.
Changing demand
The abundant supply of natural gas has supported increased demand, particularly in the following areas:
• natural gas-fired power generation
• petrochemical and industrial facilities
• Alberta oil sands.
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 increasing supply of natural gas in Mexico is driven by the CFE’s need to serve
existing markets by connecting natural gas plants to supply and building pipelines to serve new regions. They are forecasting
significant gas demand growth in the future to support economic expansion and conversion to lower carbon fuels for industrial
and power generation use. The demand created by the addition of these new markets provides additional opportunities for us to
build new pipeline infrastructure and to increase throughput on our existing pipelines. The growing focus on ESG is expected to
result in shifting market dynamics, as both energy demand and pressure for accelerated climate action increase simultaneously.
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 transportation tolls 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.
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
changing natural gas flow dynamics and supporting our corporate-level sustainability goals and ESG targets, including GHG
intensity reduction.
In 2022, 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 into service on time and on budget while ensuring the safety of our people, of the environment and
general public impacted by the construction and operation of these facilities.
Our natural gas marketing entities will complement our 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 2021 | 37
38 | TC Energy Management's discussion and analysis 2021
We are the operator of all of the following natural gas pipelines and regulated natural gas storage assets except for Iroquois.
Length
Description
Ownership
Canadian pipelines
1
NGTL System
2
Canadian Mainline
3
Foothills
4
Trans Québec & Maritimes (TQM)
5
Ventures LP
Great Lakes Canada1
U.S. pipelines and gas storage assets
6
Columbia Gas
24,494 km
(15,220 miles)
14,082 km
(8,750 miles)
Receives, transports and delivers natural gas within Alberta
and British Columbia, and connects with Canadian Mainline,
Foothills and third-party pipelines.
Transports natural gas from the Alberta/Saskatchewan
border and the Ontario/U.S. border to serve eastern Canada
and interconnects to the U.S.
1,237 km
(769 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 Portland.
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.
100%
100%
100%
50%
100%
100%
100%
100%
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.
100%
7a ANR Storage
250 Bcf
8
Columbia Gulf
9 Great Lakes
10 Northern Border
11 Gas Transmission Northwest (GTN)
12 Iroquois
13 Tuscarora
14 Bison
15 Portland
5,419 km
(3,367 miles)
3,404 km
(2,115 miles)
2,272 km
(1,412 miles)
2,216 km
(1,377 miles)
669 km
(416 miles)
491 km
(305 miles)
488 km
(303 miles)
475 km
(295 miles)
Provides regulated underground natural gas storage service
from several facilities (not all shown) to customers in key
mid-western markets.
Transports natural gas to various markets and pipeline
interconnects in the southern U.S. and U.S. Gulf Coast.
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.
Transports WCSB, Bakken and Rockies natural gas from
connections with Foothills and Bison to U.S. Midwest
markets.
Transports WCSB and Rockies natural gas to Washington,
Oregon and California. Connects with Tuscarora and
Foothills.
Connects with the Canadian Mainline and serves markets in
New York.
Transports natural gas from GTN at Malin, Oregon to
markets in northeastern California and northwestern
Nevada.
Transports natural gas from the Powder River basin in
Wyoming to Northern Border in North Dakota.
Connects with TQM near East Hereford, Québec to deliver
natural gas to customers in the U.S. Northeast and Canadian
Maritimes.
100%
100%
50%
100%
50%
100%
100%
61.7%
TC Energy Management's discussion and analysis 2021 | 39
16 Millennium
17 Crossroads
18 North Baja
Mexico pipelines
19 Sur de Texas
20 Topolobampo
21 Mazatlán
22 Tamazunchale
23 Guadalajara
24 Tula – East Section
Under construction
Canadian pipelines
25 Coastal GasLink
NGTL System 2022 Facilities1,2
Length
Description
424 km
(263 miles)
325 km
(202 miles)
138 km
(86 miles)
770 km
(478 miles)
572 km
(355 miles)
430 km
(267 miles)
370 km
(230 miles)
313 km
(194 miles)
48 km
(30 miles)
670 km
(416 miles)
415 km
(258 miles)
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.
Interstate natural gas pipeline operating in Indiana and Ohio
with multiple interconnects to other pipelines.
Transports natural gas between Arizona and California and
connects with a third-party pipeline on the California/Mexico
border.
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 to El Oro and Topolobampo, Sinaloa,
from interconnects with third-party pipelines in El Encino,
Chihuahua and El Oro.
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.
A greenfield project to deliver natural gas from the Montney
gas producing region to LNG Canada's liquefaction facility
under construction near Kitimat, British Columbia
Multiple components of the 2021 NGTL System Expansion
Program, 2022 NGTL System Expansion Program and 2023
NGTL System/Foothills West Path Delivery Program, along
with other facilities, with expected in-service dates in 2022.
Ownership
47.5%
100%
100%
60%
100%
100%
100%
100%
100%
35%
100%
40 | TC Energy Management's discussion and analysis 2021
Under construction (continued)
Length
Description
Ownership
U.S. pipelines
Elwood Power/ANR Horsepower
Replacement3
Wisconsin Access3
Alberta XPress3
Mexico pipelines
26
Villa de Reyes
27
Tula (excluding the East Section)
Permitting and pre-construction phase
NGTL System 2023/2024 Facilities1,2
U.S. pipelines
VR Project3
WR Project3
n/a
n/a
n/a
420 km
(261 miles)
276 km
(171 miles)
199 km
(124 miles)
n/a
n/a
A reliability project on ANR that will replace and upgrade
certain facilities with expected in-service in 2022.
A reliability project on ANR that will replace and upgrade
certain facilities with expected in-service in 2022.
An expansion project of ANR through compressor station
modifications and additions with expected in-service
commencing in 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.
Multiple components of the 2022 NGTL System Expansion
Program, 2023 NGTL System/Foothills West Path Delivery
Program and 2023 NGTL System Intra-Basin Expansion,
along with other facilities, with expected in-service dates
commencing in 2023.
A delivery market project on Columbia Gas that will replace
and upgrade certain facilities while improving reliability and
reducing emissions with expected in-service in 2025.
A delivery market project on ANR that will replace and
upgrade certain facilities while improving reliability and
reducing emissions with expected in-service in 2025.
100%
100%
100%
100%
100%
100%
100%
100%
1
2
3
Facilities and some pipelines are not shown on the map.
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 2021 | 41
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 which includes an incentive
mechanism for certain operating costs and the opportunity to increase depreciation rates if tolls fall below specified levels.
Beginning January 1, 2021, the Canadian Mainline is operating under the 2021-2026 Mainline settlement which includes an
incentive to decrease costs and increase revenues.
SIGNIFICANT EVENTS
Coastal GasLink Pipeline Project
Coastal GasLink is a pipeline under construction that will have an initial capacity of approximately 2.2 PJ/d (2.1 Bcf/d) and will
deliver natural gas from the Dawson Creek area to a natural gas liquefaction facility near Kitimat, British Columbia. The
LNG facility, which is owned by LNG Canada, is currently under construction. Transportation service on the pipeline is
underpinned by 25-year TSAs (with additional renewal provisions) with each of the five LNG Canada participants. We currently
hold a 35 per cent ownership interest in Coastal GasLink LP and have been contracted to develop and operate the pipeline.
The project is currently more than 59 per cent complete. The entire route has been cleared, grading is more than 70 per cent
complete and more than 240 km (149 miles) of pipeline has been installed, with reclamation activities underway in many areas.
As a result of scope changes, previous permit delays compared to the original construction schedule and the impacts from
COVID-19, including a health order issued by the British Columbia Provincial Health Officer restricting the number of workers on
site from late December 2020 until mid-April 2021, we continue to expect project costs to increase significantly along with a
delay to project completion compared to the original project cost and schedule. Coastal GasLink has sought to mitigate cost
increases and schedule delays and will continue to do so.
Coastal GasLink is in dispute with LNG Canada with respect to the recognition of certain costs and the impacts on schedule;
however, the parties are in active and constructive discussions toward a resolution of this matter. We do not expect any
suspension of construction activities while discussions continue. The ultimate level of debt financing and the amounts to be
contributed as equity by Coastal GasLink LP partners, including us, will be determined by the substance of a resolution with
LNG Canada.
During this time, in addition to using funds from its $6.8 billion project-level credit facility and the recovery of construction
carrying costs from LNG Canada, construction is also being funded in part by a subordinated demand revolving facility with
TC Energy which has a current capacity of $500 million and provides the project with additional short-term funding and financial
flexibility. At December 31, 2021, $1 million was outstanding on this revolving facility.
42 | TC Energy Management's discussion and analysis 2021
In fourth quarter 2021, as a further interim measure, TC Energy executed a subordinated loan agreement to provide additional
temporary financing to the project, if necessary, of up to $3.3 billion as a bridge to a required increase in the $6.8 billion
project-level financing to fund incremental costs. This financing will be provided through a combination of interest-bearing
loans and loans that are subject to a return to TC Energy under certain conditions at the time the final cost of the project is
determined. At December 31, 2021, $238 million was outstanding on these loans.
NGTL System
In the year ended December 31, 2021, the NGTL System placed approximately $1.1 billion of capacity projects in service.
2022 NGTL System Expansion Program
In 2021, we received regulatory approval for the 2022 NGTL System Expansion Program. With an estimated capital cost of
$1.2 billion, the 2022 NGTL System Expansion Program consists of approximately 166 km (103 miles) of new pipeline, one new
compressor unit and associated facilities and will provide incremental capacity of approximately 773 TJ/d (722 MMcf/d) to meet
firm-receipt and intra-basin delivery requirements with eight-year terms. Construction activities began in September 2021 with
anticipated in-service dates commencing in fourth quarter 2022.
2023 NGTL System Intra-Basin Expansion
In 2021, we received regulatory approval to construct and operate the NGTL System Intra-Basin Expansion Program, consisting of
23 km (14 miles) of new pipeline and two new compressor stations and is underpinned by approximately 255 TJ/d (238 MMcf/d)
of new firm-service contracts with 15-year terms. Based on the outcome of the 2021 Capacity Optimization Open Season,
changes in expected supply have reduced the scope of the program which now has an estimated capital cost of $0.6 billion. The
NGTL System Intra-Basin Expansion is expected to be placed in service commencing in 2023.
NGTL System/Foothills West Path Delivery Program
In 2019, we announced our West Path Delivery Program which is an expansion of the NGTL System and Foothills for contracted
incremental export capacity on GTN. The Canadian portion of the expansion program has an estimated capital cost of $1.2 billion
as a result of refined cost estimates and increased construction costs and consists of approximately 107 km (66 miles) of pipeline
and associated facilities with in-service dates in fourth quarter 2022 and fourth quarter 2023. The program is underpinned by
approximately 275 TJ/d (258 MMcf/d) of new firm-service contracts with terms that exceed 30 years. Regulatory approvals to
construct and operate $0.4 billion of the facilities have been received and applications for the remaining facilities have been
submitted with approvals anticipated in first and fourth quarter 2022.
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
Other Canadian pipelines1
Comparable EBITDA
Depreciation and amortization
Comparable EBIT
Specific item:
Gain on partial sale of Coastal GasLink LP
Segmented earnings
2021
1,649
838
188
2,675
(1,226)
1,449
—
1,449
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
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.
TC Energy Management's discussion and analysis 2021 | 43
Canadian Natural Gas Pipelines segmented earnings decreased by $208 million in 2021 compared to 2020 and increased by
$542 million in 2020 compared to 2019. Segmented earnings in 2020 include a pre-tax gain 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 EBITDA and
comparable EBIT.
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
2021
2020
2019
631
213
15,560
3,724
565
160
14,070
3,673
484
173
11,959
3,690
Net income for the NGTL System increased by $66 million in 2021 compared to 2020 and $81 million in 2020 compared to 2019
mainly due to a higher average investment base resulting from continued system expansions. Effective January 1, 2020, the
NGTL System is operating under the 2020-2024 Revenue Requirement Settlement which includes an ROE of 10.1 per cent on
40 per cent deemed common equity. This settlement provides the NGTL System the opportunity to increase depreciation rates if
tolls fall below specified levels and an incentive mechanism for certain operating costs where variances from projected amounts
are shared with our customers. The NGTL System’s 2019 results reflected the 2018-2019 Revenue Requirement Settlement that
expired on December 31, 2019 and 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 increased by $53 million in 2021 compared to 2020 mainly as a result of higher incentive
earnings and the elimination of a $20 million after-tax annual TC Energy contribution included in the previous settlement. Net
income in 2020 decreased by $13 million compared to 2019 mainly as a result of lower incentive earnings. Effective
January 1, 2021, the Canadian Mainline is operating under the 2021-2026 Mainline Settlement which includes an approved ROE of
10.1 per cent on 40 per cent deemed common equity and an incentive to decrease costs and increase revenues on the pipeline
under a beneficial sharing mechanism with our customers. In 2020 and 2019, the Canadian Mainline operated under the terms of
the 2015-2030 Tolls Application approved in 2014. The terms of the previous 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.
Comparable EBITDA
Comparable EBITDA for Canadian Natural Gas Pipelines was $109 million higher in 2021 compared to 2020 primarily due to the
net effect of:
• higher flow-through depreciation and income taxes as well as increased rate-base earnings on the NGTL System
• Coastal GasLink development fee revenue which commenced in second quarter 2020
• lower flow-through depreciation and financial charges, partially offset by higher flow-through income taxes, increased
incentive earnings and elimination of the TC Energy contribution on the Canadian Mainline.
Comparable EBITDA for Canadian Natural Gas Pipelines in 2020 was $292 million higher than 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 which commenced in 2020.
44 | TC Energy Management's discussion and analysis 2021
Depreciation and amortization
Depreciation and amortization was $47 million lower in 2021 compared to 2020 mainly due to one section of the Canadian
Mainline being fully depreciated in 2021, partially offset by higher depreciation on the NGTL System from expansion facilities that
were placed in service in 2021 and 2020. Depreciation and amortization was $114 million higher in 2020 compared to 2019 due to
additional NGTL System facilities placed in service in 2020 and 2019.
OUTLOOK
Comparable EBITDA and 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 comparable EBITDA is expected to be higher in 2022 driven by continued NGTL System expansion
and recovery of flow-through items, partially offset by the reduction of flow-through depreciation in the Canadian Mainline as
one segment was fully depreciated in 2021. Due to the flow-through treatment of certain expenses on our Canadian regulated
pipelines, changes in these amounts can impact our comparable EBITDA despite having no significant effect on comparable
earnings.
Canadian Natural Gas Pipelines comparable earnings in 2022 are expected to be higher than 2021 mainly due to continued
growth of the NGTL System as we advance expansion programs which extend and expand supply facilities, enhance delivery
facilities in Alberta and provide incremental service at our major border delivery locations in response to requests for firm service
on the system.
Capital spending
We spent a total of $2.7 billion in 2021 in our Canadian natural gas pipelines business on growth projects and maintenance
capital expenditures. We expect to spend approximately $3.5 billion in 2022, primarily on NGTL System expansion projects and
maintenance capital expenditures, all of which are immediately reflected in investment base and related earnings.
TC Energy Management's discussion and analysis 2021 | 45
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 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 (NPRM) 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 and the gathering line rule (part three) was issued in
November 2021. We continue to assess the operational and financial impact related to this final rule over its 15-year
implementation window that began in July 2020 and seek to optimize recovery of those costs. The remaining rulemaking
comprising the Gas Mega Rule is currently expected to be issued in April 2022.
In addition to the rulemakings noted above, new pipeline safety legislation was signed into law in December 2020 that
reauthorized PHMSA pipeline safety programs that expired under the 2016 Pipeline Safety Act at the end of September 2019. We
are in the process of assessing the impacts associated with this new legislation which include self-directed mandates to natural
gas transmission operations requiring targeted reduction of methane releases.
The Pipeline Rupture Detection and Mitigation for Onshore Populated and High Consequence Areas (HCAs) rulemaking is
expected to be published as a final rule in March 2022. The rupture detection and mitigation rule will define when the
installation of automatic shutoff valves, remote-controlled valves or manual valves is required on newly constructed pipelines or
replacements six inches and larger in diameter. The rule primarily targets Class 3 and 4 locations and HCAs but also includes more
stringent mandates on the timeliness of response and the ability for the Supervisory Control and Data Acquisition System to
detect and alert operations controllers of potential large-scale leaks with a 40-minute requirement to have a release fully
isolated. We have provided initial comments on the NPRM and will perform a full assessment when the rule is issued as final.
46 | TC Energy Management's discussion and analysis 2021
TC PipeLines, LP
On March 3, 2021, we completed the acquisition of all of the outstanding common units of TC PipeLines, LP not beneficially
owned by TC Energy. TC PipeLines, LP has ownership interests in the GTN, Northern Border, Bison, Great Lakes, North Baja,
Tuscarora, Iroquois and Portland pipeline systems. Our overall ownership for each of these assets is provided in the asset listing of
our major pipelines starting on page 39. Refer to the Corporate – Significant events section for additional information regarding
the acquisition of all outstanding common units of TC PipeLines, LP not beneficially owned by TC Energy.
SIGNIFICANT EVENTS
Columbia Gas Section 4 Rate Case
Columbia Gas filed a Section 4 rate case with FERC in July 2020 requesting an increase to its maximum transportation rates
effective February 1, 2021, subject to refund upon completion of the rate proceeding. On July 28, 2021, Columbia Gas notified
FERC that it reached a settlement-in-principle with its customers addressing all remaining issues in the case, including but not
limited to the resolution of rates and continuation of Columbia Gas's modernization program. On October 29,
2021, Columbia
Gas filed its settlement with FERC, and is now awaiting approval, with 2021 revenues expected to be generally consistent with
estimates recorded to date. On December 17, 2021, the presiding Administrative Law Judge recommended the settlement for
approval and certified it as uncontested to FERC for its review and approval. While there is no timeframe in which FERC must act
on the settlement, in line with other recent rate case settlement approval timelines, we expect to receive approval of the
settlement in early 2022.
Grand Chenier XPress
Phase I of Grand Chenier XPress, an expansion project on ANR connecting supply directly to U.S. Gulf Coast LNG export facilities,
went into service in April 2021. Phase II was placed in service in January 2022.
Delivery Market Projects
We are actively developing projects that will replace and upgrade certain facilities while reducing emissions along portions of our
pipeline systems in principal delivery markets. The enhanced facilities are expected to improve reliability of the systems and
allow for additional transportation services to address growing demand under long-term contracts while reducing direct
CO2e emissions. Consistent with this initiative, the VR project on Columbia Gas was sanctioned in 2021, subject to customary
conditions precedent and normal-course regulatory approvals. This project represents an approximate US$0.7 billion capital
investment and is targeted to be placed in service during the second half of 2025. Similarly, the WR project on ANR was also
sanctioned in 2021 and will serve markets in the midwestern U.S. This project has an estimated capital cost of approximately
US$0.8 billion and is expected to be placed in service in fourth quarter 2025.
GTN Rate Case Settlement
On September 29, 2021, GTN filed an uncontested rate settlement which would set new recourse rates for GTN effective
January 1, 2022 and institute a rate moratorium through December 31, 2023. The uncontested rate settlement was approved by
FERC on November 18, 2021. The revised rates are not expected to have a significant impact on our U.S. Natural Gas Pipelines
segment comparable earnings. In addition, GTN must file for new rates no later than April 1, 2024.
GTN XPress
The GTN XPress expansion project filed its FERC certificate application in fourth quarter 2021 and is expected to be placed in
service in the second half of 2023.
Modernization III
Subject to FERC approval as part of the Columbia Gas uncontested rate settlement, Columbia Gas and its customers entered into
a settlement arrangement (Modernization III) which provides recovery and return on investment to modernize its system,
improve system safety, integrity, compliance and reliability. The Modernization III program includes, among other things,
replacement of aging pipeline and compressor facilities, enhancements to system inspection capabilities and improvements in
control systems as well as projects designed to increase energy efficiency and reduce emissions. The program was approved for
up to US$1.2 billion of work starting in 2021 and is to be completed through 2024. As per the terms of the arrangement, facilities
in service by November 30 of each year collect revenues effective April 1 of the following year until the arrangement is
terminated. New rates will become effective once Columbia Gas files a subsequent Section 4 rate case under the Natural Gas Act.
TC Energy Management's discussion and analysis 2021 | 47
ANR Section 4 Rate Case
ANR filed a Section 4 rate case with FERC on January 28, 2022 requesting an increase to ANR's maximum transportation rates
effective August 1, 2022, subject to refund upon completion of the rate proceeding. As the rate case process progresses, we
expect to engage in a collaborative process to achieve settlement with our customers, FERC and other stakeholders.
FINANCIAL RESULTS
On March 3, 2021, we acquired all the outstanding common units of TC PipeLines, LP not beneficially owned by TC Energy in
exchange for TC Energy common shares (TC PipeLines, LP acquisition). TC PipeLines, LP results for the year ended
December 31, 2021 and comparative results for 2020 and 2019 reflect our ownership interests in eight natural gas pipelines prior
to the acquisition.
The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings
(the most directly comparable GAAP measure). Refer to page 11 for more information on non-GAAP measures we use.
year ended December 31
(millions of US$, unless otherwise noted)
Columbia Gas
ANR
Columbia Gulf
Great Lakes1,2
GTN2,3
Other U.S. pipelines2,5
TC PipeLines, LP2,4
Non-controlling interests4
Comparable EBITDA
Depreciation and amortization
Comparable EBIT
Foreign exchange impact
Comparable EBIT (Cdn$)
Specific items:
Gain on sale of Columbia Midstream assets
Risk management activities
Segmented earnings (Cdn$)
2021
1,529
592
220
158
139
313
24
100
3,075
(630)
2,445
620
3,065
—
6
2020
1,305
512
195
91
—
117
119
375
2,714
(597)
2,117
720
2,837
—
—
2019
1,222
492
164
86
—
172
119
368
2,623
(568)
2,055
671
2,726
21
—
3,071
2,837
2,747
1
2
3
4
5
Results reflect our 53.55 per cent direct interest in Great Lakes until March 3, 2021 and our 100 per cent ownership interest subsequent to the
TC PipeLines, LP acquisition.
Our ownership interest in TC PipeLines, LP was 25.5 per cent prior to our acquisition on March 3, 2021, at which time it became 100 per cent. Prior to
March 3, 2021, TC PipeLines, LP's results reflected a 46.45 per cent ownership interest in Great Lakes, its ownership of GTN, Bison, North Baja, Portland and
Tuscarora as well as its share of equity income from Northern Border and Iroquois.
Reflects 100 per cent of GTN's comparable EBITDA, subsequent to our acquisition of TC PipeLines, LP on March 3, 2021.
Reflects comparable EBITDA attributable to portions of TC PipeLines, LP and Portland that we did not own prior to our acquisition of TC PipeLines, LP on
March 3, 2021, and subsequently reflects earnings attributable to the remaining 38.3 per cent interest in Portland we do not own.
Reflects comparable EBITDA from our ownership in our mineral rights business, Crossroads and our share of equity income from Millennium and Hardy Storage,
as well as general and administrative and business development costs related to our U.S. natural gas pipelines. For the period subsequent to our acquisition of
TC PipeLines, LP on March 3, 2021, results also include 100 per cent of Bison, North Baja and Tuscarora, 61.7 per cent of Portland, plus our equity income from
Northern Border and Iroquois.
48 | TC Energy Management's discussion and analysis 2021
U.S. Natural Gas Pipelines segmented earnings in 2021 increased by $234 million compared to 2020 and increased by $90 million
in 2020 compared to 2019 and included the following specific items which have been excluded from our calculation of
comparable EBIT and comparable earnings:
• unrealized gains from changes in the fair value of derivatives related to our U.S. natural gas marketing business in 2021
• a pre-tax gain of $21 million related to the sale of certain Columbia Midstream assets in August 2019.
A weaker U.S. dollar in 2021 had a negative impact on the Canadian dollar equivalent segmented earnings from our
U.S. operations compared to the same period in 2020, while 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.
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 natural gas storage capacity and incidental commodity sales. Natural gas pipeline and storage volumes and
revenues are generally higher in the winter months because of the seasonal nature of the business.
Comparable EBITDA for U.S. Natural Gas Pipelines was US$361 million higher in 2021 than 2020 primarily due to the net effect of:
• a net increase in earnings from Columbia Gas as a result of the higher transportation rates effective February 1, 2021, pursuant
to the Columbia Gas uncontested rate case settlement. Refer to the U.S. Natural Gas Pipelines – Significant events section for
additional information
• increased earnings across our U.S. Natural Gas Pipelines assets which includes the impact of cold weather events in 2021
impacting many of the U.S. markets in which we operate
• increased earnings from our mineral rights business due to higher commodity prices
• incremental earnings resulting from increased capitalization of pipeline integrity costs and the contribution from growth
projects placed in service primarily on Columbia Gas and ANR, partially offset by higher property taxes.
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.
The positive impact on comparable earnings following the TC PipeLines, LP acquisition noted above is reflected through a
reduction in Non-controlling interests. Refer to the Corporate – Financial results section for additional information.
Depreciation and amortization
Depreciation and amortization was US$33 million higher in 2021 compared to 2020 mainly due to new projects placed in service,
net of certain fourth quarter 2021 adjustments related to the Columbia Gas uncontested rate case settlement and was
US$29 million higher in 2020 compared to 2019 mainly due to new projects placed in service.
TC Energy Management's discussion and analysis 2021 | 49
OUTLOOK
Comparable EBITDA
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. Comparable EBITDA is also affected by 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 comparable EBITDA in 2022 is expected to be consistent with 2021. This is due to, among other factors,
an expected increase in transportation rates on ANR subject to the outcome of the Section 4 rate case filed with FERC,
completion of expansion projects in 2021 and 2022 on the ANR and Columbia Gulf systems as well as higher revenues on
Columbia Gas due to the full-year implementation of higher transportation rates as part of the uncontested Section 4 rate case
settlement filed with FERC. Our pipeline systems continue to see historically strong demand for service and we anticipate our
assets will maintain the high utilization levels experienced in 2021. These positive results are expected to be partially offset by
higher operational costs and an anticipated increase in property taxes from capital projects placed in service.
Capital spending
We spent a total of US$2.2 billion in 2021 on our U.S. natural gas pipelines and expect to spend approximately US$1.6 billion in
2022 primarily on ANR expansion projects and our Columbia Gas Modernization III program, as well as Columbia Gas and ANR
maintenance capital expenditures, the return on and recovery of which is expected to be reflected in future tolls.
50 | TC Energy Management's discussion and analysis 2021
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. 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 generally at risk for operating and construction costs and in-service delay penalties, excluding
force majeure events which provide schedule relief. 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 currently suspended while management holds settlement discussions with the CFE.
In 2021, we advanced the resolution of disputed contract terms with the signing of an MOU on July 30, 2021 outlining main
settlement principles.
Villa de Reyes construction is ongoing but completion has been delayed due to COVID-19 contingency measures and challenges
gaining access to land in certain local communities. Management is working closely with state and local governments to
complete negotiations and achieve access to land so that construction can be completed. We expect to complete the
construction of Villa de Reyes in phases during 2022.
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)
2021
2020
2019
Topolobampo
Sur de Texas1
Tamazunchale
Guadalajara
Mazatlán
Comparable EBITDA
Depreciation and amortization
Comparable EBIT
Foreign exchange impact
Comparable EBIT and segmented earnings (Cdn$)
161
113
118
71
70
533
(86)
447
110
557
159
171
120
64
70
584
(87)
497
172
669
159
43
120
65
70
457
(87)
370
120
490
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 2021 decreased by $112 million compared to 2020 and increased by
$179 million in 2020 compared to 2019. A weaker U.S. dollar in 2021 had a negative impact on the Canadian dollar equivalent
segmented earnings from our Mexico operations compared to the same period in 2020, while 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.
TC Energy Management's discussion and analysis 2021 | 51
Comparable EBITDA for Mexico Natural Gas Pipelines decreased by US$51 million in 2021 compared to 2020 mainly due to:
• decreased Sur de Texas equity income due to one-time fees of US$55 million recognized in 2020 associated with the
construction of the project
• higher earnings from Guadalajara following the implementation of a flow reversal project completed in 2020.
Comparable EBITDA for Mexico Natural Gas Pipelines increased by US$127 million in 2020 compared to 2019 mainly due to:
• 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 construction 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.
Depreciation and amortization
Depreciation and amortization in 2021 was consistent with the same periods in 2020 and 2019.
OUTLOOK
Comparable EBITDA
Mexico Natural Gas Pipelines comparable EBITDA reflects long-term, stable, principally U.S. dollar-denominated transportation
contracts that are affected by the cost of providing service and includes 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, comparable EBITDA is
generally consistent year-over-year except when new assets are placed into service. Comparable EBITDA for 2022 is expected to
be higher than 2021 due to the anticipated settlement of the disputed contract terms with the CFE and the expected in-service
of Villa de Reyes during 2022.
Capital spending
We spent a total of US$0.1 billion in 2021 primarily related to the construction of the Villa de Reyes pipeline, maintenance of
constructed Tula segments and life-cycle enhancements to existing assets. Capital spending in 2022 to complete construction of
Villa de Reyes and additional life-cycle asset investments is expected to be US$0.1 billion.
52 | TC Energy Management's discussion and analysis 2021
NATURAL GAS PIPELINES – BUSINESS RISKS
The following are risks specific to our Natural Gas Pipelines business. Refer to page 93 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. Columbia Gas 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 policy and 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 are being developed closer to markets we have
historically served and 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 pipeline expansion
We face competition from other pipeline companies seeking to invest in greenfield natural gas pipeline development
opportunities. This competition could result in fewer available projects that meet our investment hurdles or projects that
proceed with lower overall financial returns. While renewable deployments are expected to garner an increasing portion of
future energy needs, including in the power generation sector, natural gas demand is still projected to grow under the most
aggressive renewable deployment forecasts. The reliability of natural gas is an important factor in the successful wide-scale
deployment of renewables with more intermittent capabilities.
Demand for pipeline capacity
Demand for pipeline capacity ultimately drives the sale of pipeline transportation services and is impacted by supply and market
competition, variations in economic activity, weather variability, natural gas pipeline and storage competition, energy
conservation as well as 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 of demand for transportation services
and/or new natural gas pipeline infrastructure. Disruptions in the energy supply chain can result in price volatility and a decline
in natural gas prices that could impact our shippers' financial condition and their ability to meet their transportation service cost
obligations.
TC Energy Management's discussion and analysis 2021 | 53
Regulatory risk
Decisions and evolving policies by regulators and other government authorities, including changes in regulation, can impact 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 could therefore 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 evolving public opinion and government policy related to natural gas pipeline
infrastructure development. If regulatory decisions are subsequently challenged in courts, this could result in further impacts to
project costs and schedule delays.
Increased scrutiny of construction and operations processes by the regulator 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 legislative and 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 or changes in government can impact our ability to grow our business. More complex regulatory
processes, broader consultation requirements, more restrictive emissions policies and changes to environmental regulations 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.
54 | TC Energy Management's discussion and analysis 2021
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 460 km (290 miles).
Strategy
Optimize the value of our existing Liquids Pipelines assets, while operating safely and reliably. We also pursue emerging growth
opportunities to add incremental value to our business. In support of our GHG emissions reduction targets, we are taking
significant steps to source renewable power for our operations. The strategy addresses scope two emissions, which are primarily
generated by the consumption of electricity used to power our liquids pipelines.
Recent highlights
• U.S. President Biden revoked the existing Presidential Permit for the Keystone XL pipeline project on January 20, 2021. As a
result, we terminated the Keystone XL pipeline project
• submitted a Request for Arbitration to formally initiate a legacy North American Free Trade Agreement (NAFTA) claim to
recover economic damages resulting from the revocation of the Presidential Permit for the Keystone XL pipeline project
• received $35 million in proceeds from the monetization of our remaining interest in Northern Courier
• entered into a joint venture with Motiva Enterprises (Motiva) to construct the US$152 million Port Neches Link pipeline system.
Construction has commenced and is expected to be in service in mid-2022.
TC Energy Management's discussion and analysis 2021 | 55
56 | TC Energy Management's discussion and analysis 2021
We are the operator and developer of the following:
Liquids pipelines
1
Keystone Pipeline System
2 Marketlink
3 Grand Rapids
4 White Spruce
In development
5 Grand Rapids Phase II
Length
Description
Ownership
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.
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.
460 km
(287 miles)
72 km
(45 miles)
460 km
(287 miles)
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.
100%
100%
50%
100%
50%
TC Energy Management's discussion and analysis 2021 | 57
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, and offer ancillary services such as short- and long-term storage of liquids at key terminal locations
to offer our customers delivery flexibility while optimizing the value of our pipeline assets.
We provide pipeline transportation capacity to customers 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 customers
which provide for the recovery of costs we incur to construct the asset. Generally, the costs to operate and maintain the system
are flowed through to customers via a variable-toll mechanism. 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 the U.S. Midwest and
the U.S. Gulf Coast refiners' demand for Canadian crude oil. It also provides significant capacity between Cushing, Oklahoma and
the U.S. Gulf Coast market, primarily transporting U.S. crude oil. Our two intra-Alberta liquids pipelines – Grand Rapids and White
Spruce – provide crude oil 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 continues to be impacted by the COVID-19 pandemic as containment measures imposed by
most countries around the world continue to reduce transportation, commercial and non-essential activities. Demand is
expected to gradually recover to pre-COVID-19 levels through 2022.
Global crude oil and liquids demand is projected to increase from 97 million Bbl/d in 2021 to 107 million Bbl/d in 2035, driven
primarily by the transportation and industrial sectors which account for 80 per cent of total crude oil and liquids demand. 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, South America and the Middle East. To meet this demand requirement, a strong crude oil price
environment is needed to support continuing investment in the energy sector.
Crude oil prices have recovered from 2020 lows, due to crude oil supply management efforts, primarily by OPEC+, capital
discipline of North American producers and global demand growth. The ongoing COVID-19 pandemic, combined with
uncertainty over the ability for OPEC+ to manage and meet market requirements, continues to drive crude oil price volatility.
Supply outlook
Canada
Canada has the world’s third largest crude oil reserves with over 160 billion barrels of economically and technically recoverable
conventional and oil sands reserves, primarily in Alberta. Total 2021 WCSB crude oil production was approximately
4.4 million Bbl/d and is expected to increase to approximately 5.2 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 3.2 million Bbl/d and is a favourable supply source given its decades-long reserve life, steady production and
rapidly improving cost and environmental performance.
U.S.
The U.S. is one of the largest crude oil producing countries in the world at approximately 11 million Bbl/d in 2021. The majority of
continental U.S. crude oil production is in the form of light tight oil from the Permian, Williston, Eagle Ford and Niobrara 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 greater than 6 million Bbl/d by 2035.
58 | TC Energy Management's discussion and analysis 2021
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. U.S. crude oil exports have remained strong at close to 3 million Bbl/d in 2021, despite the global demand
impact from the COVID-19 pandemic. By 2035, the U.S. is expected to export approximately 4.9 million Bbl/d of predominantly
light crude oil and import approximately 4.8 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 greater than 16 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 2021. The U.S. Midwest refiners have total refining capacity of approximately 4 million Bbl/d,
which requires approximately 1.5 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 close to 10 million Bbl/d, representing more than half of the total U.S. refining capacity. The
U.S. Gulf Coast imported over 2 million Bbl/d of primarily heavy crude oil in 2021 to meet demand.
Canada is currently the largest exporter of crude oil to the U.S. at nearly 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 continue to fall due to the continued declines in its production and
new domestic demand. Approximately 36 per cent of U.S. Gulf Coast heavy crude oil imports are currently met by Mexico which
presents a significant opportunity for Canada to become a more prominent supplier of crude oil to the U.S.
Strategic priorities
Our intra-Alberta liquids pipelines and the Keystone Pipeline System strategically position us to provide competitive
transportation solutions for growing supplies of Alberta heavy crude oil and U.S. light tight oil to the U.S. Midwest and the
U.S. Gulf Coast.
Within our established risk preferences, we remain committed to:
• optimizing the value and competitiveness 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.
COVID-19 has had a material impact on energy markets by disrupting and delaying industry growth. 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. The cyclical nature of commodity prices may influence the pace at which our customers 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.
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.
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.
TC Energy Management's discussion and analysis 2021 | 59
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. We continually work with existing and potential customers to provide pipeline transportation and terminal
services. The combination of the scale and location of our assets assists us in attracting additional volumes and in growing our
business.
We closely monitor the marketplace for strategic asset acquisitions or joint venture opportunities 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.
ESG considerations form an important part of our strategy. Our Liquids Pipelines assets can underpin our de-carbonization goals
and present opportunities to create partnerships with Indigenous communities. Our GHG reduction strategy in Liquids Pipelines
is to competitively source renewable energy to power our base operating systems and reduce our carbon footprint with a goal of
reducing 99 per cent of our liquids pipelines' scope two GHG emissions from our operations by 2025 and achieving net-zero
emissions by 2030. We also seek to develop partnerships with Indigenous communities that will create value and further enable
participation in energy infrastructure by those partners.
SIGNIFICANT EVENTS
Keystone XL
Following the revocation of the Presidential Permit for the Keystone XL pipeline project on January 20, 2021, and after a
comprehensive review of options in consultation with our partner, the Government of Alberta, on June 9, 2021, we terminated
the Keystone XL pipeline project.
The Keystone XL investment was evaluated for impairment in 2021 along with our investments in related capital projects
including Heartland Pipeline, TC Terminals and Keystone Hardisty Terminal. We determined that the carrying amount of these
assets was no longer fully recoverable. As a result, we recognized an asset impairment charge, net of expected contractual
recoveries and other contractual and legal obligations related to termination activities, of $2.8 billion ($2.1 billion after tax)
for the year ended December 31, 2021 which was excluded from comparable earnings. The asset impairment charge was based
on the excess of the carrying value of the asset of $3.3 billion over the estimated fair value of $175 million, net of contractual
recoveries of $693 million and contractual and legal obligations related to termination activities of $342 million.
Termination activities and related costs will continue through 2022 with any adjustments to the estimated fair value and future
contractual and legal obligations expensed as determined and excluded from comparable earnings. Refer to Note 6,
Keystone XL, of our 2021 Consolidated financial statements for additional information.
Although we recorded a $2.1 billion after-tax asset impairment charge, net of expected contractual recoveries and other
contractual and legal obligations related to the Keystone XL pipeline project termination activities, a significant portion of this
amount was shared with the Government of Alberta, thereby reducing the net financial impact to us. In June 2021, Class A
Interests previously issued to the Government of Alberta totaling $394 million were repurchased for a nominal amount, the
$1.0 billion (US$849 million) balance on the project-level credit facility was fully paid by the Government of Alberta and
$91 million of Class C Interests were issued to the Government of Alberta entitling them to future liquidation proceeds from
specified Keystone XL project assets. After considering these transactions, including the income tax impact thereon, the net
financial impact to us as a result of the termination of Keystone XL and related projects at December 31, 2021 was $1.0 billion
determined as follows:
(millions of $)
Asset impairment charge and other (after tax)1
Government of Alberta Class A Interests repurchased for a nominal amount2
Credit facility balance – guaranteed and paid by the Government of Alberta (net) 2,3
Net financial impact of the termination of the Keystone XL pipeline project
1
2
3
Refer to Note 6, Keystone XL, of our 2021 Consolidated financial statements for additional information.
Recognized through the Consolidated statement of equity.
Net of income taxes and Class C Interests issued.
60 | TC Energy Management's discussion and analysis 2021
2021
2,134
(394)
(737)
1,003
After the Presidential Permit was revoked, construction activities ceased except for certain activities required to clean up and
reclaim worksites in adherence to our commitment to safety, the environment and our regulatory requirements. Right-of-way
clean up and restoration is substantially complete while termination activities will continue through 2022. We will coordinate
with regulators, stakeholders and Indigenous groups to meet our environmental and regulatory commitments and ensure a safe
exit from the Keystone XL pipeline project. The majority of these associated costs were funded through a final drawdown on the
project-level credit facility which occurred in June 2021, subsequent to which the project-level credit facility was fully repaid by
the Government of Alberta and terminated.
We continue to manage legacy challenges to the Presidential Permit and the Bureau of Land Management Grant of
Right-of-Way, which remain pending before the federal district court in Montana in a manner consistent with the termination of
the project.
On November 22, 2021, we filed a Request for Arbitration to formally initiate a legacy NAFTA claim to recover economic damages
resulting from the revocation of the Presidential Permit for the Keystone XL pipeline project. We will be seeking to recover more
than US$15 billion in damages as a result of the U.S. Government's breach of its NAFTA obligations. This claim is in a preliminary
stage with the timing and ultimate outcome unknown at present.
Northern Courier
On November 30, 2021, we received $35 million in proceeds from the monetization of our remaining 15 per cent equity interest
in Northern Courier to Astisiy Limited Partnership, a partnership comprised of Suncor Energy Inc. and eight Indigenous
communities in the Regional Municipality of Wood Buffalo. As a result, we recorded a pre-tax gain on sale of $13 million
($19 million after tax). The pre-tax gain was included in Net gain/(loss) on assets sold/held for sale in the Consolidated statement
of income.
Port Neches
On March 8, 2021, we entered a joint venture with Motiva to construct the US$152 million Port Neches Link pipeline system which
will connect the Keystone Pipeline System to Motiva’s Port Neches Terminal, which supplies 630,000 Bbl/d to their Port Arthur
refinery. This common carrier pipeline system will also include facilities to tie in additional liquids terminals to the
Keystone Pipeline System with other downstream infrastructure and is expected to be in service in the second half of 2022.
TC Energy Management's discussion and analysis 2021 | 61
FINANCIAL RESULTS
The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented
(losses)/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
Intra-Alberta pipelines1
Liquids marketing and other
Comparable EBITDA
Depreciation and amortization
Comparable EBIT
Specific items:
Keystone XL asset impairment charge and other
Keystone XL preservation and other
Gain on sale of Northern Courier
Risk management activities
Segmented (losses)/earnings
Comparable EBITDA denominated as follows:
Canadian dollars
U.S. dollars
Foreign exchange impact
Comparable EBITDA
2021
1,281
87
158
1,526
(318)
1,208
(2,775)
(43)
13
(3)
2020
1,474
92
134
1,700
(332)
1,368
—
—
—
(9)
(1,600)
1,359
417
884
225
1,526
418
955
327
1,700
2019
1,654
137
401
2,192
(341)
1,851
—
—
69
(72)
1,848
442
1,318
432
2,192
1
Intra-Alberta pipelines included Grand Rapids, White Spruce and Northern Courier. In July 2019, we sold an 85 per cent interest in Northern Courier, subsequent
to which we applied equity accounting to our remaining 15 per cent investment. In November 2021, we sold the remaining 15 per cent interest in Northern
Courier.
Liquids Pipelines segmented earnings decreased by $3.0 billion in 2021 compared to 2020 and decreased by $489 million in 2020
compared to 2019 and included the following specified items which have been excluded from our calculation of comparable
EBIT:
• a $2.8 billion pre-tax asset impairment charge, net of expected contractual recoveries and other contractual and legal
obligations, in 2021 associated with the termination of the Keystone XL pipeline project and related projects following the
January 20, 2021 revocation of the Presidential Permit. Refer to the Liquids Pipelines – Significant events section for additional
information
• pre-tax preservation and other costs in 2021 of $43 million related to the preservation and storage of the Keystone XL pipeline
project assets which could not be accrued as part of the Keystone XL asset impairment charge
• pre-tax gain of $13 million related to the sale of the remaining 15 per cent interest in Northern Courier in 2021 and $69 million
related to the sale of an 85 per cent interest in Northern Courier in 2019
• unrealized gains and losses from changes in the fair value of derivatives related to our liquids marketing business.
A weaker U.S. dollar in 2021 had a negative impact on the Canadian dollar equivalent segmented earnings from our
U.S. operations compared to the same period in 2020, while 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.
Comparable EBITDA for Liquids Pipelines was $174 million lower in 2021 compared to 2020 primarily due to the net effect of:
• lower volumes on the U.S. Gulf Coast section of the Keystone Pipeline System
• increased contributions from liquids marketing activities mainly attributable to higher margins and volumes.
62 | TC Energy Management's discussion and analysis 2021
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.
Depreciation and amortization
Depreciation and amortization was $14 million lower in 2021 compared to 2020 primarily as a result of a weaker U.S. dollar.
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.
OUTLOOK
Comparable EBITDA
Comparable EBITDA in 2022 is expected to be lower than 2021 for both the Keystone Pipeline System and liquids marketing
business as a result of continuing lower volumes on the U.S. Gulf Coast section of the Keystone Pipeline System and decreased
margins, respectively. As discussed in the Understanding our Liquids Pipelines business section, global crude oil demand
continues to be impacted by the COVID-19 pandemic but is expected to gradually recover to pre-COVID-19 levels through 2022.
Capital spending
We spent a total of $0.2 billion in 2021 primarily related to capital projects in the U.S. Gulf Coast and on our operating pipelines
and expect to spend approximately $0.2 billion in 2022.
BUSINESS RISKS
The following are risks specific to our Liquids Pipelines business. Refer to page 93 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.
Operations
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.
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 and operation 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. In the 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 could negatively impact opportunities to expand our liquids
pipelines infrastructure and, in the longer term, to re-contract with customers as current agreements expire.
TC Energy Management's discussion and analysis 2021 | 63
Competition
As we continue to further develop our competitive position in the North American liquids transportation market to connect
growing crude oil 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.
Shifting political trends and ESG requirements
North American governments are attempting to improve their environmental standards and position climate action as a key
priority. Meanwhile, the business environment is also evolving quickly as investors demand greater ESG commitments. While
there is downside risk to policies that shift support away from our traditional services, there are also opportunities to reduce
GHG emissions and generate associated renewable energy and carbon credits for TC Energy.
64 | TC Energy Management's discussion and analysis 2021
Power and Storage
Our power business includes approximately 4,300 MW of generation capacity located in Alberta, Ontario, Québec and
New Brunswick, using natural gas and nuclear fuel sources and is generally supported by long-term contracts. Additionally, we
are pursuing generation assets and PPA opportunities in Canada and the United States.
We own and operate approximately 118 Bcf of non-regulated natural gas storage capacity in Alberta.
Strategy
Our strategy is to leverage TC Energy’s competitive footprint as a platform to grow our power business and enhance the life cycle
and reliability of our assets, all driven by internal and external customer needs. Long term, we believe there will be a growing
need for a reliable supply of resources as the energy transition unfolds. We can play a vital role in the energy transition by
sourcing zero-carbon growth opportunities, new technologies and markets while decarbonizing our existing assets.
Recent highlights
• further advanced the Bruce Power life extension program with the submission of the final cost and schedule duration estimate
to the IESO for the Unit 3 MCR while the Unit 6 MCR project proceeded on budget and schedule
• executed a 15-year PPA for 100 per cent of the power produced and associated environmental attributes from the 297 MW
Sharp Hills Wind Farm located in Alberta, which is anticipated to begin operation in 2023
• continued to progress the development of the 1,000 MW clean energy Ontario Pumped Storage Project on federal lands,
subject to conditions and regulatory approval
• the Claresholm Solar facility came into service commencing our eight-year PPA and adding 74 MW to our portfolio
• completed the purchase of the remaining interests in the Canyon Creek Pumped Storage project giving us full ownership.
TC Energy Management's discussion and analysis 2021 | 65
66 | TC Energy Management's discussion and analysis 2021
Power and Storage assets currently have a combined power generation capacity, net to TC Energy, of 4,258 MW and we operate
each facility except for Bruce Power.
Generating
capacity (MW)
Type of fuel Description
1 Bruce Power1
3,170
nuclear
Eight operating reactors in Tiverton, Ontario. Bruce Power
leases the nuclear facilities from OPG.
Ownership
48.4%
2 Bécancour
550
natural gas Cogeneration plant in Trois-Rivières, Québec. Power generation
100%
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
8 Crossfield
9 Edson
68 Bcf
50 Bcf
1
Our share of power generation capacity.
Underground facility connected to the NGTL System near
Crossfield, Alberta.
Underground facility connected to the NGTL System near
Edson, Alberta.
100%
100%
100%
100%
100%
100%
100%
TC Energy Management's discussion and analysis 2021 | 67
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 or have the rights to approximately 1,100 MW of power supply in Canada, excluding our investment in Bruce Power. In
Alberta we own four natural gas-fired cogeneration facilities and exercise a disciplined operating strategy to maximize revenues.
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 6,550 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 is the first of the six-unit MCR life extension program. This outage commenced in January 2020 and is expected
to be completed on schedule and on budget. The second unit in the MCR program is Unit 3 and the final cost and schedule
duration estimate for Unit 3 was submitted to the IESO in December 2021. The Unit 3 MCR is scheduled to proceed in 2023 and
has an expected completion in 2026. Investments in the remaining four units' MCR programs 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. In 2021, Bruce Power launched Project 2030 with a goal of achieving a site peak output of 7,000 MW by
2033 in support of climate change targets and future clean energy needs. Project 2030 will focus on continued asset
optimization, innovation and leveraging new technology, which could include integration with storage and other forms of
energy, to increase the site peak output.
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.
68 | TC Energy Management's discussion and analysis 2021
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 was paid to the IESO from 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. No
operating and cost efficiencies were realized for the 2019 to 2021 period.
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, harvested during certain planned
maintenance outages and provided for medical use 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.
U.S. Power
Our U.S. power and emissions commercial trading and marketing business provides our customers with various physical and
financial products with a measured approach to our risk management and a focus on financial discipline, compliance and
operational excellence.
Power Purchase Agreements
We have secured approximately 400 MW of wind and solar generation PPAs and associated environmental attributes in Alberta
as of December 31, 2021. These PPAs allow us to generate incremental earnings while also contributing to the reduction of our
operational GHG intensity and allowing us to offer renewable power products to our customers.
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 for these transactions.
TC Energy Management's discussion and analysis 2021 | 69
SIGNIFICANT EVENTS
Sharp Hills Wind Power Purchase Agreement
On September 20, 2021, we executed a 15-year PPA for 100 per cent of the power produced and the rights to all environmental
attributes from the 297 MW Sharp Hills Wind Farm located in eastern Alberta. The Sharp Hills Wind Farm is anticipated to be
operational in 2023, subject to customary regulatory approvals and conditions.
Bruce Power Outage
In mid-2021, as part of the planned inspections, testing, analysis and maintenance activities at Bruce Power during the current
Unit 6 MCR outage and the Unit 3 planned outage, higher than anticipated readings of hydrogen concentration in pressure tubes
were detected. These readings were limited to a very small area of the respective pressure tubes and did not impact safety nor
pressure tube integrity as concluded following an assessment of all of the Bruce Power units. On October 9, 2021, Unit 3 returned
to service after the Canadian Nuclear Safety Commission approved Bruce Power's restart request following extensive inspections
which demonstrated that safety and pressure tube integrity continued to meet regulatory requirements. Bruce Power will be
incorporating additional inspections as part of their normal surveillance programs to address the new findings while progressing
further programs that demonstrate fitness for service at elevated hydrogen concentration levels. These inspections were added
to the Unit 7 planned outage which returned to service on January 23, 2022.
Bruce Power Life Extension
The Unit 6 MCR program continues on schedule and on budget; however, COVID-19 may have an impact on cost and schedule
contingency. As applicable, Bruce Power will seek recovery of any impacts in accordance with the force majeure provisions of the
IESO contract. The program is nearing the end of the Inspection Phase and has entered the Installation Phase. Preparation of the
Unit 3 MCR program, which is the next scheduled MCR outage, continues and Bruce Power submitted its final cost and schedule
duration estimate to the IESO in December 2021. As well, Bruce Power submitted its initial preliminary cost and schedule
duration estimate for the Unit 4 MCR program, which is the next unit scheduled after Unit 3.
Bruce Power Uprate Initiative
In 2021, Bruce Power launched Project 2030 with the goal of achieving a site peak output of 7,000 MW by 2033 in support of
climate change targets and future clean energy needs. Project 2030 will focus on continued asset optimization, innovation and
leveraging new technology, which could include integration with storage and other forms of energy, to increase the site peak
output at Bruce Power.
Ontario Pumped Storage Project
As part of our strategy to capture opportunities that capitalize on the transition to a less carbon-intensive energy mix, we
continue to progress the development of the Ontario Pumped Storage project, an energy storage facility located near
Meaford, Ontario that would provide 1,000 MW of flexible, clean energy to Ontario's electricity system using a process known
as pumped hydro storage.
Two key milestones on the Ontario Pumped Storage project were reached in 2021. On July 28, 2021, the Federal Minister of
National Defence granted long-term land access to the fourth Canadian Division Training Centre for development of the project
on this site. On November 11, 2021, Ontario’s Minister of Energy instructed the IESO to progress the project to Gate 2 of the
Unsolicited Proposals Process. Once in service, this project will store emission-free energy when available and provide it to
Ontario during periods of peak demand, thereby maximizing the value of existing emissions-free generation in the province.
We also continue to consult with the Saugeen Ojibway Nation and other Indigenous groups along with other local stakeholders
as we continue to advance this project, which remains subject to a number of conditions and approvals, including approval of
our Board of Directors.
Renewable Energy Request for Information
Through an RFI process in 2021, we announced that we were seeking to identify potential contracts and/or investment
opportunities in up to 620 MW of wind energy projects, 300 MW of solar projects and 100 MW of energy storage projects to meet
the electricity needs of the U.S. portion of the Keystone Pipeline System assets. We also identified meaningful origination
opportunities to supply renewable energy products and services to industrial and oil and gas sectors proximate to our in-corridor
demand. We received a significant number of responses to our RFI and are currently evaluating proposals and expect to finalize
contracts during the first half of 2022.
70 | TC Energy Management's discussion and analysis 2021
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 $)
Bruce Power1
Canadian Power2
Natural Gas Storage and other
Comparable EBITDA
Depreciation and amortization
Comparable EBIT
Specific items:
Gain/(loss) on sale of Ontario natural gas-fired power plants
Gain on sale of Coolidge generating station
U.S. Northeast power marketing contracts
Risk management activities
Segmented earnings
2021
2020
2019
411
253
19
683
(78)
605
17
—
—
6
628
439
213
25
677
(67)
610
(414)
—
—
(15)
181
527
285
20
832
(95)
737
(279)
68
(8)
(63)
455
1
2
Includes our share of equity income from Bruce Power.
Includes our Ontario natural gas-fired power plants until sold in April 2020 and Coolidge generating station until sold in May 2019.
Power and Storage segmented earnings increased by $447 million in 2021 compared to 2020 and decreased by $274 million in
2020 compared to 2019 and included the following specific items which have been excluded from our calculation of comparable
EBIT and comparable earnings:
• a $17 million pre-tax recovery of certain costs from the IESO in 2021 associated with the Ontario natural gas-fired power plants
sold in April 2020 (pre-tax loss 2020 – $414 million; 2019 – $279 million)
• 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
• unrealized gains and 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 increased by $6 million in 2021 compared to 2020 primarily due to the net effect of:
• increased Canadian Power earnings primarily due to higher realized margins in 2021, contributions from trading activities and
a full of year of earnings from our MacKay River cogeneration facility following its return to service in May 2020, partially offset
by the sale of our Ontario natural gas-fired power plants in April 2020
• decreased Bruce Power contribution as a result of increased operating expenses and lower volumes resulting from greater
planned outage days, partially offset by higher realized prices and gains on funds invested for post-retirement benefits as well
as lower financial charges. Additional financial and operating information on Bruce Power is provided below
• decreased Natural Gas Storage and other earnings as a result of increased business development activities across the segment,
partially offset by higher realized Alberta natural gas storage spreads in 2021.
TC Energy Management's discussion and analysis 2021 | 71
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 in January 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 in April 2020. In
addition, we sold our Coolidge generating station in May 2019.
Depreciation and amortization
Depreciation and amortization increased by $11 million in 2021 compared to 2020 primarily due to incremental TC Turbines
depreciation following the November 2020 acquisition of the remaining 50 per cent ownership interest as well as other
adjustments in 2020. Depreciation was $28 million lower in 2020 compared to 2019 primarily due to the cessation of
depreciation on our Halton Hills power plant in July 2019.
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:
Revenues1
Operating expenses
Depreciation and other
Comparable EBITDA and EBIT2
Bruce Power – other information
Plant availability3,4
Planned outage days4
Unplanned outage days
Sales volumes (GWh)2
Realized power price per MWh5
2021
2020
2019
1,656
(922)
(323)
411
86%
321
22
20,542
$80
1,681
(884)
(358)
439
88%
276
36
20,956
$80
1,746
(883)
(336)
527
84%
393
58
22,669
$76
1
2
3
4
5
Net of amounts recorded to reflect operating cost efficiencies shared with the IESO.
Represents our 48.4 per cent ownership interest in Bruce Power. Sales volumes include deemed generation and Unit 6 output until January 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.
Plant availability in 2021, excluding the Unit 6 MCR, was 86 per cent as planned maintenance on Units 1 and 3 was completed in
2021 while planned maintenance on Unit 7 commenced in fourth quarter 2021 and returned to service on January 23, 2022.
Excluding the Unit 6 MCR which commenced in January 2020, plant availability in 2020 was 88 per cent as planned maintenance
was completed on Units 3, 4, 5 and 8. Plant availability in 2019 was 84 per cent as planned maintenance was completed on
Units 2, 3, 5 and 7.
72 | TC Energy Management's discussion and analysis 2021
OUTLOOK
Comparable EBITDA
Power and Storage comparable EBITDA in 2022 is expected to be generally consistent with 2021. Bruce Power equity income in
2022 is expected to be similar to 2021 as the impact of its contract price increase for the Unit 3 MCR program is expected to be
offset by greater non-MCR planned outage days and operating costs in 2022. Planned maintenance is currently scheduled for
Units 1 to 5 in the first half of 2022 and for Unit 4 in the second half of 2022 while the planned outage on Unit 7, which began in
fourth quarter 2021, was completed on January 23, 2022. The average 2022 plant availability percentage, excluding Unit 6 which
continues its MCR program, is expected to be in the low-80 per cent range.
Capital spending
We invested $0.8 billion in 2021 for our share of Bruce Power's life extension and other maintenance capital projects across the
segment and expect to invest approximately $0.9 billion in 2022.
BUSINESS RISKS
The following are risks specific to our Power and Storage business. Refer to page 93 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. As the contracts on these assets expire 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.
Regulatory
We operate in both regulated and deregulated power markets in both Canada and the United States. These markets are subject
to various federal, provincial and state 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 affect the price of power. 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.
TC Energy Management's discussion and analysis 2021 | 73
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.
Traditional and non-traditional players are entering the growing low-carbon economy in North America and, as a result, we face
competition in building low-carbon platforms with energy and financial options to provide customer-driven solutions for energy
transition.
74 | TC Energy Management's discussion and analysis 2021
Corporate
COVID-19
Amid the ongoing adaptations and restrictions in place as a result of the COVID-19 pandemic, we continue to effectively operate
our assets, conduct commercial activities and execute on projects with a focus on health, safety and reliability. While it remains
premature to ascertain any long-term impact that COVID-19 may have on our capital program, we continue to observe some
slowdown on certain of our construction activities and capital expenditures. In addition, supply chain impacts are manifesting
with rising costs for certain commodities and labour shortages in some areas which can cause cost increases and slower progress
than anticipated. Further details for capital projects more significantly impacted by COVID-19 are described within the different
business segment sections.
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 somewhat 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 and the Financial risks sections.
SIGNIFICANT EVENTS
Alberta Carbon Grid
On June 17, 2021, we announced a partnership with Pembina Pipeline Corporation to jointly develop a world-scale carbon
transportation and sequestration system which, when fully constructed, will be capable of transporting more than 20 million
tonnes of carbon dioxide annually, thereby providing opportunities to retrofit existing assets and reduce our carbon footprint.
By leveraging existing pipelines and a newly developed sequestration hub, the ACG is expected to provide an infrastructure
platform for Alberta-based industries to manage their emissions and contribute to a lower-carbon economy. Designed to be an
open-access system, the ACG would connect the Fort McMurray, Alberta Industrial Heartland and Drayton Valley regions to key
sequestration locations and delivery points across the province. We are also pursuing opportunities to leverage our existing
systems in support of hydrogen production and transportation.
Irving Oil Decarbonization
On August 12, 2021, we signed an MOU to explore the joint development of a series of proposed energy projects focused on
reducing GHG emissions and creating new economic opportunities in New Brunswick and Atlantic Canada. Together with
Irving Oil, we have identified a series of potential projects focused on decarbonizing existing assets and deploying emerging
technologies to reduce overall emissions over the medium and long term. The partnership’s initial focus will consider a suite of
upgrade projects at Irving Oil’s refinery in Saint John, New Brunswick, with the goal of significantly reducing emissions through
the production and use of low-carbon power generation.
Hydrogen Hubs
We have entered into two JDAs, to support customer-driven hydrogen production for long-haul transportation, power
generation, large industrials and heating customers across the United States and Canada. The first opportunity is a partnership
with Nikola Corporation, a designer and manufacturer of zero-emission battery-electric and hydrogen-electric vehicles and
related equipment, where Nikola will be a long-term anchor customer for hydrogen production infrastructure supporting
hydrogen fueled zero-emission heavy-duty trucks. The JDA with Nikola supports co-development of large-scale green and blue
hydrogen production hubs, utilizing our power and natural gas infrastructure.
Our second customer-driven opportunity is a partnership with Hyzon Motors, a leader in fuel cell electric mobility for commercial
vehicles, to develop hydrogen production facilities focused on zero-to-negative carbon intensity hydrogen from renewable
natural gas, biogas and other sustainable sources. The facilities will be located close to demand, supporting Hyzon’s
back-to-base vehicle deployments. Our significant pipeline, storage and power assets can potentially be leveraged to lower the
cost and increase the speed of development of these hubs. This may include exploring the integration of pipeline assets to
enable hydrogen distribution and storage via pipeline and/or to deliver carbon dioxide to permanent sequestration sites to
decarbonize the hydrogen production process.
TC Energy Management's discussion and analysis 2021 | 75
Voluntary Retirement Program
In mid-2021, we offered a one-time VRP to eligible employees. Participants in the program retired by December 31, 2021 and
received a transition payment in addition to existing retirement benefits. In 2021, we expensed a total of $81 million before
income tax, mainly related to the VRP transition payments, which was included in Plant operating costs and other. Of the total
program costs, $63 million was excluded from comparable earnings and $18 million was recorded in Revenues related to costs
that are recoverable through regulatory and tolling structures on a flow-through basis.
Acquisition of Common Units of TC PipeLines, LP
On March 3, 2021, we completed the acquisition of all of the outstanding common units of TC PipeLines, LP not beneficially
owned by TC Energy, resulting in TC PipeLines, LP becoming an indirect, wholly-owned subsidiary of TC Energy. Upon close of the
transaction and in accordance with the acquisition terms, TC PipeLines, LP common unitholders received 0.70 common shares of
TC Energy for each issued and outstanding publicly-held TC PipeLines, LP common unit resulting in the issuance of 38 million
TC Energy common shares valued at approximately $2.1 billion, net of transaction costs. Refer to Note 22, Common shares, of our
2021 Consolidated financial statements for additional information.
FINANCIAL RESULTS
The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to Corporate segmented
(losses)/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 $)
Comparable EBITDA and EBIT
Specific items:
Voluntary Retirement Program
Foreign exchange gains/(losses) – inter-affiliate loans1
Segmented (losses)/earnings
2021
(24)
(63)
41
(46)
2020
(16)
—
86
70
2019
(17)
—
(53)
(70)
1
Reported in Income from equity investments in the Consolidated statement of income.
Corporate segmented losses in 2021 increased by $116 million from segmented earnings of $70 million in 2020 to segmented
losses of $46 million in 2021. Segmented earnings increased by $140 million in 2020 compared to segmented losses of $70 million
in 2019.
Corporate segmented (losses)/earnings included pre-tax costs for the VRP offered in mid-2021 as well as 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 foreign exchange gains and losses are recorded in Income from equity investments in the Corporate segment 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. Refer to the
Corporate – Significant events section for additional information on the VRP and Other Information – Related party transactions
section for additional information on our peso-denominated inter-affiliate loans.
Comparable EBITDA and EBIT for Corporate decreased by $8 million in 2021 compared to 2020. The decrease was primarily due to
a U.S. capital tax adjustment recorded in 2020. Comparable EBITDA for Corporate in 2020 was consistent with 2019.
76 | TC Energy Management's discussion and analysis 2021
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
2021
2020
2019
(712)
(1,259)
(320)
(2,291)
(85)
22
(685)
(1,302)
(446)
(2,433)
(89)
294
(598)
(1,326)
(434)
(2,358)
(161)
186
(2,333)
—
(2,333)
Interest expense included in comparable earnings
(2,354)
(2,228)
Specific item:
Keystone XL preservation and other
Interest expense
(6)
(2,360)
—
(2,228)
Interest expense in 2021 increased by $132 million compared to 2020 and included $6 million related to the Keystone XL
project-level credit facility for the period following the revocation of the Presidential Permit for the Keystone XL pipeline project.
This has been removed from our calculation of interest expense included in comparable earnings.
Interest expense included in comparable earnings in 2021 increased by $126 million compared to 2020 primarily due to the
net effect of:
• lower capitalized interest due to its cessation for the Keystone XL pipeline project following the revocation of the Presidential
Permit on January 20, 2021, the change to equity accounting for our Coastal GasLink investment upon the sale of a 65 per cent
interest in Coastal GasLink LP in 2020 and the completion of the Napanee power plant in 2020
• the foreign exchange impact from a weaker U.S. dollar on translation of U.S. dollar-denominated interest
• lower interest rates on reduced levels of short-term borrowings
• long-term debt and junior subordinated note issuances, net of maturities. Refer to the Financial condition section for
additional information on long-term debt and junior subordinated notes.
Interest expense included in comparable earnings in 2020 decreased by $105 million compared to 2019 mainly 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 in May 2020, partially offset by lower capitalized interest due to the completion of
Napanee construction in 2020. The increase of capitalized interest for Keystone XL was 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 were
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
• foreign exchange impact from a stronger U.S. dollar on translation of U.S. dollar-denominated interest.
TC Energy Management's discussion and analysis 2021 | 77
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
2021
2020
2019
140
101
26
267
106
182
61
349
203
205
67
475
AFUDC decreased by $82 million in 2021 compared to 2020. The increase in Canadian dollar-denominated AFUDC is primarily
related to a higher balance of NGTL System expansion projects under construction. The decrease in U.S. dollar-denominated
AFUDC is mainly the result of the suspension of recording AFUDC on the Villa de Reyes project effective January 1, 2021 due to
ongoing delays and the Columbia Gas BXP project which went into service on January 1, 2021, partially offset by the impact of
increased capital expenditures on our U.S. natural gas pipeline projects.
AFUDC decreased by $126 million in 2020 compared to 2019. The lower Canadian dollar-denominated AFUDC in 2020 was mainly
due to NGTL System expansion projects placed in service. The decrease in U.S. dollar-denominated AFUDC was primarily the
result of the suspension of recording AFUDC on Tula, effective January 1, 2020, due to ongoing construction delays, partially
offset by continuing construction of the Villa de Reyes project.
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
2021
444
(41)
(203)
200
2020
173
(86)
126
213
2019
162
53
245
460
Interest income and other decreased by $13 million in 2021 compared to 2020 and by $247 million in 2020 compared to 2019
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 and 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.
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 are reflected in Income from equity investments in the
Corporate and Mexico Natural Gas Pipelines segments, respectively. The foreign exchange gains and losses on these
inter-affiliate loans are removed from comparable earnings while the interest income and interest expense are included in
comparable earnings with all amounts offsetting and resulting in no impact on net income. Refer to Other Information – Related
party transactions for additional information.
Interest income and other included in comparable earnings increased by $271 million in 2021 compared to 2020 primarily due to
the net effect of:
• realized gains in 2021 compared to realized losses in 2020 on derivatives used to manage our net exposure to foreign exchange
rate fluctuations on U.S. dollar-denominated income
• lower interest income in 2021 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.
78 | TC Energy Management's discussion and analysis 2021
Interest income and other included in comparable earnings increased by $11 million in 2020 compared to 2019 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.
Income tax expense
year ended December 31
(millions of $)
Income tax expense included in comparable earnings
Specific items:
Keystone XL asset impairment charge and other
Voluntary Retirement Program
Keystone XL preservation and other
Sale of Northern Courier
Sale of Ontario natural gas-fired power plants
Income tax valuation allowance releases
Partial sale of Coastal GasLink LP
Sale of Columbia Midstream assets
Alberta corporate income tax rate reduction
U.S. Northeast power marketing contracts
Sale of Coolidge generating station
Risk management activities
Income tax expense
2021
(833)
641
15
12
6
(10)
—
—
—
—
—
—
49
(120)
2020
(654)
—
—
—
—
131
299
38
18
—
—
—
(26)
(194)
2019
(898)
—
—
—
46
85
195
—
(173)
32
2
(14)
(29)
(754)
Income tax expense in 2021 decreased by $74 million compared to 2020 and decreased by $560 million in 2020 compared to
2019 and included the specific items noted below which have been removed from our calculation of Income tax expense
included in comparable earnings.
In addition, some of the income tax impacts noted in the table above relate to specific items referenced elsewhere in this MD&A.
In 2021, all specific items are discussed in their respective business segment disclosure as they did not relate to income tax
specific items.
Specific items 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 pipeline
project
• an $18 million income tax recovery related to state income taxes on the sale of certain Columbia Midstream assets.
Specific items in 2019:
• an income tax valuation allowance release of $195 million related to certain prior years' U.S. income 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 tax balances attributable to our Canadian businesses not subject to RRA due to
an Alberta corporate income tax rate reduction enacted in June 2019.
These items were removed from Income tax expense included in comparable earnings in addition to the income tax impacts of
the specific items referenced elsewhere in this MD&A.
TC Energy Management's discussion and analysis 2021 | 79
Income tax expense included in comparable earnings in 2021 increased by $179 million compared to 2020 primarily due to higher
flow-through income taxes on Canadian rate-regulated pipelines, increased earnings subject to income tax and the impact of
Mexico inflationary adjustments, partially offset by higher foreign tax rate differentials.
Income tax expense included in comparable earnings in 2020 decreased by $244 million compared to 2019 primarily due to lower
flow-through income taxes on Canadian rate-regulated pipelines and higher foreign tax rate differentials.
Net income attributable to non-controlling interests
year ended December 31
(millions of $)
Net income attributable to non-controlling interests
2021
(91)
2020
(297)
2019
(293)
Net income attributable to non-controlling interests decreased by $206 million in 2021 compared to 2020 primarily as a result of
the March 3, 2021 acquisition of all outstanding common units of TC PipeLines, LP not beneficially owned by TC Energy.
Subsequent to the acquisition, TC PipeLines, LP became an indirect, wholly-owned subsidiary of TC Energy. Refer to the
Corporate – Significant events section and Note 21, Non-controlling interests, of our 2021 Consolidated financial statements for
additional information.
In 2020, Net income attributable to non-controlling interests increased by $4 million 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.
Preferred share dividends
year ended December 31
(millions of $)
Preferred share dividends
2021
(140)
2020
(159)
2019
(164)
Preferred share dividends decreased by $19 million in 2021 compared to 2020 primarily due to the redemption of all issued and
outstanding Series 13 preferred shares on May 31, 2021. Preferred share dividends of $159 million in 2020 were generally
consistent with 2019.
80 | TC Energy Management's discussion and analysis 2021
Financial condition
We strive to maintain financial strength 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 Annual
Information Form 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.
Balance sheet analysis
At December 31, 2021, our current assets totaled $7.4 billion and current liabilities amounted to $13.0 billion, leaving us with a
working capital deficit of $5.6 billion compared to $6.8 billion at December 31, 2020. 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 $5.0 billion of short-term borrowing capacity remains
available, net of $5.0 billion backstopping outstanding commercial paper balances. We also have arrangements in place for a
further $2.4 billion of demand credit facilities of which $1.2 billion remains available as of December 31, 2021
• our access to capital markets, including through securities issuances, incremental credit facilities, portfolio management
activities, DRP and Corporate ATM programs, if deemed appropriate.
Our total assets at December 31, 2021 were $104.2 billion compared to $100.3 billion at December 31, 2020 with the increase
primarily reflecting our 2021 capital spending program, working capital and equity investments, partially offset by depreciation,
the Keystone XL asset impairment and the impact of a weaker U.S. dollar at December 31, 2021 compared to December 31, 2020
on translation of our U.S. dollar-denominated assets.
At December 31, 2021 our total liabilities were $70.8 billion, compared to $66.8 billion at December 31, 2020 due to the net
effect of movements in debt, working capital and foreign exchange rates as discussed above.
Our equity at December 31, 2021 was $33.4 billion, consistent with $33.1 billion at December 31, 2020.
Consolidated capital structure
The following table summarizes the components of our capital structure.
at December 31
(millions of $, unless otherwise noted)
Notes payable
Redeemable non-controlling interest1
Long-term debt, including current portion
Cash and cash equivalents
Junior subordinated notes
Redeemable non-controlling interest
Preferred shares
Common shareholders' equity
Non-controlling interests
1
Classified in Current liabilities on the Consolidated balance sheet.
2021
5,166
—
38,661
(673)
43,154
8,939
—
3,487
29,784
125
85,489
Per cent
of total
6
—
45
(1)
50
11
—
4
35
—
100
2020
4,176
633
36,885
(1,530)
40,164
8,498
393
3,980
27,418
1,682
82,135
Per cent
of total
5
1
45
(2)
49
10
1
5
33
2
100
TC Energy Management's discussion and analysis 2021 | 81
At February 9, 2022, we had unused capacity of $3.0 billion, $1.5 billion, US$4.0 billion and $1.5 billion under our TC Energy
equity, TCPL Canadian and U.S. debt and TC Trust hybrid 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, 2021.
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
(Decrease)/increase in cash and cash equivalents
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 Keystone XL asset impairment charge,
preservation and other
Keystone XL preservation and other
Voluntary Retirement Program
Current income tax recovery on Voluntary Retirement Program
Current income tax expense on sale of Columbia Midstream assets
U.S. Northeast power marketing contracts
2021
6,890
(7,712)
(88)
(910)
53
(857)
2021
6,890
287
7,177
131
49
63
(14)
—
—
2020
7,058
(6,052)
(800)
206
(19)
187
2020
7,058
327
7,385
—
—
—
—
—
—
Comparable funds generated from operations
7,406
7,385
2019
7,082
(6,872)
693
903
(6)
897
2019
7,082
(293)
6,789
—
—
—
—
320
8
7,117
Net cash provided by operations
Net cash provided by operations decreased by $168 million in 2021 compared to 2020 primarily due to lower funds generated
from operations, partially offset by the amount and timing of working capital changes.
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.
82 | TC Energy Management's discussion and analysis 2021
Comparable funds generated from operations
Comparable funds generated from operations, a non-GAAP measure, helps us assess the cash generating ability of our businesses
by excluding the timing effects of working capital changes as well as the cash impact of our specific items.
Comparable funds generated from operations increased by $21 million in 2021 compared to 2020 primarily due to higher
comparable earnings, including realized gains in 2021 compared to realized losses in 2020 on derivatives used to manage our net
exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income. This was partially offset by fees collected in
2020 associated with the construction of the Sur de Texas pipeline, as well as lower distributions from the operating activities of
our equity investments in 2021.
Comparable funds generated from operations increased by $268 million in 2020 compared to 2019 primarily due to 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.
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
Loan to affiliate
Acquisition
Other distributions from equity investments
Payment for unredeemed shares of Columbia Pipeline Group, Inc.
Deferred amounts and other
Net cash used in investing activities
2021
2020
2019
(5,924)
—
(1,210)
(7,134)
35
(239)
—
73
—
(447)
(7,712)
(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)
Net cash used in investing activities increased from $6.1 billion in 2020 to $7.7 billion in 2021 largely as a result of proceeds
received from the sale of assets in 2020, as discussed below, as well as higher contributions to equity investments and a loan
issued to one of our affiliates in 2021, partially offset by lower capital spending in 2021.
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. (Columbia) shareholders in 2019. This was partially offset by
the cost to acquire the remaining 50 per cent ownership interest in TC Turbines.
TC Energy Management's discussion and analysis 2021 | 83
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
2021
2,737
2,820
129
571
842
35
7,134
2020
3,608
2,785
173
1,442
834
58
8,900
2019
3,906
2,516
357
954
1,019
32
8,784
1
Capital spending includes Capital expenditures, Capital projects in development and Contributions to equity investments. Refer to Note 4, Segmented
information, of our 2021 Consolidated financial statements for the financial statement line items that comprise total capital spending.
Capital expenditures
Capital expenditures in 2021 were incurred primarily for the expansion of the NGTL System, ANR and Columbia Gas projects, as
well as maintenance capital expenditures. Lower capital spending in 2021 compared to 2020 reflected reduced spending on
Columbia Gas projects, the sale of a 65 per cent equity interest in and subsequent equity accounting for Coastal GasLink LP in
second quarter 2020, along with the termination of the Keystone XL pipeline project following the January 20, 2021 revocation
of the Presidential Permit, partially offset by higher capital spending on ANR.
Capital projects in development
Costs incurred during 2020 and 2019 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 2021 compared to 2020 mainly due to higher investments in Bruce Power and
Iroquois.
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 in 2019 include our proportionate share of Sur de Texas debt financing.
Proceeds from sales of assets
In 2021, we completed the sale of our remaining 15 per cent equity interest in Northern Courier for gross proceeds of $35 million.
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 initial draw by Coastal
GasLink LP on the project-level financing which preceded the equity sale.
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 the Northern
Courier debt issuance which preceded the equity sale.
84 | TC Energy Management's discussion and analysis 2021
Acquisition
On November 13, 2020, we acquired the remaining 50 per cent ownership interest in TC Turbines for cash consideration of
US$67 million.
Other distributions from equity investments
Other distributions from equity investments relate to our proportionate share of the Sur de Texas debt repayments in 2021 along
with 2019 distributions received from Bruce Power and Northern Border financings undertaken to fund their respective capital
programs and to also make distributions to their partners. In 2021, we received distributions of $73 million from Sur de Texas in
relation to the repayment on our 60 per cent proportionate share of long-term debt financing to the joint venture. In 2019, we
received distributions of $120 million from Bruce Power in connection with their issuance of senior notes in the capital markets,
as well as $66 million 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 issued/(repaid), 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
Redeemable non-controlling interest repurchased
Contributions from redeemable non-controlling interest
Dividends and distributions paid
Common shares issued, net of issue costs
Preferred shares redeemed
Acquisition of TC PipeLines, LP transaction costs
Net cash (used in)/provided by financing activities
2021
1,003
10,730
(7,758)
495
(10)
(633)
—
(3,548)
148
(500)
(15)
(88)
2020
(220)
5,770
(3,977)
—
(130)
—
1,033
(3,367)
91
—
—
(800)
2019
1,656
3,024
(3,502)
1,436
—
—
—
(2,174)
253
—
—
693
Net cash used in financing activities decreased by $0.7 billion in 2021 compared to 2020 primarily due to higher net issuances of
long-term debt and notes payable along with the 2021 issuance of junior subordinated notes, partially offset by contributions
received in 2020 in support of Keystone XL construction in the form of a redeemable non-controlling interest as well as the
2021 subsequent repurchase of the redeemable non-controlling interest in addition to the preferred shares redemption.
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.
The principal transactions reflected in our financing activities are discussed in further detail below.
TC Energy Management's discussion and analysis 2021 | 85
Long-term debt issued
The following table outlines significant long-term debt issuances in 2021:
(millions of Canadian $, unless otherwise noted)
Company
Issue date
Type
Maturity date
Amount
Interest rate
TRANSCANADA PIPELINES LIMITED
October 2021
Senior Unsecured Notes
October 2024
October 2021
Senior Unsecured Notes
October 2031
June 2021
Medium Term Notes
June 2021
Medium Term Notes
June 2024
June 2031
June 2021
Medium Term Notes
September 2047
US 1,250
US 1,000
750
500
250
1.00%
2.50%
Floating
2.97%
4.33%
Various
Project-Level Credit Facility
June 2021
US 849
Floating
January 2021
Unsecured Term Loan
June 2022
US 4,040
Floating
KEYSTONE XL SUBSIDIARIES1
COLUMBIA PIPELINE GROUP, INC.2
1
2
On January 4, 2021, we established a US$4.1 billion project-level credit facility to support the construction of the Keystone XL pipeline, which was fully
guaranteed by the Government of Alberta and non-recourse to TC Energy. The availability of this credit facility was subsequently reduced to US$1.6 billion and
all amounts outstanding were fully repaid by the Government of Alberta in June 2021.
In December 2020, Columbia entered into a US$4.2 billion Unsecured Term Loan agreement. In January 2021, US$4.0 billion was drawn on the Unsecured Term
Loan and the total availability under the loan agreement was reduced accordingly. The loan was fully repaid and retired in December 2021.
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.
Long-term debt retired/repaid
The following table outlines significant long-term debt repaid in 2021:
(millions of Canadian $, unless otherwise noted)
Company
TRANSCANADA PIPELINES LIMITED
COLUMBIA PIPELINE GROUP, INC.
TC PIPELINES, LP
ANR PIPELINE COMPANY
KEYSTONE XL SUBSIDIARIES1
Retirement/
repayment date
Type
Amount
Interest rate
November 2021
Medium Term Notes
January 2021
Debentures
500
US 400
3.65%
9.875%
December 2021
Unsecured Term Loan
US 4,040
Floating
November 2021
Unsecured Term Loan
March 2021
Senior Unsecured Notes
US 450
US 350
Floating
4.65%
November 2021
Senior Unsecured Notes
US 300
9.625%
June 2021
Project-Level Credit Facility
US 849
Floating
1
In June 2021, in accordance with the terms of the guarantee, the Government of Alberta repaid the US$849 million outstanding balance under the Keystone XL
project-level credit facility bearing interest at a floating rate, and it was subsequently terminated, resulting in no cash impact to TC Energy.
On March 4, 2021, our subsidiary, TC PipeLines, LP, terminated our US$500 million Unsecured Loan Facility bearing interest at a
floating rate on which no amount was outstanding.
86 | TC Energy Management's discussion and analysis 2021
Junior subordinated notes issued
In March 2021, TransCanada Trust (the Trust) issued $500 million of Trust Notes – Series 2021-A to investors with a fixed interest
rate of 4.20 per cent per annum for the first 10 years and resetting on the 10th anniversary and every five years thereafter. All of
the proceeds of the issuance by the Trust were loaned to TCPL for $500 million of junior subordinated notes of TCPL at an initial
fixed rate of 4.45 per cent per annum, including a 0.25 per cent administration charge. The rate on the junior subordinated
notes of TCPL will reset every five years commencing March 2031 until March 2051 to the then Five-Year Government of Canada
Yield, as defined in the document governing the subordinated notes, plus 3.316 per cent per annum; from March 2051 until
March 2081, the interest rate will reset to the then Five-Year Government of Canada Yield plus 4.066 per cent per annum. The
junior subordinated notes are callable at TCPL's option at any time from December 4, 2030 to March 4, 2031 and on each interest
payment and reset date thereafter 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.
For more information about long-term debt and junior subordinated notes issued and long-term debt repaid in 2021, 2020
and 2019, refer to the notes to our 2021 Consolidated financial statements.
Redeemable non-controlling interest repurchased
On January 8, 2021, we exercised our call right in accordance with contractual terms and paid US$497 million to repurchase the
Government of Alberta Class A Interests which were classified as Current liabilities on the Consolidated balance sheet at
December 31, 2020. This transaction was funded by draws on the Keystone XL project-level credit facility.
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. Commencing with the dividends declared October 31, 2019,
common shares purchased under TC Energy’s DRP are acquired on the open market at 100 per cent of the weighted average
purchase price. From January 1, 2019 to October 31, 2019, common shares under the DRP were issued from treasury at a discount
of two per cent to market prices over a specified period.
TC Energy Corporate ATM program
In December 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 program in 2021 or 2020.
TC Energy Management's discussion and analysis 2021 | 87
Share information
as at February 9, 2022
Common Shares
issued and outstanding
981 million
Preferred Shares
issued and outstanding
convertible to
Series 1
Series 2
Series 3
Series 4
Series 5
Series 6
Series 7
Series 9
Series 11
Series 15
Options to buy common shares
14.6 million
7.4 million
10 million
4 million
12.1 million
1.9 million
24 million
18 million
10 million
40 million
outstanding
8 million
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 16 preferred shares
exercisable
4 million
On May 31, 2021, we redeemed all of the 20 million issued and outstanding Series 13 preferred shares at a redemption price of
$25.00 per share and paid the final quarterly dividend of $0.34375 per Series 13 preferred share for the period up to but
excluding May 31, 2021 as previously declared on May 6, 2021.
On March 3, 2021, we issued 37,955,093 TC Energy common shares to acquire all the outstanding common units of
TC PipeLines, LP, not beneficially owned by TC Energy, valued at approximately $2.1 billion, net of transaction costs. Refer to the
Corporate – Significant events section for additional information on the acquisition.
On February 1, 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.
For more information on preferred shares refer to the notes to our 2021 Consolidated financial statements.
88 | TC Energy Management's discussion and analysis 2021
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
2021
2020
2019
$3.48
$0.86975
$0.50997
$0.4235
$0.34997
$0.48725
$0.41622
$0.97575
$0.9405
$0.83775
$0.34375
$1.225
$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
On February 14, 2022, we increased the quarterly dividend on our outstanding common shares by 3.4 per cent to $0.90 per
common share for the quarter ending March 31, 2022 which equates to an annual dividend of $3.60 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 9, 2022, we had a total of $12.4 billion of committed revolving and demand credit facilities, including:
(billions of Canadian $, unless otherwise noted)
Borrower
Description
Matures
Total facilities
Unused
capacity1
Committed, syndicated, revolving, extendible, senior unsecured credit facilities:
TCPL
Supports TCPL's Canadian dollar commercial paper
program and for general corporate purposes
TCPL / TCPL USA /
Columbia / TransCanada
American Investments Ltd.
Supports TCPL's and TCPL USA's U.S. dollar commercial
paper programs and for general corporate purposes of
the borrowers, guaranteed by TCPL
TCPL / TCPL USA /
Columbia / TransCanada
American Investments Ltd.
For general corporate purposes of the borrowers,
guaranteed by TCPL
December 2026
3.0
0.8
December 2022
US 4.5
US 1.7
December 2024
US 1.0
US 1.0
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
Demand
2.1 2
1.0 2
MXN 5.0 2
MXN 2.6 2
1
2
Unused capacity is net of commercial paper outstanding and facility draws.
Or the U.S. dollar equivalent.
TC Energy Management's discussion and analysis 2021 | 89
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, 2021
(millions of $)
Notes payable
Long-term debt and junior subordinated notes1
Operating leases2
Purchase obligations and other
Total
< 1 year
1 - 3 years
4 - 5 years
> 5 years
5,166
47,928
554
4,625
58,273
5,166
1,320
73
2,211
8,770
—
4,480
136
773
5,389
—
4,476
129
432
—
37,652
216
1,209
5,037
39,077
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 $5.2 billion at the end of 2021 compared to $4.2 billion at the end of 2020.
Long-term debt and junior subordinated notes
At December 31, 2021, we had $38.7 billion of long-term debt and $8.9 billion of junior subordinated notes outstanding
compared to $36.9 billion of long-term debt and $8.5 billion of junior subordinated notes at December 31, 2020.
We attempt to ladder the maturity profile of our debt. The weighted-average maturity of our junior subordinated notes and
long-term debt, excluding call features is approximately 20 years.
Interest payments
At December 31, 2021, scheduled interest payments related to our long-term debt and junior subordinated notes were
as follows:
at December 31, 2021
(millions of $)
Long-term debt
Junior subordinated notes
Total
< 1 year
1 - 3 years
4 - 5 years
> 5 years
23,278
21,658
44,936
1,777
461
2,238
3,384
922
4,306
3,028
916
3,944
15,089
19,359
34,448
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.
90 | TC Energy Management's discussion and analysis 2021
Payments due (by period)
at December 31, 2021
(millions of $)
Canadian Natural Gas Pipelines
Transportation by others1
Capital spending2
U.S. Natural Gas Pipelines
Transportation by others1
Capital spending2
Mexico Natural Gas Pipelines
Capital spending2
Liquids Pipelines
Capital spending2
Other
Power and Storage
Capital spending2
Other3
Corporate
Other
Capital spending2
Total
< 1 year
1 - 3 years
4 - 5 years
> 5 years
1,829
1,472
619
130
102
57
9
65
50
160
1,432
128
124
31
56
3
48
10
278
14
4,625
205
14
2,211
327
37
219
6
71
1
6
16
21
69
—
773
308
3
97
—
—
—
—
1
19
4
—
432
1,034
—
175
—
—
—
—
—
—
—
—
1,209
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 approximately $24 billion of secured projects, as well as our projects under development,
which are subject to key corporate and 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 2021 | 91
GUARANTEES
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 2022.
At December 31, 2021, our share of potential exposure under the Sur de Texas pipeline guarantees was estimated to be
$93 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, 2021, 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, 2021 to be approximately $80 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 made funding contributions of $105 million to our defined benefit pension plans, $8 million for other post-retirement
benefit plans and $58 million for the savings plan and defined contribution plans. We also provided an additional $20 million
letter of credit to the Canadian defined benefit plan for funding of solvency requirements.
Considering current market conditions and the reduction to the number of active plan members due to the VRP, we expect 2022
required funding levels to be lower than 2021 levels, although actuarial valuations for determining 2022 funding of our pension
and other post-retirement benefit plans as at January 1, 2022 will be carried out in mid-2022. We currently expect 2022 funding
contributions of approximately $76 million for the defined benefit pension plans, approximately $7 million for other
post-retirement benefit plans and approximately $55 million for the savings plans and defined contribution pension plans. In
addition, we expect to provide an additional estimated $20 million letter of credit to the Canadian defined benefit plan for
solvency funding requirements.
The net benefit cost for our defined benefit and other post-retirement plans decreased to $108 million in 2021 from $114 million
in 2020 primarily due to the impact of a pension curtailment and settlement related to the VRP.
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.
92 | TC Energy Management's discussion and analysis 2021
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) program that identifies enterprise risks, including ESG-related risks, that could materially impact the
achievement of our strategic objectives.
Our Board of Directors retains general oversight of all enterprise risks, as identified below, and specifically has direct oversight of
reputation and relationships, regulatory uncertainty, capital allocation strategy and execution and capital costs. The Board
reviews the enterprise risk register annually and is informed quarterly on emerging risks and how these risks are being managed
and mitigated in accordance with TC Energy’s risk appetite and tolerances. The Board also participates in detailed presentations
on each enterprise risks identified in the enterprise risk register as required or requested.
Our Board of Directors' Governance Committee oversees the ERM program, ensuring appropriate oversight of our risk
management activities. Other Board committees oversee specific types of risk, including ESG risk, within their mandate. More
specifically:
• 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, including climate change
related risks
• 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. Each identified enterprise risk has an executive leadership team
member as the governance and execution owner who provides an in-depth review for the Board on an annual basis.
Key segment-specific financial, health, safety and environment risks are covered in their respective sections of this MD&A. The
following is a summary of enterprise-wide risks with potential to affect all of our operations. These are being continuously
monitored.
TC Energy Management's discussion and analysis 2021 | 93
Risk and description
Impact
Monitoring and mitigation
Business interruption
Operational risks, including equipment
malfunctions and breakdowns, labour
disputes, pandemic and other
catastrophic events including those
related to climate change, acts of terror,
sabotage and third-party excavations on
our right of way.
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 or fatality,
property and environmental damage.
Climate change
As a leading energy infrastructure
company in North America, our assets
could be impacted by significant
temperature or weather changes and
our business may be impacted by
market risks resulting from emerging
decarbonization policies or shifts in
energy consumption affecting long-term
energy supply and demand trajectories.
Fluctuations in energy supply and
demand, increasing commodity prices or
volatility and output capability. Business
interruption caused by physical changes to
our environment which could result in a
decrease in revenues and increase in
operating costs, legal proceedings or
regulatory actions, or other expenses, all
of which could reduce our earnings.
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 process safety,
incident, emergency and crisis management programs to
ensure TC Energy can effectively respond to operational
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 our risks, but insurance does not cover all
events in all circumstances.
In 2021, we established a dedicated energy transition team
to assess relevant technologies and opportunities to
support business resiliency irrespective of the pace or
direction of energy transition. This team worked cross
functionally to set our enterprise-wide goal of 30 per cent
reduction of GHG emission intensity by 2030 which
positions us to achieve net-zero emissions from our
operations by 2050, using a 2019 baseline year.
We evaluate the resilience of our asset portfolio over a
range of potential energy supply and demand outcomes,
also known as scenario analysis, as part of our strategic
planning process. We monitor climate policy and related
developments through our ERM program to ensure
leadership has visibility to the broader perspective, and that
treatments are applied in a holistic and consistent manner.
Our engineering standards are also regularly reviewed to
ensure assets continue to be designed and operated to
withstand the potential impacts of climate change.
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.
94 | TC Energy Management's discussion and analysis 2021
Risk and description
Impact
Monitoring and mitigation
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 stakeholder
expectations and concerns, including
those related to ESG, can have a
significant impact on our operations and
projects, infrastructure development and
overall reputation. It could also affect our
ability to operate and grow.
Regulatory uncertainty
Our ability to construct and operate
energy infrastructure requires regulatory
approvals and is dependent on evolving
policies and regulations by government
authorities. This includes changes in
regulation that may affect our projects
and operations.
Adverse impacts on competitive
geographic and business positions could
result in the inability to meet our growth
targets through missed or lost organic,
greenfield and brownfield opportunities.
Financial impacts of denied or delayed
projects could include lost development
costs, loss of investor confidence and
potential legal costs from litigation.
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 in 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.
Our core values – safety, responsibility, collaboration,
integrity and innovation – guide us in building and
maintaining 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.
We monitor regulatory and government developments and
decisions to analyze their possible impact on our
businesses. We build scenario analysis into our strategic
outlook and work closely with our rightsholders and
stakeholders in the development and operation of our
assets.
We identify emerging risks and signposts including
customer, regulatory and government decisions as well as
innovative technology development, and report on our
management of these risks quarterly through the ERM
program to the Board. We also use this information to
inform our capital allocation strategy and adapt to
changing market conditions.
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
hearing their feedback and keeping them apprised of
developments in our business and factually communicating
our prospects, risks and challenges as well as ESG-related
updates. We also conduct research around the evolving
ESG preferences of our investors and financial partners
which we consider in our decision making.
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.
TC Energy Management's discussion and analysis 2021 | 95
Risk and description
Impact
Monitoring and mitigation
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.
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, supporting 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.
Health, safety, sustainability and environment
The Board's HSSE Committee oversees operational risk, occupational and process safety, sustainability, 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 also conforms to applicable industry standards and complies with
applicable regulatory requirements. It covers the lifecycle of our assets and follows a continuous improvement cycle organized
into four key areas:
• Plan – risk and regulatory assessment as well as objective and target setting, which includes establishing total recordable case
rate targets while striving for zero incidents plus 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 and assessed by management.
The HSSE Committee reviews performance and operational risk management. It receives updates and reports on:
• overall HSSE corporate governance
• operational performance and preventive maintenance metrics
• asset integrity programs
• environment programs
• significant occupational safety, process safety and asset integrity incidents
• emergency preparedness, incident response and evaluation
• occupational and process safety performance metrics
• biodiversity and land reclamation
• 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 as well as related
voluntary public disclosure such as our Report on Sustainability, Reconciliation Action Plan, ESG Data Sheet and GHG Emissions
Reduction Plan
• our Occupational Health and Hygiene Program, which includes physical and mental health and psychological safety.
96 | TC Energy Management's discussion and analysis 2021
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 into service only after all necessary requirements, both regulatory and internal, have been satisfied.
In 2021, we spent $1.4 billion for pipeline integrity on the natural gas and liquids pipelines we operate, similar to 2020.
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.
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 and Climate change risk discussions 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.
TC Energy Management's discussion and analysis 2021 | 97
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
to environmental policy, legislation and regulation. 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.
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, 2021, accruals related to these obligations totaled $30 million (2020 – $24 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 2021, we incurred $59 million (2020 – $64 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 and, in October 2021, we
published a GHG Emissions Reduction Plan that includes GHG reduction targets in support of global climate goals. 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,
other expenses or capital expenditures to comply with possible new regulations.
98 | TC Energy Management's discussion and analysis 2021
Existing policies
Canadian jurisdictions
• ECCC's methane reduction regulations that detail requirements to reduce methane emissions through operational and capital
modifications came into effect in January 2020. ECCC’s methane reduction regulation aims to reduce the oil and gas sector
emissions by 40 to 45 per cent below 2012 levels by 2025. Alberta, British Columbia and Saskatchewan have drafted their own
methane regulations that take the place of the federal regulation for provincially-regulated assets. 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. 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 currently 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. As a result, our assets across Canada are all subject
to some type of carbon pricing
• new requirements for federally regulated project applications under the Impact Assessment Agency were introduced through
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. The CER published a revision to its Filing Manual to integrate the Strategic Assessment of
Climate Change, which includes a 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. Responses to this requirement are being developed and
provided as part of the project applications on a case by case basis
• British Columbia 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, British Columbia established the CleanBC program which provides
incentive payments or tax rebates for industrial operations that meet an established emission intensity benchmark, and the
CleanBC Industry Fund 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 Technology Innovation and Emissions Reduction (TIER) regulation has been in effect since January 2020. The
TIER regulation requires established industrial facilities with GHG emissions above a certain threshold to reduce their emissions
below an intensity baseline. The TIER system 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
and TQM natural gas pipeline facilities in Québec are also subject to this program and compliance instruments have been or
will be purchased in order to comply with the requirements of this initiative
• On March 29, 2021, the Ontario and Federal governments reached an agreement whereby the Federal OBPS in Ontario will be
replaced on January 1, 2022 by the Ontario Emissions Performance Standards program. Covered facilities are required to meet
the Federal OBPS regulations for the 2020 and 2021 compliance periods. Federal OBPS and the Ontario Emissions Performance
Standards that apply to our Canadian Mainline operations in the province and costs under this program will be recovered in
tolls. At this time, we do not anticipate a material impact to the financial performance of our Ontario natural gas facilities as a
result of the Ontario Emissions Performance Standards program.
TC Energy Management's discussion and analysis 2021 | 99
U.S. jurisdictions
• Federal: On June 30, 2021, a joint Congressional resolution (CRA resolution) disapproving the 2020 policy amendment was
signed into law. The CRA resolution reinstated the 2016 New Source Performance Standards on the transmission and storage
segments. The impact to us from the reinstatement was minimal as we previously made the decision to continue to comply
even though the 2020 policy amendments removed the transmission and storage segment as an applicable source category
• 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 in January 2020, thresholds for leak repair under this
program were reduced. California also has a GHG cap-and-trade program linked with Québec's program through the WCI. All
Tuscarora facilities fall below the threshold requiring participation in the GHG cap-and-trade program
• 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 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.
Mexico jurisdictions
• the General Climate Change Law (LGCC) establishes various public policy instruments, including the National Emissions
Registry and its regulations, which allow for the compilation of information on the emission of compounds and GHGs of the
different productive sectors of the country. The LGCC defines the National Inventory of GHGs and compounds as the document
that contains the estimate of anthropogenic emissions by sources and absorption by sinks in Mexico. This law requires an
annual submission of our emissions
• 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 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 GHG 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 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 are scheduled to 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
• On October 11, 2021, ECCC committed to developing a plan to reduce oil and gas sector methane emissions by at least
75 per cent below 2012 levels by 2030. We will assess the potential implications of any policy and regulatory updates
associated with this announcement through 2022 as more information is made available.
100 | TC Energy Management's discussion and analysis 2021
U.S. jurisdictions
• Federal: In August 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 United States Environmental Protection Agency
(USEPA) 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
• Federal: On November 2, 2021, the USEPA released proposed rulemaking to reduce methane and other harmful air pollutants
from both new and existing sources in the oil and natural gas industry. The methane rule was posted to the federal register on
November 15, 2021 with a public hearing scheduled on November 30, 2021 and the public comment period closing on
January 14, 2022. An additional supplemental proposal was released on November 15,2021 which included supporting
regulator text. The proposed rule for new or modified sources is expected to impact any new projects that begin in 2022 and
beyond. The guidelines for existing emission sources have the potential to impact all of our existing facilities when fully
implemented in the future
• Washington: The state has announced the beginning of the rulemaking process for its cap-and-trade program, which passed
through legislature in 2021. Rulemaking will proceed through 2022 with the program launching in January of 2023. The state is
continuing rulemaking on its Greenhouse Gas Assessment for Projects rule, which would require projects to provide an
estimate of their potential GHG emissions using the environmental assessment methods described in the rule. Rule language
will be proposed in early 2022 and the state will hold public comments and hearings before finalizing later in the year. This
program and associated rules would apply to our assets and projects in the state. They have also begun the process to update
the Washington Commercial Building Code, including language that would limit the use of natural gas in new construction.
This process will continue into 2022
• California: Our assets may be affected by the Governor of California's executive order, issued in September 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. 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.
The state Department of Environmental Quality recommended a final draft of the rule to the state Environmental Quality
Commission (EQC) for a vote at the EQC’s December 2021 meeting. The EQC approved the program which still exempts our
facilities and their emissions
• 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: In August 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.
Changes to environmental remediation regulations – U.S. Jurisdictions
• Federal: On October 22, 2021, the USEPA proposed a rule entitled, Alternate Polychlorinated Biphenyl (PCB) Extraction Methods
and Amendments to PCB Cleanup and Disposal Regulations. The rule addresses a myriad of issues related to laboratory
methodologies, performance-based disposal options for PCB remediation waste and during emergency situations, among
other proposed changes. We are currently reviewing the proposed rule to determine its impact, if any, to our PCB
Management activities but at this time do not believe that it will have a material impact on our business, financial condition
or results of operations.
TC Energy Management's discussion and analysis 2021 | 101
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, internal audit and business
segment 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- 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, cash flows 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 our exposure to market risk resulting from commodity price risk management
activities 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 businesses, we enter into contracts and engage in hedging activities as well as selling and purchasing electricity
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.
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.
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.
102 | TC Energy Management's discussion and analysis 2021
Interest rate risk
We utilize both short- 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 short-term debt including 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 U.S. dollar LIBOR, of
which certain rate settings have ceased to be published at the end of 2021 with full cessation by mid-2023. We have completed
necessary system changes to facilitate the adoption of the proposed standard market reference rates. We have also completed
the analysis of contracts impacted by reference rate reform and contract modifications, if required, will take place prior to the
full cessation date in mid-2023. These changes are not expected to have a material impact on our consolidated financial
statements; however, we will continue to monitor any new developments up to the full cessation date.
Foreign exchange risk
Certain of our businesses generate all or most of their earnings in U.S. dollars and, 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 comparable EBITDA and net
income. Refer to the 2021 Financial highlights – Foreign exchange section for additional information.
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.
We hedge a portion of our net investment in foreign operations (on an after-tax basis) with U.S. dollar-denominated debt,
cross-currency interest rate swaps, foreign exchange forwards and foreign exchange options, as appropriate.
Counterparty credit risk
We have exposure to counterparty credit risk in a number of areas including:
• cash and cash equivalents
• accounts receivable and certain contractual recoveries
• available-for-sale assets
• 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 and communication with those counterparties experiencing greater
financial pressures.
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, 2021 and 2020, we had no significant credit losses, no
significant credit risk concentrations and no significant amounts past due or impaired.
TC Energy Management's discussion and analysis 2021 | 103
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 risk
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. 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.
104 | TC Energy Management's discussion and analysis 2021
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, 2021, 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, 2021, 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, 2021, the internal control
over financial reporting was effective.
Our internal control over financial reporting as of December 31, 2021 has been audited by KPMG LLP, an independent registered
public accounting firm, as stated in their attestation report which is included in our 2021 Consolidated financial statements.
CEO and CFO certifications
Our President and CEO and our CFO have attested to the quality of the public disclosure in our fiscal 2021 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.
TC Energy Management's discussion and analysis 2021 | 105
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 2021 we recorded a $2.8 billion pre-tax asset impairment charge, net of expected contractual recoveries and other contractual
and legal obligations, related to the termination of the Keystone XL pipeline project ($2.1 billion after tax).
In 2020 and 2019, no impairments were recorded.
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.
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, other than the Columbia reporting unit for which we elected to proceed directly to a quantitative impairment test. It was
determined that it was more likely than not that the fair value of all reporting units exceeded their carrying amounts, including
goodwill, and therefore, goodwill was not impaired.
Following the uncontested rate case settlement with shippers in 2021, we performed a quantitative annual goodwill impairment
test for Columbia as at December 31, 2021. It was determined that the fair value of Columbia exceeded its carrying value,
including goodwill, at December 31, 2021.
106 | TC Energy Management's discussion and analysis 2021
FINANCIAL INSTRUMENTS
With the exception of Long-term debt and Junior subordinated notes, our derivative and non-derivative financial
instruments are recorded on the balance sheet at fair value unless they were entered into and continue to be held for
the purpose of receipt or delivery in accordance with our normal purchase and sales exemptions and are documented as such.
In addition, fair value accounting is not required for other financial instruments that qualify for certain accounting exemptions.
Derivative 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
2021
169
48
(221)
(47)
(51)
2020
235
41
(72)
(59)
145
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, 2021
(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
173
(200)
44
(68)
(51)
159
(184)
10
(37)
(52)
8
(12)
29
(30)
(5)
6
(3)
5
(1)
7
—
(1)
—
—
(1)
TC Energy Management's discussion and analysis 2021 | 107
Unrealized and realized gains/(losses) on derivative instruments
The following summary does not include hedges of our net investment in foreign operations.
year ended December 31
(millions of $)
Derivative instruments held for trading1
Amount of unrealized gains/(losses) in the year
Commodities
Foreign exchange
Amount of realized gains/(losses) in the year
Commodities
Foreign exchange
Derivative instruments in hedging relationships2
Amount of realized (losses)/gains in the year
Commodities
Interest rate
2021
2020
2019
9
(203)
287
240
(44)
(32)
(23)
126
183
(33)
6
(16)
(111)
245
378
(70)
(6)
2
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.
There were no gains and 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 26, Risk
management and financial instruments, of our 2021 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.
Sur de Texas
At December 31, 2021, the Loans receivable from affiliates on our Consolidated balance sheet of MXN$19.7 billion or $1.2 billion,
represented our 60 per cent proportionate share of debt financing to the Sur de Texas joint venture. At December 31, 2020, this
loan was recorded as Long-term loans receivable from affiliates on our Consolidated balance sheet and amounted to
MXN$20.9 billion or $1.3 billion.
Our 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 our 60 per cent proportionate share of
Sur de Texas equity earnings as follows:
year ended December 31
(millions of $)
Interest income1
Interest expense2
Foreign exchange (losses)/gains1
Foreign exchange gains/(losses)1
1
2
Included in our Corporate segment.
Included in our Mexico Natural Gas Pipelines segment.
2021
87
(87)
(41)
41
2020
110
(110)
(86)
86
2019
Affected line item in the Consolidated
statement of income
147
Interest income and other
(147)
Income from equity investments
53
Interest income and other
(53)
Income from equity investments
108 | TC Energy Management's discussion and analysis 2021
Coastal GasLink LP
We hold a 35 per cent equity interest in Coastal GasLink LP and have been contracted to develop and operate the Coastal GasLink
pipeline. We have a subordinated demand revolving credit facility with Coastal GasLink LP to provide additional short-term
liquidity and funding flexibility to the project. The facility bears interest at a floating market-based rate and had a capacity of
$500 million at December 31, 2021 with an outstanding balance of $1 million (December 31, 2020 – nil) reflected in Loans
receivable from affiliates on our Consolidated balance sheet.
On December 6, 2021, we entered into a subordinated loan agreement with Coastal GasLink LP to provide interim temporary
financing, if necessary, of up to $3.3 billion to fund incremental project costs as a bridge to a required increase in the
project-level financing. Financing available to Coastal GasLink LP under this agreement is provided through a combination of
interest-bearing facilities subject to floating market-based rates and non-interest-bearing facilities that are subject to a return to
us under certain conditions at the time the final cost of the project is determined. At December 31, 2021, Long-term loans
receivable from affiliates on our Consolidated balance sheet reflected $238 million in amounts outstanding under the
subordinated loan agreement.
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 2021 Consolidated financial
statements.
TC Energy Management's discussion and analysis 2021 | 109
QUARTERLY RESULTS
Selected quarterly consolidated financial data
2021
(millions of $, except per share amounts)
Revenues
Net income/(loss) attributable to common shares
Comparable earnings
Share statistics:
Net income/(loss) per common share – basic
Comparable earnings per common share
Dividends declared per common share
2020
(millions of $, except per share amounts)
Revenues
Net income attributable to common shares
Comparable earnings
Share statistics:
Net income per common share – basic
Comparable earnings per common share
Dividends declared per common share
Fourth
3,584
1,118
1,035
$1.14
$1.06
$0.87
Fourth
3,297
1,124
1,080
$1.20
$1.15
$0.81
Third
3,240
779
972
$0.80
$0.99
$0.87
Third
3,195
904
893
$0.96
$0.95
$0.81
Second
First
3,182
975
1,038
$1.00
$1.06
$0.87
Second
3,089
1,281
863
$1.36
$0.92
$0.81
3,381
(1,057)
1,108
($1.11)
$1.16
$0.87
First
3,418
1,148
1,109
$1.22
$1.18
$0.81
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 segmented earnings
generally remain relatively stable during any fiscal year. Over the long term, however, they fluctuate because of:
• regulatory 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 segmented earnings are based on contracted and uncontracted spot transportation, as
well as liquids marketing activities. Quarter-over-quarter revenues and segmented earnings 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.
110 | TC Energy Management's discussion and analysis 2021
In Power and Storage, quarter-over-quarter revenues and segmented earnings 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 specific 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 2021, comparable earnings also excluded:
• an incremental $60 million after-tax reduction to the Keystone XL asset impairment charge, net of expected contractual
recoveries and other contractual and legal obligations, related to the termination of the Keystone XL pipeline project
• an after-tax gain of $19 million related to the sale of the remaining interest in Northern Courier
• preservation and storage costs for Keystone XL pipeline project assets of $10 million after tax, which could not be accrued as
part of the Keystone XL asset impairment charge
• a $7 million after-tax gain related to pension adjustments as part of the VRP
• an incremental $6 million income tax expense related to the sale of our Ontario natural gas-fired power plants sold in
April 2020.
In third quarter 2021, comparable earnings also excluded:
• a $55 million after-tax expense with respect to transition payments incurred as part of the VRP
• preservation and storage costs for Keystone XL pipeline project assets of $11 million after tax, which could not be accrued as
part of the Keystone XL asset impairment charge.
In second quarter 2021, comparable earnings also excluded:
• preservation and storage costs for Keystone XL pipeline project assets of $16 million after tax, which could not be accrued as
part of the Keystone XL asset impairment charge and interest expense on the Keystone XL project-level credit facility prior to
its termination
• a $13 million after-tax recovery of certain costs from the IESO associated with the Ontario natural gas-fired power plants sold in
April 2020
• an incremental $2 million after-tax asset impairment charge, net of expected contractual recoveries and other contractual and
legal obligations, related to the termination of the Keystone XL pipeline project.
In first quarter 2021, comparable earnings also excluded:
• an after-tax asset impairment charge, net of expected contractual recoveries and other contractual and legal obligations, of
$2.2 billion related to the formal suspension of the Keystone XL pipeline project following the January 20, 2021 revocation of
the Presidential Permit.
TC Energy Management's discussion and analysis 2021 | 111
In fourth quarter 2020, comparable earnings also excluded:
• an incremental after-tax loss of $81 million related to the sale of our Ontario natural gas-fired power plants
• an income tax valuation allowance release of $18 million related to certain prior years' U.S. income 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.
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 of $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
• an incremental after-tax loss of $77 million related to the Ontario natural gas-fired power plant assets held for sale.
FOURTH QUARTER 2021 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
2021
2020
389
818
123
373
191
(6)
1,888
(611)
72
87
1,436
(278)
1,158
(8)
1,150
(32)
1,118
$1.14
350
730
137
300
43
(150)
1,410
(530)
95
373
1,348
(116)
1,232
(69)
1,163
(39)
1,124
$1.20
Net income attributable to common shares decreased by $6 million or $0.06 per common share for the three months ended
December 31, 2021 compared to the same period in 2020. Net income per common share in fourth quarter 2021 reflects the
impact of common shares issued for the acquisition of the remaining ownership interests in TC PipeLines, LP in first quarter 2021.
112 | TC Energy Management's discussion and analysis 2021
The following specific items were recognized in Net income attributable to common shares and were excluded from comparable
earnings:
Fourth quarter 2021 results included:
• an incremental $60 million after-tax reduction to the Keystone XL asset impairment charge, net of expected contractual
recoveries and other contractual and legal obligations, related to the termination of the Keystone XL pipeline project following
the January 20, 2021 revocation of the Presidential Permit
• an after-tax gain of $19 million related to the sale of the remaining interest in Northern Courier
• preservation and storage costs for Keystone XL pipeline project assets of $10 million after tax, which could not be accrued as
part of the Keystone XL asset impairment charge
• a $7 million after-tax gain primarily related to pension adjustments incurred as part of the VRP
• an incremental $6 million income tax expense related to the sale of our Ontario natural gas-fired power plants sold in
April 2020.
The Keystone XL pipeline project asset impairment charge does not reflect offsetting amounts with respect to the Government
of Alberta's investment in Keystone XL nor their repayment of the project's guaranteed credit facility without recourse to
TC Energy, both of which were accounted for within the Consolidated statement of equity in second quarter 2021 and served to
reduce our net financial impact from the Keystone XL pipeline project termination.
Fourth quarter 2020 results included:
• an incremental after-tax loss of $81 million related to the Ontario natural-gas fired power plants sold in April 2020
• an income tax valuation allowance release of $18 million following our reassessment of deferred tax assets that were deemed
more likely than not to be realized in 2020
• an additional $18 million income tax recovery related to state income taxes on the sale of certain Columbia Midstream assets.
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 2021 | 113
2021
1,118
(60)
(19)
(7)
10
6
—
—
(13)
1,035
$1.14
(0.06)
(0.02)
(0.01)
0.01
0.01
—
—
(0.01)
$1.06
2020
1,124
—
—
—
—
81
(18)
(18)
(89)
1,080
$1.20
—
—
—
—
0.08
(0.02)
(0.02)
(0.09)
$1.15
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):
Keystone XL asset impairment charge and other
Gain on partial sale of Northern Courier
Voluntary Retirement Program
Keystone XL preservation and other
Loss on sale of Ontario natural gas-fired power plants
Income tax valuation allowance releases
Gain on sale of Columbia Midstream assets
Risk management activities1
Comparable earnings
Net income per common share
Specific items (net of tax):
Keystone XL asset impairment charge and other
Gain on partial sale of Northern Courier
Voluntary Retirement Program
Keystone XL preservation and other
Loss on sale of Ontario natural gas-fired power plants
Income tax valuation allowance releases
Gain on sale of Columbia Midstream assets
Risk management activities
Comparable earnings per common share
three months ended December 31
1
(millions of $)
U.S. Natural Gas Pipelines
Liquids Pipelines
Canadian Power
Natural Gas Storage
Foreign exchange
Income taxes attributable to risk management activities
Total unrealized gains from risk management activities
2021
2020
7
(5)
4
30
(20)
(3)
13
—
(25)
(1)
(5)
150
(30)
89
114 | TC Energy Management's discussion and analysis 2021
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.
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
2021
2020
674
1,032
151
380
177
(10)
2,404
(634)
(611)
72
103
(259)
(8)
(32)
1,035
$1.06
682
919
166
408
161
(13)
2,323
(652)
(530)
95
86
(134)
(69)
(39)
1,080
$1.15
TC Energy Management's discussion and analysis 2021 | 115
Comparable EBITDA – 2021 versus 2020
Comparable EBITDA increased by $81 million for the three months ended December 31, 2021 compared to the same period in
2020 primarily due to the net effect of the following:
• increased earnings in U.S. Natural Gas Pipelines primarily from higher Columbia Gas transportation rates effective
February 1, 2021 as a result of the subsequently uncontested rate case settlement, lower operating costs across a number of
pipelines and improved earnings from our mineral rights business
• higher Power and Storage comparable EBITDA resulting from increased Canadian Power earnings mainly due to contributions
from trading activities and higher realized margins, as well as increased earnings from Bruce Power due to higher volumes
resulting from fewer outage days
• decreased earnings from Liquids Pipelines attributable to lower volumes on the U.S. Gulf Coast section of the Keystone Pipeline
System, partially offset by increased contributions from liquids marketing activities reflecting higher margins and volumes
• lower comparable EBITDA from Canadian Natural Gas Pipelines due to the net effect of lower flow-through depreciation and
financial charges, partially offset by higher incentive earnings and the elimination of the TC Energy contribution on the
Canadian Mainline, offset in part by higher flow-through income taxes as well as increased rate-base earnings on the NGTL
System
• foreign exchange impact of a weaker U.S. dollar on the Canadian dollar equivalent segmented earnings in our
U.S. dollar-denominated operations. As detailed below, U.S. dollar-denominated comparable EBITDA increased by
US$92 million to US$1.2 billion compared to US$1.1 billion in 2020; however, this was translated at a rate of 1.26 in 2021 versus
1.30 in 2020. Refer to the Foreign exchange discussion below for additional information.
While the weakening of the U.S. dollar in fourth quarter 2021 compared to the same period in 2020 had a considerable negative
impact on 2021 comparable EBITDA for the three months ended December 31, 2021, the corresponding impact on comparable
earnings was not significant due to offsetting natural and economic hedges. Refer to the Foreign exchange discussion below for
additional information.
Due to the flow-through treatment of certain expenses including income taxes, financial charges and depreciation in our
Canadian rate-regulated pipelines, changes in these expenses impact our comparable EBITDA despite having no significant effect
on net income.
Comparable earnings – 2021 versus 2020
Comparable earnings decreased by $45 million or $0.09 per common share for the three months ended December 31, 2021
compared to the same period in 2020 and was primarily the net effect of:
• changes in comparable EBITDA described above
• higher Income tax expense mainly due to the impact of lower foreign tax rate differentials, Mexico inflationary adjustments, as
well as increased flow-through income taxes on Canadian rate-regulated pipelines
• higher Interest expense primarily due to lower capitalized interest as a result of its cessation for the Keystone XL pipeline
project following the revocation of the Presidential Permit on January 20, 2021, partially offset by the foreign exchange impact
from a weaker U.S. dollar on translation of U.S. dollar-denominated interest
• lower AFUDC, predominantly due to suspension of recording AFUDC on the Villa de Reyes project effective January 1, 2021
resulting from ongoing delays, partially offset by NGTL System expansion projects under construction
• lower Non-controlling interests following the March 3, 2021 acquisition of all outstanding common units of TC PipeLines, LP
not beneficially owned by TC Energy
• decreased Depreciation and amortization in our Canadian Natural Gas Pipelines due to one section of the Canadian Mainline
being fully depreciated in 2021, partially offset by new projects in U.S. Gas Natural Gas Pipelines placed in service and certain
fourth quarter 2021 adjustments related to the Columbia Gas uncontested rate case settlement
• higher Interest income and other mainly attributable to higher realized gains in 2021 compared to 2020 on derivatives used to
manage our net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income.
Foreign exchange
Despite the decrease in the average exchange rate for the three months ended December 31, 2021 compared to 2020, the net
impact of U.S. dollar movements on comparable earnings over this period, after considering natural offsets and economic
hedges, was not significant. The components of our financial results denominated in U.S. dollars are set out in the table below,
including our U.S. and Mexico Natural Gas Pipelines operations along with the majority of our Liquids Pipelines business.
Comparable EBITDA is a non-GAAP measure.
116 | TC Energy Management's discussion and analysis 2021
Pre-tax U.S. dollar-denominated income and expense items
three months ended December 31
(millions of US$)
Comparable EBITDA
U.S. Natural Gas Pipelines
Mexico Natural Gas Pipelines1
U.S. Liquids Pipelines
Depreciation and amortization
Interest on long-term debt and junior subordinated notes
Capitalized interest
Allowance for funds used during construction
Non-controlling interests and other
Average exchange rate - U.S. to Canadian dollars
2021
2020
819
140
216
1,175
(245)
(314)
—
28
(9)
635
1.26
706
146
231
1,083
(216)
(315)
42
56
(70)
580
1.30
1
Excludes interest expense on our inter-affiliate loan with Sur de Texas which is fully offset in Interest income and other.
Highlights by business segment
Canadian Natural Gas Pipelines
Canadian Natural Gas Pipelines segmented earnings increased by $39 million for the three months ended December 31, 2021
compared to the same period in 2020.
Net income for the NGTL System increased by $18 million for the three months ended December 31, 2021 compared to the same
period in 2020 mainly due to a higher average investment base resulting from continued system expansions. Effective
January 1, 2020, the NGTL System is operating under the 2020-2024 Revenue Requirement Settlement which includes an ROE of
10.1 per cent on 40 per cent deemed common equity. This settlement provides the NGTL System the opportunity to increase
depreciation rates if tolls fall below specified levels and an incentive mechanism for certain operating costs where variances from
projected amounts are shared with our customers.
Net income for the Canadian Mainline increased by $15 million for the three months ended December 31, 2021 compared to the
same period in 2020 mainly as a result of higher incentive earnings and the elimination of a $20 million after-tax annual
TC Energy contribution included in the previous settlement. Effective January 1, 2021, the Canadian Mainline is operating under
the 2021-2026 Mainline Settlement which includes an approved ROE of 10.1 per cent on 40 per cent deemed common equity and
an incentive to decrease costs and increase revenues on the pipeline under a beneficial sharing mechanism with our customers.
In 2020, the Canadian Mainline operated under the terms of the 2015-2030 Tolls Application approved in 2014. The terms of the
previous 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.
Comparable EBITDA for Canadian Natural Gas Pipelines decreased by $8 million for the three months ended December 31, 2021
compared to the same period in 2020 primarily due to the net effect of:
• lower flow-through depreciation and financial charges, partially offset by higher incentive earnings, the elimination of the
TC Energy contribution and higher flow-through income taxes on the Canadian Mainline
• higher flow-through depreciation and income taxes as well as increased rate-base earnings on the NGTL System.
Depreciation and amortization decreased by $47 million for the three months ended December 31, 2021 compared to the same
period in 2020 mainly due to one section of the Canadian Mainline being fully depreciated in 2021, partially offset by higher
depreciation on the NGTL System from facilities that were placed in service.
TC Energy Management's discussion and analysis 2021 | 117
U.S. Natural Gas Pipelines
U.S. Natural Gas Pipelines segmented earnings increased by $88 million for the three months ended December 31, 2021
compared to the same period in 2020 and included unrealized gains from changes in the fair value of derivatives related to our
U.S. natural gas marketing business in 2021 which have been excluded from our calculation of comparable EBIT. A weaker
U.S. dollar in 2021 had a negative impact on the Canadian dollar equivalent segmented earnings from our U.S. operations
compared to the same period in 2020.
Comparable EBITDA for U.S. Natural Gas Pipelines increased by US$113 million for the three months ended December 31, 2021
compared to the same period in 2020 and was primarily due to the net effect of:
• a net increase in comparable EBITDA from Columbia Gas as a result of the higher transportation rates effective
February 1, 2021, pursuant to the Columbia Gas uncontested rate case settlement. Refer to U.S. Natural Gas Pipelines –
Significant events for additional information
• increased earnings from lower operating costs across a number of pipelines and the contribution from growth projects placed
in service primarily on Columbia Gas and ANR
• increased earnings from our mineral rights business due to higher commodity prices.
Depreciation and amortization increased by US$30 million for the three months ended December 31, 2021 compared to the same
period in 2020 mainly due to new projects placed in service and certain fourth quarter 2021 adjustments related to the Columbia
Gas uncontested rate case settlement.
Mexico Natural Gas Pipelines
Mexico Natural Gas Pipelines comparable EBIT and segmented earnings decreased by $14 million for the three months ended
December 31, 2021, compared to the same period in 2020. A weaker U.S. dollar in fourth quarter 2021 had a negative impact on
the Canadian dollar equivalent segmented earnings compared to the same period in 2020.
Comparable EBITDA for Mexico Natural Gas Pipelines decreased by US$6 million for the three months ended December 31, 2021
compared to the same period in 2020 as a result of lower equity income from Sur de Texas.
Depreciation and amortization for the three months ended December 31, 2021 was consistent with the same period in 2020.
Liquids Pipelines
Liquids Pipelines segmented earnings increased by $73 million for the three months ended December 31, 2021 compared to the
same period in 2020 and included the following specific items which have been excluded from our calculation of comparable
EBIT:
• pre-tax asset impairment charge reduction of $79 million for the three months ended December 31, 2021, associated with the
termination of the Keystone XL pipeline and related projects following the January 20, 2021 revocation of the Presidential
Permit
• pre-tax preservation and storage costs for Keystone XL pipeline project assets of $14 million for the three months ended
December 31, 2021, which could not be accrued as part of the Keystone XL asset impairment charge
• pre-tax gain of $13 million related to the sale of the remaining 15 per cent interest in Northern Courier in fourth quarter 2021
• unrealized gains and losses from changes in the fair value of derivatives related to our liquids marketing business.
A weaker U.S. dollar in 2021 had a negative impact on the Canadian dollar equivalent segmented earnings from our
U.S. operations compared to the same period in 2020.
Comparable EBITDA for Liquids Pipelines decreased by $28 million for the three months ended December 31, 2021 compared to
the same period in 2020 and was primarily due to the net effect of:
• lower volumes on the U.S. Gulf Coast section of the Keystone Pipeline System
• increased contributions from liquids marketing activities due to higher margins and volumes.
Depreciation and amortization decreased by $3 million for the three months ended December 31, 2021 compared to the same
period in 2020 primarily as a result of a weaker U.S. dollar.
118 | TC Energy Management's discussion and analysis 2021
Power and Storage
Power and Storage segmented earnings increased by $148 million for the three months ended December 31, 2021 compared to
the same period in 2020 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 related to the sale of our Ontario natural
gas-fired power plants
• unrealized gains and losses from changes in the fair value of derivatives used to manage our exposure to commodity price risk.
Comparable EBITDA for Power and Storage increased by $16 million for the three months ended December 31, 2021 compared to
the same period in 2020 primarily due to the net effect of:
• increased Canadian Power earnings primarily due to contributions from trading activities and higher realized margins
• increased contributions from Bruce Power mainly due to higher volumes resulting from lower outage days, partially offset by
increased operating costs
• decreased Natural Gas Storage and other earnings as a result of increased business development activities across the segment
and lower realized Alberta natural gas storage spreads.
Depreciation and amortization for the three months ended December 31, 2021 was consistent with the same period in 2020.
Corporate
Corporate segmented losses decreased by $144 million for the three months ended December 31, 2021 compared to the same
period in 2020. Corporate segmented losses included an $8 million gain primarily due to a pension settlement and curtailment
following the VRP offered in mid-2021. In addition, segmented losses included foreign exchange losses and gains on our
proportionate share of peso-denominated inter-affiliate loans to the Sur de Texas joint venture from its partners. These foreign
exchange losses and gains are recorded in Income from equity investments in the Corporate segment and have been excluded
from our calculation of comparable EBITDA and EBIT as they are fully offset by corresponding foreign exchange gains and losses
on the inter-affiliate loan receivable included in Interest income and other.
Comparable EBITDA and EBIT for Corporate for the three months ended December 31, 2021 was largely consistent with the same
period in 2020.
TC Energy Management's discussion and analysis 2021 | 119
Accounting terms
AFUDC
GAAP
LIBOR
RRA
ROE
Allowance for funds used during
construction
U.S. generally accepted accounting
principles
London Interbank Offered Rate
Rate-regulated accounting
Return on common equity
Government and regulatory bodies terms
CER
CFE
CRE
ECCC
FERC
IESO
NYSE
OBPS
OPEC+
OPG
PHMSA
SEC
TSX
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)
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
MMcf/d
MW
MWh
PJ/d
TJ/d
Barrel(s) per day
Billion cubic feet
Billion cubic feet per day
Gigawatt hours
Kilometres
Million cubic feet per day
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
force majeure
GHG
HSSE
investment base
LDC
LNG
MOU
OM&A
PPA
rate base
TSA
TOMS
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
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
Memorandum of understanding
Operating, maintenance and
administration
Power purchase arrangement
Average assets in service, working
capital and deferred amounts used in
setting of regulated rates
Transportation Service Agreement
TC Energy's Operational Management
System
Western Canadian Sedimentary basin
120 | TC Energy Management's discussion and analysis 2021
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 2021 to that in 2020, and highlights significant changes between 2020 and 2019. 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, 2021, 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.
François L. Poirier
President and
Chief Executive Officer
February 14, 2022
Joel E. Hunter
Executive Vice-President and
Chief Financial Officer
TC Energy Consolidated Financial Statements 2021 |121
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, 2021 and 2020, 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, 2021, 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, 2021 and 2020, and the results of its operations and its cash flows for each of the
years in the three‑year period ended December 31, 2021, 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, 2021, 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 14, 2022 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 Matters
The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial
statements that were communicated or required to be communicated to the Audit Committee and that: (1) relate 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 critical audit matters 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 matters below, providing separate
opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Qualitative goodwill impairment indicators
As discussed in Note 13 to the consolidated financial statements, the goodwill balance as of December 31, 2021 was
$12,582 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, including goodwill, might be impaired. Other than the
Columbia Pipeline Group, Inc. (Columbia) reporting unit where the Company has elected to proceed directly to a quantitative
goodwill impairment test, the Company 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, 2021.
122 | TC Energy Consolidated Financial Statements 2021
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 include macroeconomic conditions, industry and market considerations,
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. In addition, the audit effort associated with this evaluation required specialized skills and knowledge.
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 them 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 assessment, by comparing them against a discount rate range that
was independently developed using publicly available market data for comparable entities.
Valuation of goodwill for the Columbia reporting unit
As discussed in Note 13 to the consolidated financial statements, the goodwill balance as of December 31, 2021 was
$12,582 million, of which $9,303 million related to the Columbia reporting unit. 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,
including goodwill, might be impaired. The Company has the option to first assess qualitative factors to determine whether it is
necessary to perform the quantitative goodwill impairment assessment. In respect of the Columbia reporting unit, the Company
elected to proceed directly to the quantitative goodwill impairment test following an uncontested rate case settlement with
shippers in 2021. The quantitative goodwill impairment assessment involves determining the fair value of a reporting unit and
comparing that value to the carrying value of the reporting unit, including goodwill. Fair value is estimated using a discounted
cash flow model which requires the use of assumptions related to revenue and capital expenditure projections, the valuation
multiple and the discount rate (key assumptions).
We identified the valuation of goodwill for the Columbia reporting unit as a critical audit matter. A high degree of auditor
judgment was required to evaluate the key assumptions. Minor changes to the key assumptions could have had a significant
effect on the Company’s determination of the fair value of the Columbia reporting unit. In addition, the audit effort associated
with this estimate required specialized skills and knowledge.
TC Energy Consolidated Financial Statements 2021 |123
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 critical audit matter. This included controls related to the
Company’s determination of the fair value of the Columbia reporting unit and key assumptions. We compared the Company’s
historical revenue and capital expenditure projections to actual results to assess the Company’s ability to accurately forecast. We
evaluated the Company’s revenue and capital expenditure projections by comparing them to the actual results and the
outcomes of the uncontested rate case settlement with shippers in 2021. We also compared the Company’s revenue and capital
expenditure projections to assumptions used in industry publications related to North American and global energy consumption
and natural gas production forecasts. In addition, we involved a valuation professional with specialized skills and knowledge,
who assisted in:
• evaluating the Company’s determination of a valuation multiple by comparing it to independently observed recent market
transactions of comparable assets and publicly available market data for comparable entities
• evaluating the discount rate used by management in the valuation, by comparing it against a discount rate range that was
independently developed using publicly available market data for comparable entities
• evaluating the Company’s estimate of the fair value of the Columbia reporting unit by comparing the result of the Company’s
estimate to publicly available market data and valuation metrics for comparable entities.
Chartered Professional Accountants
We have served as the Company's auditor since 1956.
Calgary, Canada
February 14, 2022
124 | TC Energy Consolidated Financial Statements 2021
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, 2021, 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, 2021, 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, 2021 and 2020, 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, 2021, and the related notes (collectively, the consolidated financial statements), and our report dated
February 14, 2022 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 Annual
Report on Internal Control over Financial Reporting included in the Company's Management’s Discussion and Analysis. 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 14, 2022
TC Energy Consolidated Financial Statements 2021 | 125
Consolidated statement of income
year ended December 31
(millions of Canadian $, except per share amounts)
2021
2020
2019
Revenues (Note 5)
Canadian Natural Gas Pipelines
U.S. Natural Gas Pipelines
Mexico Natural Gas Pipelines
Liquids Pipelines
Power and Storage
Income from Equity Investments (Note 10)
Operating and Other Expenses
Plant operating costs and other
Commodity purchases resold
Property taxes
Depreciation and amortization
Asset impairment charge and other (Note 6)
Net Gain/(Loss) on Assets Sold/Held for Sale (Note 28)
Financial Charges
Interest expense (Note 19)
Allowance for funds used during construction
Interest income and other
Income before Income Taxes
Income Tax Expense (Note 18)
Current
Deferred
Net Income
Net income attributable to non-controlling interests (Note 21)
Net Income Attributable to Controlling Interests
Preferred share dividends
Net Income Attributable to Common Shares
Net Income per Common Share (Note 22)
Basic
Diluted
4,519
5,233
605
2,306
724
13,387
898
4,098
87
774
2,522
2,775
10,256
30
2,360
(267)
(200)
1,893
2,166
305
(185)
120
2,046
91
1,955
140
1,815
$1.87
$1.86
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
Dividends Declared per Common Share
$3.48
$3.24
$3.00
Weighted Average Number of Common Shares (millions) (Note 22)
Basic
Diluted
973
974
940
940
929
931
The accompanying Notes to the consolidated financial statements are an integral part of these statements.
126 | TC Energy Consolidated Financial Statements 2021
Consolidated statement of comprehensive income
year ended December 31
(millions of Canadian $)
Net Income
Other Comprehensive Income/(Loss), 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 income/(loss) on equity investments
Other comprehensive income/(loss) (Note 24)
Comprehensive Income
Comprehensive income attributable to non-controlling interests
Comprehensive Income Attributable to Controlling Interests
Preferred share dividends
Comprehensive Income Attributable to Common Shares
2021
2020
2,046
4,913
(108)
—
(2)
(10)
55
158
14
535
642
2,688
81
2,607
140
2,467
(609)
—
36
(583)
489
12
17
(280)
(918)
3,995
259
3,736
159
3,577
2019
4,433
(944)
(13)
35
(62)
14
(10)
10
(82)
(1,052)
3,381
194
3,187
164
3,023
The accompanying Notes to the consolidated financial statements are an integral part of these statements.
TC Energy Consolidated Financial Statements 2021 | 127
Consolidated statement of cash flows
year ended December 31
(millions of Canadian $)
Cash Generated from Operations
Net income
Depreciation and amortization
Asset impairment charge and other (Note 6)
Deferred income taxes (Note 18)
Income from equity investments (Note 10)
Distributions received from operating activities of equity investments (Note 10)
Employee post-retirement benefits funding, net of expense (Note 25)
Net (gain)/loss on assets sold/held for sale (Note 28)
Equity allowance for funds used during construction
Unrealized losses/(gains) on financial instruments
Foreign exchange losses/(gains) on loan receivable from affiliate (Note 11)
Other
(Increase)/decrease in operating working capital (Note 27)
Net cash provided by operations
Investing Activities
Capital expenditures (Note 4)
Capital projects in development (Note 4)
Contributions to equity investments (Notes 4 and 10)
Proceeds from sales of assets, net of transaction costs
Loan to affiliate (Note 11)
Acquisition
Other distributions from equity investments (Note 10)
Payment for unredeemed shares of Columbia Pipeline Group, Inc. (Note 28)
Deferred amounts and other
Net cash used in investing activities
Financing Activities
Notes payable issued/(repaid), 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 26)
Redeemable non-controlling interest repurchased (Note 6)
Contributions from redeemable non-controlling interest (Note 6)
Dividends on common shares
Dividends on preferred shares
Distributions to non-controlling interests
Distributions on Class C Interests (Note 6)
Common shares issued, net of issue costs
Preferred shares redeemed (Note 23)
Acquisition of TC PipeLines, LP transaction costs (Note 21)
Net cash (used in)/provided by financing activities
Effect of Foreign Exchange Rate Changes on Cash and Cash Equivalents
(Decrease)/Increase in Cash and Cash Equivalents
Cash and Cash Equivalents
Beginning of year
Cash and Cash Equivalents
End of year
2021
2020
2019
2,046
2,522
2,775
(185)
(898)
975
(5)
(30)
(191)
194
41
(67)
(287)
6,890
(5,924)
—
(1,210)
35
(239)
—
73
—
(447)
(7,712)
1,003
10,730
(7,758)
495
(10)
(633)
—
(3,317)
(141)
(74)
(16)
148
(500)
(15)
(88)
53
(857)
1,530
673
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)
—
1,033
(2,987)
(159)
(221)
—
91
—
—
(800)
(19)
187
1,343
1,530
4,433
2,464
—
55
(920)
1,213
(45)
121
(299)
(134)
(53)
(46)
293
7,082
(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
446
1,343
The accompanying Notes to the consolidated financial statements are an integral part of these statements.
128 | TC Energy Consolidated Financial Statements 2021
Consolidated balance sheet
at December 31
(millions of Canadian $)
ASSETS
Current Assets
Cash and cash equivalents
Accounts receivable
Loans receivable from affiliates (Note 11)
Inventories
Other current assets (Note 7)
Plant, Property and Equipment (Note 8)
Equity Investments (Note 10)
Long-Term Loans Receivable from Affiliates (Note 11)
Restricted Investments
Regulatory Assets (Note 12)
Goodwill (Note 13)
Other Long-Term Assets (Note 14)
LIABILITIES
Current Liabilities
Notes payable (Note 15)
Accounts payable and other (Note 16)
Dividends payable
Accrued interest
Redeemable non-controlling interest (Note 6)
Current portion of long-term debt (Note 19)
Regulatory Liabilities (Note 12)
Other Long-Term Liabilities (Note 17)
Deferred Income Tax Liabilities (Note 18)
Long-Term Debt (Note 19)
Junior Subordinated Notes (Note 20)
Redeemable Non-Controlling Interest (Note 6)
EQUITY
Common shares, no par value (Note 22)
Issued and outstanding:
Preferred shares (Note 23)
Additional paid-in capital
Retained earnings
Accumulated other comprehensive loss (Note 24)
Controlling Interests
Non-controlling interests (Note 21)
December 31, 2021 – 981 million shares
December 31, 2020 – 940 million shares
2021
2020
673
3,092
1,217
724
1,717
7,423
70,182
8,441
238
2,182
1,767
12,582
1,403
104,218
5,166
5,099
879
577
—
1,320
13,041
4,300
1,059
6,142
37,341
8,939
70,822
—
26,716
3,487
729
3,773
(1,434)
33,271
125
33,396
104,218
1,530
2,162
—
629
880
5,201
69,775
6,677
1,338
1,898
1,753
12,679
979
100,300
4,176
3,816
795
595
633
1,972
11,987
4,148
1,475
5,806
34,913
8,498
66,827
393
24,488
3,980
2
5,367
(2,439)
31,398
1,682
33,080
100,300
Commitments, Contingencies and Guarantees (Note 29)
Variable Interest Entities (Note 30)
The accompanying Notes to the consolidated financial statements are an integral part of these statements.
On behalf of the Board:
François L. Poirier, Director
Una M. Power, Director
TC Energy Consolidated Financial Statements 2021 | 129
Consolidated statement of equity
year ended December 31
(millions of Canadian $)
Common Shares (Note 22)
Balance at beginning of year
Shares issued:
Acquisition of TC PipeLines, LP, net of transaction costs (Note 21)
Exercise of stock options
Dividend reinvestment and share purchase plan
Balance at end of year
Preferred Shares (Note 23)
Balance at beginning of year
Redemption of shares
Balance at end of year
Additional Paid-In Capital
Balance at beginning of year
Keystone XL project-level credit facility retirement and issuance of Class C Interests (Note 6)
Acquisition of TC PipeLines, LP (Note 21)
Repurchase of redeemable non-controlling interest (Note 6)
Issuance of stock options, net of exercises
Balance at end of year
Retained Earnings
Balance at beginning of year
Net income attributable to controlling interests
Common share dividends
Preferred share dividends
Redemption of preferred shares
Balance at end of year
Accumulated Other Comprehensive Loss (Note 24)
Balance at beginning of year
Other comprehensive income/(loss) attributable to controlling interests
Acquisition of TC PipeLines, LP (Note 21)
Balance at end of year
Equity Attributable to Controlling Interests
Equity Attributable to Non-Controlling Interests
Balance at beginning of year
Net income attributable to non-controlling interests
Other comprehensive loss attributable to non-controlling interests
Distributions declared to non-controlling interests
Acquisition of TC PipeLines, LP (Note 21)
Balance at end of year
Total Equity
2021
2020
2019
24,488
24,387
23,174
2,063
165
—
—
101
—
—
282
931
26,716
24,488
24,387
3,980
(493)
3,487
2
737
(398)
394
(6)
729
5,367
1,955
(3,409)
(133)
(7)
3,773
3,980
—
3,980
—
—
—
—
2
2
3,955
4,616
(3,045)
(159)
—
5,367
(2,439)
(1,559)
652
353
(1,434)
33,271
(880)
—
(2,439)
31,398
3,980
—
3,980
17
—
—
—
(17)
—
2,773
4,140
(2,794)
(164)
—
3,955
(606)
(953)
—
(1,559)
30,763
1,682
1,634
1,655
90
(10)
(74)
(1,563)
125
33,396
307
(38)
(221)
—
1,682
33,080
293
(99)
(215)
—
1,634
32,397
The accompanying Notes to the consolidated financial statements are an integral part of these statements.
130 | TC Energy Consolidated Financial Statements 2021
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 40,580 km (25,216 miles) of
regulated natural gas pipelines currently in operation.
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 currently in operation.
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 currently in operation.
Liquids Pipelines
The Liquids Pipelines segment primarily consists of the Company's investments in 4,856 km (3,019 miles) of crude oil pipeline
systems currently in operation 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. 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.
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:
• fair value of reporting units that contain goodwill (Notes 13 and 28)
• fair value of assets and liabilities acquired in a business combination (Note 28).
TC Energy Consolidated Financial Statements 2021 | 131
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:
• valuation of Keystone XL assets (Note 6)
• recoverability and depreciation rates of plant, property and equipment (Note 8)
• determining whether a contract contains a lease (Note 9)
• fair value of equity investments (Note 10)
• carrying value of regulatory assets and liabilities (Note 12)
• carrying value of asset retirement obligations (Note 17)
• provisions for income taxes, including valuation allowances and releases (Note 18)
• assumptions used to measure retirement and other post-retirement benefit obligations (Note 25)
• fair value of financial instruments (Note 26)
• provisions for commitments, contingencies and guarantees (Note 29).
TC Energy continues to assess the impact of climate change on the consolidated financial statements. The Company has
announced internal greenhouse gas reduction targets and closely monitors regulatory initiatives that may impact its existing
businesses. The impact of these changes are continuously assessed to ensure any changes in assumptions that would impact
estimates listed above are adjusted on a timely basis.
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 natural gas pipelines in Canada, U.S. and Mexico, 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.
132 | TC Energy Consolidated Financial Statements 2021
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.
The majority of income earned from marketing activities, as it relates to the purchase and sale of crude oil, natural gas and
electricity, is recorded on a net basis in the month of delivery.
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.
TC Energy Consolidated Financial Statements 2021 | 133
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 regard 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.
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 28, Acquisitions and dispositions, for additional information regarding the sale of the Columbia Midstream assets.
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.
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.
Power and Storage
Power
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.
134 | TC Energy Consolidated Financial Statements 2021
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 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.
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 28, Acquisitions and dispositions, for additional information.
TC Energy Consolidated Financial Statements 2021 | 135
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.
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
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, including power purchase agreements (PPA), 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 facilities and liquids tank
terminals for which the Company is the lessor.
136 | TC Energy Consolidated Financial Statements 2021
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.
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. The fair value of a reporting unit is determined by using a discounted cash flow analysis
which requires the use of assumptions that may include, but are not limited to, revenue and capital expenditure projections,
valuation multiples, and discount rates.
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.
TC Energy Consolidated Financial Statements 2021 | 137
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.
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.
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. The Company’s exposure to uncertain tax positions is evaluated and
a provision is made where it is more likely than not that this exposure will materialize.
Canadian income taxes are not provided for 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
• 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.
138 | TC Energy Consolidated Financial Statements 2021
Emission allowances or credits purchased for compliance are recorded on the Consolidated balance sheet at historical cost and
derecognized 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 in the Consolidated statement of income.
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.
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 income/(loss)(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.
TC Energy Consolidated Financial Statements 2021 | 139
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.
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.
140 | TC Energy Consolidated Financial Statements 2021
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 2021 | 141
3. ACCOUNTING CHANGES
Changes in Accounting Policies for 2021
Income Taxes
In December 2019, the Financial Accounting Standards Board (FASB) issued new guidance that simplified the accounting for
income taxes and clarified existing guidance. This new guidance was effective January 1, 2021, and did not have a material
impact on the Company's consolidated financial statements.
Reference Rate Reform
In response to the expected cessation of the U.S. dollar London Interbank Offered Rate (LIBOR), for which certain rate settings
ceased to be published at the end of 2021 with full cessation 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 has completed necessary system changes to facilitate
the adoption of the proposed standard market reference rates. The Company has also completed its analysis of contracts
impacted by reference rate reform. Contract modifications, if required, will take place prior to the full cessation date in
mid-2023. The Company expects to use practical expedients available in the guidance to treat contract modifications as events
that do not require contract remeasurement or reassessment of previous accounting determinations. As such, these changes are
not expected to have a material impact on the consolidated financial statements; however, the Company will continue to
monitor any new developments up to the full cessation date.
Future Accounting Changes
Government Assistance
In November 2021, the FASB issued new guidance that expands annual disclosure requirements for entities that account for a
transaction with a government by applying a grant or contribution accounting model by analogy to other accounting guidance.
Entities are required to disclose the nature of the transactions, the related accounting policies used to account for the
transactions, the effect of the transactions on an entity’s financial statements, and any significant terms and conditions of the
transaction. This new guidance is effective for annual disclosure requirements at December 31, 2022 and can be applied either
prospectively or retrospectively, with early application permitted. The Company is currently evaluating the impact of the
adoption of this guidance and has not yet determined the effect on its consolidated financial statements.
Contract Assets and Liabilities from Contracts with Customers
In October 2021, the FASB issued new guidance that amends the accounting for contract assets and liabilities from contracts with
customers acquired in a business combination. At the acquisition date, an acquirer should account for the contract assets and
liabilities in accordance with guidance on revenue from contracts with customers. This new guidance is effective January 1, 2023
and is applied prospectively with early adoption permitted. Early adoption requires the application of the amendments
retrospectively to all business combinations with an acquisition date in the year of early adoption. The Company is currently
evaluating the timing of the adoption of this guidance.
142 | TC Energy Consolidated Financial Statements 2021
4. SEGMENTED INFORMATION
year ended December 31, 2021
(millions of Canadian $)
Revenues
Intersegment revenues
Income from equity investments
Canadian
Natural
Gas
Pipelines
U.S.
Natural
Gas
Pipelines
Mexico
Natural
Gas
Pipelines
Liquids
Pipelines
Power
and
Storage
Corporate1
Total
4,519
5,233
—
145
4,519
5,378
12
244
605
—
605
119
2,306
—
2,306
71
724
14
738
411
Plant operating costs and other
(1,567)
(1,393)
(55)
(700)
(455)
Commodity purchases resold
Property taxes
Depreciation and amortization
Asset impairment charge and other
Gain on sale of assets
—
(289)
(1,226)
—
—
—
(367)
(791)
—
—
(3)
—
(109)
—
—
(84)
(113)
(318)
(2,775)
13
—
(5)
(78)
—
17
—
13,387
2
(159)
—
(159)
13,387
3
2
41
72
—
—
—
—
—
898
(4,098)
(87)
(774)
(2,522)
(2,775)
30
Segmented Earnings/(Losses)
1,449
3,071
557
(1,600)
628
(46)
4,059
Interest expense
Allowance for funds used during construction
Interest income and other3
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
Contributions to equity investments
(2,360)
267
200
2,166
(120)
2,046
(91)
1,955
(140)
1,815
5,924
1,210
7,134
2,629
2,611
108
209
2,737
2,820
129
—
129
488
83
571
32
810
842
35
—
35
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 11, Loans receivable from affiliates, for additional information.
TC Energy Consolidated Financial Statements 2021 | 143
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
Interest income and other3
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
4,469
5,031
—
165
4,469
5,196
12
264
(1,631)
(1,485)
(284)
(1,273)
364
(337)
(801)
—
1,657
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
Corporate1
Total
—
12,999
2
(185)
—
(185)
12,999
3
2
86
169
—
—
—
70
1,019
(3,878)
(727)
(2,590)
(50)
6,773
(2,228)
349
213
5,107
(194)
4,913
(297)
4,616
(159)
4,457
8,013
122
765
8,900
3,503
2,785
173
1,315
—
105
—
—
—
—
122
5
3,608
2,785
173
1,442
179
—
655
834
58
—
—
58
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 11, Loans receivable from affiliates, for additional information.
144 | TC Energy Consolidated Financial Statements 2021
year ended December 31, 2019
(millions of Canadian $)
Revenues
Intersegment revenues
Income/(loss) from equity investments
Canadian
Natural
Gas
Pipelines
U.S.
Natural
Gas
Pipelines
Mexico
Natural
Gas
Pipelines
Liquids
Pipelines
Power
and
Storage
Corporate1
Total
4,010
4,978
—
164
4,010
5,142
12
264
603
—
603
56
2,879
—
2,879
70
Plant operating costs and other
(1,473)
(1,581)
(54)
(728)
Commodity purchases resold
Property taxes
Depreciation and amortization
Net gain/(loss) on assets sold/held for sale
—
(275)
(1,159)
—
—
(345)
(754)
21
Segmented Earnings/(Losses)
1,115
2,747
—
—
(115)
—
490
—
(101)
(341)
69
1,848
785
19
804
571
(243)
(365)
(6)
(95)
(211)
455
—
13,255
2
(183)
—
(183)
13,255
3
2
(53)
166
—
—
—
—
920
(3,913)
(365)
(727)
(2,464)
(121)
(70)
6,585
Interest expense
Allowance for funds used during construction
Interest income and other3
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
(2,333)
475
460
5,187
(754)
4,433
(293)
4,140
(164)
3,976
7,475
707
602
8,784
3,900
2,500
6
—
—
16
3,906
2,516
323
—
34
357
239
701
14
954
481
—
538
1,019
32
—
—
32
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 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 11, Loans receivable from affiliates, for additional information.
TC Energy Consolidated Financial Statements 2021 | 145
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
2021
2020
25,213
45,502
7,547
14,951
6,563
4,442
22,852
43,217
7,215
16,744
5,062
5,210
104,218
100,300
2021
2020
2019
4,603
1,226
6,953
605
4,392
1,059
6,832
716
4,059
1,035
7,558
603
13,387
12,999
13,255
2021
2020
24,890
39,335
5,957
70,182
24,092
39,698
5,985
69,775
146 | TC Energy Consolidated Financial Statements 2021
5. REVENUES
Disaggregation of Revenues
year ended December 31, 2021
(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
4,432
4,139
576
2,025
—
11,172
Power generation
Natural gas storage and other1
Other revenues2,3
—
87
4,519
—
—
1,057
5,196
37
4,519
5,233
—
29
605
—
605
—
5
2,030
276
2,306
324
278
602
122
724
324
1,456
12,952
435
13,387
1
2
3
Includes $87 million of fee revenues from an affiliate related to development and construction of the Coastal GasLink pipeline project which is 35 per cent
owned by TC Energy as at December 31, 2021. Refer to Note 28, Acquisitions and dispositions, for additional information.
Other revenues include income from the Company's marketing activities, financial instruments and lease arrangements. Refer to Note 9, Leases, and Note 26,
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 12,
Rate-regulated businesses, for additional information.
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
Natural gas storage and other1
Other revenues2,3
—
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 was related to the construction of the Sur de Texas pipeline which is 60 per cent
owned by TC Energy and $61 million was 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 28, Acquisitions and dispositions, for additional information.
Other revenues include income from the Company's marketing activities, financial instruments and lease arrangements. Refer to Note 9, Leases, and Note 26,
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 12,
Rate-regulated businesses, for additional information.
TC Energy Consolidated Financial Statements 2021 | 147
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 revenues1,2
—
—
—
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 9, Leases, and Note 26,
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 12,
Rate-regulated businesses, for additional information.
Contract Balances
at December 31
(millions of Canadian $)
Receivables from contracts with customers
Contract assets (Note 7)
Long-term contract assets (Note 14)
Contract liabilities1 (Note 16)
Long-term contract liabilities (Note 17)
2021
1,627
202
249
90
184
2020
Affected line item on the
Consolidated balance sheet
1,330
Accounts receivable
132
192
129
203
Other current assets
Other long-term assets
Accounts payable and other
Other long-term liabilities
1
During the year ended December 31, 2021, $15 million (2020 – $18 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, 2021, future revenues from long-term pipeline capacity arrangements and transportation as well as natural
gas storage and other contracts extending through 2049 are approximately $23.8 billion, of which approximately $3.4 billion is
expected to be recognized in 2022.
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.
148 | TC Energy Consolidated Financial Statements 2021
6. KEYSTONE XL
Asset Impairment Charge and Other
Following the revocation of the Presidential Permit for the Keystone XL pipeline project on January 20, 2021, and after a
comprehensive review of options in consultation with its partner, the Government of Alberta, on June 9, 2021, the Company
terminated the Keystone XL pipeline project. The Keystone XL investment was evaluated for impairment in 2021, along with
TC Energy's investments in related capital projects, including Heartland Pipeline, TC Terminals and Keystone Hardisty Terminal.
As a result, the Company determined that the carrying amount of these assets within the Liquids Pipelines segment was no
longer fully recoverable and recognized an asset impairment charge, net of expected contractual recoveries and other
contractual and legal obligations related to termination activities, of $2,775 million($2,134 million after tax) for the year ended
December 31, 2021. The asset impairment charge was based on the excess of the carrying value of $3,301 million over the
estimated fair value of $175 million. Termination activities and related costs will continue through 2022 with any adjustments to
the estimated fair value and future contractual and legal obligations expensed as determined.
year ended December 31, 2021
(millions of Canadian $)
Asset impairment charge
Plant and equipment
Related capital projects in development
Other capitalized costs
Capitalized interest
Other
Contractual recoveries
Contractual and legal obligations related to termination activities1
Estimated Fair Value
of Plant, Property
and Equipment
Asset impairment charge and other
Pre tax
After tax
175
—
—
—
175
n/a
n/a
175
412
230
2,158
326
3,126
(693)
342
2,775
312
175
1,642
248
2,377
(525)
282
2,134
1
In 2021, the Company paid $192 million towards contractual and legal obligations related to termination activities.
The estimated fair value of $175 million related to plant and equipment is based on the price that is expected to be received from
selling these assets in their current condition and is updated as required. Key assumptions used in the determination of selling
price included an estimated two-year disposal period and current energy market demand. The valuation considered a variety of
potential selling prices based on various markets that could be used to dispose of these assets and required the use of
unobservable inputs. As a result, the fair value is classified in Level III of the fair value hierarchy.
As the Company did not see the related capital projects in development proceeding at the time of the assessment in 2021, it
recorded an asset impairment charge equal to the carrying value of these projects included in Other long-term assets on the
Consolidated balance sheet as the estimated fair value of these related projects was determined to be nil.
Redeemable Non-Controlling Interest and Long-Term Debt
In March 2020, the Company announced that it would proceed with construction of the Keystone XL pipeline. As part of the
funding plan, the Government of Alberta invested $1,033 million in the form of Class A Interests in the year ended
December 31, 2020. 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. For the year ended December 31, 2020, 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.
TC Energy Consolidated Financial Statements 2021 | 149
On January 8, 2021, the Company exercised its call right in accordance with contractual terms and paid $633 million
(US$497 million) to repurchase the Government of Alberta Class A Interests in certain Keystone XL subsidiaries which were
classified as Current liabilities on the Consolidated balance sheet at December 31, 2020. This transaction was funded by draws on
the project-level credit facility. Following the revocation of the Presidential Permit for the Keystone XL pipeline project on
January 20, 2021, the Company ceased accruing a return on the remaining Government of Alberta Class A Interests.
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 was fully guaranteed by the Government of Alberta and non-recourse to the Company. For the year
ended December 31, 2021, the Company made draws under the Keystone XL project-level credit facility totaling $1,028 million
(US$849 million) and in accordance with the terms of the guarantee, the Government of Alberta repaid the full outstanding
balance in June 2021 and it was subsequently terminated. As part of this arrangement, TC Energy issued $91 million of Class C
Interests in the Keystone XL subsidiaries which entitle the Government of Alberta to future liquidation proceeds from specified
Keystone XL project assets. The Class C Interests of $91 million, net of $16 million of related distributions to the Government of
Alberta, were recorded in Accounts payable and other on the Consolidated balance sheet at December 31, 2021. Termination of
the project-level credit facility, net of the issuance of Class C Interests, resulted in $937 million ($737 million after tax) recorded
to Additional paid-in capital.
In June 2021, the Company repurchased the remaining Government of Alberta Class A Interests for a nominal amount, which was
accounted for as an equity transaction and resulted in $394 million recognized in Additional paid-in capital.
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
Net income/(loss) attributable to redeemable non-controlling interest1
Class A Interests repurchased
Class A Interests transferred to Current liabilities
Balance at end of year
2021
393
—
1
(394)
—
—
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 attributable to
non-controlling interests in the Consolidated statement of income.
7. OTHER CURRENT ASSETS
at December 31
(millions of Canadian $)
Keystone XL contractual recoveries (Note 6)
Cash provided as collateral
Contract assets (Note 5)
Fair value of derivative contracts (Note 26)
Keystone XL assets held for sale
Prepaid expenses
Regulatory assets (Note 12)
Other
150 | TC Energy Consolidated Financial Statements 2021
2021
2020
640
273
202
169
138
112
53
130
1,717
—
142
132
235
—
126
131
114
880
8. PLANT, PROPERTY AND EQUIPMENT
at December 31
(millions of Canadian $)
Canadian Natural Gas Pipelines
2021
2020
Cost
Accumulated
Depreciation
Net
Book Value
Cost
Accumulated
Depreciation
Net
Book Value
NGTL System
Pipeline
Compression
Metering and other
Under construction
Canadian Mainline
Pipeline
Compression
Metering and other
Under construction
Other Canadian Natural Gas Pipelines1
Other
Under construction
U.S. Natural Gas Pipelines
Columbia Gas
Pipeline
Compression
Metering and other
Under construction
ANR
Pipeline
Compression
Metering and other
Under construction
14,892
6,191
1,458
22,541
2,285
24,826
10,423
4,165
652
5,751
2,065
705
8,521
—
8,521
7,698
3,125
264
15,240
11,087
139
—
15,379
11,087
1,937
58
1,995
42,200
11,205
4,522
3,657
19,384
433
19,817
1,820
2,559
1,391
5,770
833
6,603
1,567
—
1,567
21,175
799
381
257
1,437
—
1,437
557
565
422
1,544
—
1,544
9,141
4,126
753
14,020
2,285
16,305
2,725
1,040
388
4,153
139
4,292
370
58
428
21,025
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
10,406
10,198
4,141
3,400
17,947
433
18,380
1,263
1,994
969
4,226
833
5,059
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
8,912
3,515
745
13,172
1,402
14,574
2,854
930
398
4,182
150
4,332
377
42
419
19,325
9,641
4,011
3,203
16,855
1,070
17,925
1,173
1,657
901
3,731
431
4,162
TC Energy Consolidated Financial Statements 2021 | 151
at December 31
2021
2020
(millions of Canadian $)
Other U.S. Natural Gas Pipelines
Columbia Gulf
GTN
Great Lakes
Other2
Under construction
Mexico Natural Gas Pipelines
Pipeline
Compression
Metering and other
Under construction
Liquids Pipelines
Keystone Pipeline System
Pipeline
Pumping equipment
Tanks and other
Under construction3
Intra-Alberta Pipelines
Power and Storage
Natural Gas
Natural Gas Storage and Other
Under construction
Corporate
Cost
Accumulated
Depreciation
Net
Book Value
Cost
Accumulated
Depreciation
Net
Book Value
2,749
2,701
2,162
1,755
9,367
533
9,900
36,320
2,957
480
626
4,063
2,590
6,653
9,209
1,020
3,534
13,763
72
13,835
199
14,034
1,267
797
2,064
5
2,069
836
178
1,071
1,255
657
3,161
—
3,161
6,142
476
80
155
711
—
711
1,758
252
737
2,747
—
2,747
14
2,761
605
216
821
—
821
320
2,571
1,630
907
1,098
6,206
533
6,739
2,638
2,330
2,117
1,568
8,653
389
9,042
30,178
33,536
2,481
400
471
3,352
2,590
5,942
7,451
768
2,797
11,016
72
11,088
185
2,952
480
624
4,056
2,525
6,581
9,254
1,025
3,522
13,801
2,870
16,671
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
9
2,487
1,322
894
990
5,693
389
6,082
28,169
2,541
411
491
3,443
2,525
5,968
7,675
797
2,878
11,350
2,870
14,220
189
11,273
16,869
2,460
14,409
662
581
1,243
5
1,248
516
1,255
780
2,035
11
2,046
993
569
194
763
—
763
372
686
586
1,272
11
1,283
621
102,112
31,930
70,182
99,372
29,597
69,775
1
2
3
Includes Foothills, Ventures LP and Great Lakes Canada.
Includes Portland, North Baja, Tuscarora, Crossroads and mineral rights.
Following the revocation of the Presidential Permit for the Keystone XL pipeline project on January 20, 2021, the Company recognized a pre-tax asset
impairment charge of $3,126 million, of which $2,896 million was related to Keystone XL assets under construction and $230 million was related to associated
capital projects in development. Refer to Note 6, Keystone XL, for additional information.
152 | TC Energy Consolidated Financial Statements 2021
9. 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 $)
Operating lease cost1
Sublease income
Net operating lease cost
1
Includes short-term leases and variable lease costs.
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
2021
105
(8)
97
2021
69
32
2021
9 years
3.5%
2020
124
(13)
111
2020
77
14
2020
10 years
3.5%
2021
2020
63
60
58
55
54
213
503
(74)
429
72
61
59
58
54
269
573
(90)
483
TC Energy Consolidated Financial Statements 2021 | 153
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 17)
2021
49
380
429
2020
56
427
483
As at December 31, 2021, the carrying value of the ROU assets recorded under operating leases was $415 million
(2020 – $473 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. The
Company has long-term PPAs for the sale of power from these assets which expire between 2024 and 2026.
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, 2021 was
$126 million (2020 – $130 million; 2019 – $180 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
2021
2020
113
111
110
94
70
—
498
119
111
109
109
94
70
612
The cost and accumulated depreciation for facilities accounted for as operating leases was $812 million and $340 million,
respectively, at December 31, 2021 (2020 – $858 million and $327 million, respectively).
154 | TC Energy Consolidated Financial Statements 2021
10. EQUITY INVESTMENTS
(millions of Canadian $)
Canadian Natural Gas Pipelines
TQM1
Coastal GasLink1,2
U.S. Natural Gas Pipelines
Northern Border3
Millennium
Iroquois4
Other
Mexico Natural Gas Pipelines
Sur de Texas5
Liquids Pipelines
Grand Rapids1,6
Northern Courier1,7
Port Neches Link LLC1,8
HoustonLink Pipeline1
Power and Storage
Bruce Power1,9
Portlands Energy Centre1,10
TransCanada Turbines11
Ownership
Interest at
December 31,
2021
Income from Equity
Investments
Equity
Investments
year ended December 31
at December 31
2021
2020
2019
2021
2020
50.0%
35.0%
50.0%
47.5%
50.0%
Various
12
—
80
91
55
18
12
—
100
96
52
16
60.0%
160
213
50.0%
nil
95.0%
50.0%
48.4%
nil
100.0%
54
16
—
1
411
—
—
898
53
22
—
—
439
12
4
1,019
12
—
91
92
54
27
3
56
14
—
—
527
35
9
920
118
386
505
474
392
137
90
211
521
482
197
120
835
680
980
—
103
18
998
53
—
19
4,493
3,306
—
—
—
—
8,441
6,677
1
2
3
4
5
6
7
8
9
10
11
Classified as a non-consolidated VIE. Refer to Note 30, Variable interest entities, for additional information.
In May 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 28, Acquisitions and dispositions, for additional
information. At December 31, 2021, the difference between the carrying value of the investment and the underlying equity in the net assets of Coastal GasLink
Pipeline Limited Partnership was $167 million (2020 – $188 million) due mainly to the fair value assessment of assets at the time of partial monetization along
with deferred development fee revenue accounting.
At December 31, 2021, the difference between the carrying value of the investment and the underlying equity in the net assets of Northern Border was
US$115 million (2020 – US$116 million) due mainly to the fair value assessment of assets at the time of acquisition.
At December 31, 2021, the difference between the carrying value of the investment and the underlying equity in the net assets of Iroquois was US$39 million
(2020 – US$39 million) due mainly to the fair value assessment of the assets at the times of acquisition.
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, 2021, the difference between the carrying value of the investment and the underlying equity in the net assets of Sur de Texas was
US$77 million (2020 – US$79 million) due mainly to the accounting for fees earned from the successful construction of the pipeline.
At December 31, 2021, the difference between the carrying value of the investment and the underlying equity in the net assets of Grand Rapids was $96 million
(2020 – $98 million) due mainly to interest capitalized during construction.
On November 30, 2021, TC Energy sold its remaining 15 per cent equity interest in Northern Courier. Refer to Note 28, 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 due mainly to the fair value of guarantees and the fair value assessment of assets at the time of partial monetization.
On March 8, 2021, TC Energy entered a joint venture with Motiva Enterprises to construct the Port Neches Link pipeline system. TC Energy has a 95 per cent
equity interest and, as a jointly-controlled entity, applies the equity method of accounting.
At December 31, 2021, the difference between the carrying value of the investment and the underlying equity in the net assets of Bruce Power was $755 million
(2020 – $796 million) due mainly to capitalized interest and the fair value assessment of assets at the time of acquisition.
In April 2020, TC Energy sold its investment in Portlands Energy Centre. Refer to Note 28, Acquisitions and dispositions, for additional information.
In November 2020, TC Energy purchased the remaining 50 per cent ownership in TransCanada Turbines which was subsequently consolidated. Refer to Note 28,
Acquisitions and dispositions, for additional information.
TC Energy Consolidated Financial Statements 2021 | 155
Distributions and Contributions
Distributions received from equity investments for the year ended December 31, 2021 were $1,048 million (2020 – $1,123 million;
2019 – $1,399 million). For the year ended December 31, 2021, $73 million (2020 – nil; 2019 – $186 million) was included in
Investing activities in the Consolidated statement of cash flows relating to TC Energy's proportionate share of the Sur de Texas
2021 partial debt repayment, and in 2019, included distributions received from Bruce Power and Northern Border from their
respective financing programs.
Contributions made to equity investments for the year ended December 31, 2021 were $1,210 million (2020 – $765 million;
2019 – $602 million) and were included in Investing activities in the Consolidated statement of cash flows. For 2019,
contributions of $32 million 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
2021
2020
2019
5,447
(3,293)
1,859
898
5,838
(3,341)
2,047
1,019
5,693
(3,408)
1,990
920
2021
2020
3,498
30,165
(2,540)
(16,400)
2,911
26,957
(3,727)
(15,309)
11. 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.
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, 2021, Loans receivable from affiliates under
Current assets on the Company's Consolidated balance sheet reflected a MXN$19.7 billion or $1.2 billion loan receivable from the
Sur de Texas joint venture which represents TC Energy's proportionate share of debt financing to the joint venture. At
December 31, 2020, this loan was recorded as Long-term loans receivable from affiliates on the Company's Consolidated balance
sheet and amounted to MXN$20.9 billion or $1.3 billion.
156 | TC Energy Consolidated Financial Statements 2021
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 $)
Interest income1
Interest expense2
Foreign exchange (losses)/gains1
Foreign exchange gains/(losses)1
1
2
Included in the Corporate segment.
Included in the Mexico Natural Gas Pipelines segment.
2021
87
(87)
(41)
41
2020
110
(110)
(86)
86
2019
Affected line item in the
Consolidated statement of income
147
Interest income and other
(147)
Income from equity investments
53
Interest income and other
(53)
Income from equity investments
Coastal GasLink Pipeline Limited Partnership
TC Energy holds a 35 per cent equity interest in Coastal GasLink Pipeline Limited Partnership (Coastal GasLink LP) and has been
contracted to develop and operate the Coastal GasLink pipeline.
Subordinated Demand Revolving Credit Facility
The Company has a subordinated demand revolving credit facility with Coastal GasLink LP to provide additional short-term
liquidity and funding flexibility to the project. The facility bears interest at a floating market-based rate and had a capacity of
$500 million at December 31, 2021 with an outstanding balance of $1 million (December 31, 2020 – nil) reflected in Loans
receivable from affiliates under Current assets on the Company's Consolidated balance sheet.
Subordinated Loan Agreement
On December 6, 2021, the Company entered into a subordinated loan agreement with Coastal GasLink LP to provide interim
temporary financing, if necessary, of up to $3,275 million to fund incremental project costs as a bridge to a required increase in
the project-level financing. Financing available to Coastal GasLink LP under this agreement is provided through a combination of
interest-bearing facilities subject to floating market-based rates and non-interest-bearing facilities that are subject to a return to
the Company under certain conditions at the time the final cost of the project is determined. At December 31, 2021, Long-term
loans receivable from affiliates on the Company’s Consolidated balance sheet reflected $238 million in amounts outstanding
under the subordinated loan agreement.
12. RATE-REGULATED BUSINESSES
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, 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.
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 Consolidated Financial Statements 2021 | 157
TC Energy's Canadian natural gas transmission services are supplied under natural gas transportation tariffs that provide for cost
recovery, including return of and 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.
NGTL System
The NGTL System currently operates under the terms of the 2020-2024 Revenue Requirement Settlement which includes an
ROE of 10.1 per cent on 40 per cent deemed common equity, the opportunity to increase depreciation rates if tolls fall below
specified levels and an incentive mechanism for certain operating costs where variances from projected amounts are shared
between the NGTL System and its customers.
NGTL System's 2019 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 40 per cent deemed common equity, 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 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.
In April 2020, the CER approved the six-year unanimous negotiated settlement (2021-2026 Mainline Settlement) effective
January 1, 2021. 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. 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 and the Company will
commence amortization over the remaining settlement term when predetermined thresholds per the settlement agreement are
met.
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). The U.S.
corporate income tax rate was reduced from 35 per cent to 21 per cent in 2017 as a result of U.S. Tax Reform. The U.S. regulated
operations, where applicable, established regulatory liabilities amortized over the remaining average useful lives of the
underlying property for the differences between the amounts previously recovered in rates and the expected deferred tax
liabilities.
158 | TC Energy Consolidated Financial Statements 2021
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$2.6 billion from
2013-2020 to modernize the Columbia Gas system thereby improving system integrity and enhancing service reliability and
flexibility.
In July 2020, Columbia Gas filed a general NGA Section 4 Rate Case with FERC requesting an increase on its maximum
transportation rates to be effective February 1, 2021, subject to refund on completion of the rate proceeding. On
October 29, 2021, Columbia Gas filed a petition with FERC requesting approval of the Stipulation and Agreement of Settlement
(Columbia Gas Settlement) that reflects a rate case settlement with its customers and, if approved, will increase Columbia Gas’
maximum rates effective February 1, 2021. On December 17, 2021, the presiding Administrative Law Judge recommended the
settlement for approval and certified it as uncontested to FERC for its review and approval. The Columbia Gas Settlement
(a) extends Columbia’s modernization program allowing for the cost recovery and return on additional investment of up to
US$1.2 billion over a four-year period through 2024 (b) establishes a rate case and tariff filing moratorium through April 1, 2025
and (c) requires Columbia Gas to file a general rate case under Section 4 of the NGA with new rates to be effective no later than
April 1, 2026.
ANR Pipeline
ANR Pipeline operates under rates established through a FERC-approved rate settlement in 2016. To meet terms of the 2016
settlement, on January 28, 2022, ANR Pipeline filed a Section 4 Rate Case with FERC requesting an increase to maximum
transportation rates effective August 1, 2022, subject to refund. As the rate process progresses, the Company expects to engage
in a collaborative process to achieve settlement with its customers, FERC and other stakeholders.
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.
Great Lakes
Great Lakes operates under a settlement approved by FERC in February 2018 which does not include a moratorium. However,
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.
As a result of the 2018 FERC Actions, Great Lakes made a limited NGA Section 4 filing and reduced rates by two per cent effective
February 1, 2019.
Gas Transmission Northwest
Gas Transmission Northwest (GTN) operates under a settlement approved by FERC in November 2018. GTN and its customers
agreed upon a moratorium on further rate changes until December 31, 2021 and GTN is required to have new rates in effect on
January 1, 2022.
On September 29, 2021, GTN filed a rate settlement (2021 GTN Settlement) which was approved by FERC on November 18, 2021,
extending the Company’s existing maximum transportation rates at their current levels, with GTN’s annual depreciation rates
remaining unchanged. The 2021 GTN Settlement contains a moratorium until December 31, 2023, at which point GTN will be
required to file for new rates to become effective no later than April 1, 2024.
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.
TC Energy Consolidated Financial Statements 2021 | 159
Regulatory Assets and Liabilities
at December 31
(millions of Canadian $)
Regulatory Assets
Deferred income taxes1
Pensions and other post-retirement benefits1,2
Foreign exchange on long-term debt1,3
Operating and debt-service regulatory assets4
Other
Less: Current portion included in Other current assets (Note 7)
Regulatory Liabilities
Pipeline abandonment trust balances5
Deferred income taxes – U.S. Tax Reform6
Canadian Mainline bridging amortization account7
Cost of removal8
Canadian Mainline long-term adjustment account7,9
Deferred income taxes1
Canadian Mainline short-term adjustment and toll-stabilization accounts7,9,10
ANR post-employment and retirement benefits other than pension11
Operating and debt-service regulatory liabilities4
Pensions and other post-retirement benefits2
Other
Less: Current portion included in Accounts payable and other (Note 16)
2021
2020
Remaining
Recovery/
Settlement
Period
(years)
1,509
203
3
1
104
1,820
53
1,767
2,086
1,141
483
254
186
139
60
40
32
13
66
4,500
200
4,300
1,287
401
7
54
135
1,884
131
1,753
1,842
1,170
537
246
223
115
4
40
48
18
58
4,301
153
4,148
n/a
n/a
1-8
1
n/a
n/a
n/a
9
n/a
5
n/a
n/a
n/a
1
n/a
n/a
1
2
3
4
5
6
7
8
9
10
11
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.
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.
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.
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.
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.
These regulatory accounts are used to capture revenue and cost variances plus toll-stabilization adjustments during the 2015-2030 settlement term.
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.
Under the terms of the 2021-2026 Mainline Settlement, $223 million is amortized over the six-year settlement term and the residual of $4 million was
transferred to the STAA at December 31, 2020.
Under the terms of the 2021-2026 Mainline Settlement, the STAA account will commence amortization over the remainder of the six-year settlement term
when predetermined thresholds per the settlement agreement are met.
This balance represents the amount ANR estimates it 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, 2021 is subject to resolution through future regulatory proceedings and, accordingly, a settlement period
cannot be determined at this time.
160 | TC Energy Consolidated Financial Statements 2021
13. GOODWILL
The Company has recorded the following Goodwill on its acquisitions:
(millions of Canadian $)
Balance at January 1, 2020
Foreign exchange rate changes
Balance at December 31, 2020
Foreign exchange rate changes
Balance at December 31, 2021
U.S. Natural
Gas Pipelines
12,887
(208)
12,679
(97)
12,582
As part of the annual goodwill impairment assessment at December 31, 2021, the Company evaluated qualitative factors
impacting the fair value of the underlying reporting units for all its reporting units other than the Columbia reporting unit. It was
determined that it was more likely than not that the fair value of these reporting units exceeded their carrying amounts,
including goodwill.
The Company elected to proceed directly to a quantitative annual goodwill impairment test at December 31, 2021 for the
$9,303 million of goodwill related to the Columbia reporting unit following an uncontested rate case settlement with shippers in
2021. It was determined that the fair value of Columbia exceeded its carrying value, including goodwill at December 31, 2021.
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 28, Acquisitions and dispositions, for additional details.
14. OTHER LONG-TERM ASSETS
at December 31
(millions of Canadian $)
Deferred income tax assets (Note 18)
Employee post-retirement benefits (Note 25)
Long-term contract assets (Note 5)
Keystone XL contractual recoveries (Note 6)
Fair value of derivative contracts (Note 26)
Capital projects in development1
Other
2021
2020
509
312
249
50
48
14
221
1,403
177
207
192
—
41
231
131
979
1
Following the revocation of the Presidential Permit for the Keystone XL pipeline project on January 20, 2021, the Company recognized a pre-tax asset
impairment charge of $3,126 million, of which $2,896 million was related to Keystone XL assets under construction and $230 million was related to associated
capital projects in development. Refer to Note 6, Keystone XL, for additional information.
TC Energy Consolidated Financial Statements 2021 | 161
15. NOTES PAYABLE
2021
2020
(millions of Canadian $, unless otherwise noted)
Outstanding at
December 31
Canada1
U.S. (2021 – US$54; 2020 – US$900)
Mexico (2021 – US$115; 2020 – US$150)2
4,953
68
145
5,166
Weighted
Average
Interest Rate
per Annum
at December 31
0.4%
0.3%
1.7%
Outstanding at
December 31
2,836
1,149
191
4,176
Weighted
Average
Interest Rate
per Annum
at December 31
0.4%
0.4%
1.7%
1
2
At December 31, 2021, Notes payable consisted of Canadian dollar-denominated notes of $1,989 million (2020 – $656 million) and U.S. dollar-denominated
notes of US$2,341 million (2020 – US$1,709 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, 2021 and 2020, Notes payable reflects short-term borrowings in Canada by TransCanada PipeLines Limited
(TCPL), in the U.S. by TransCanada PipeLine USA Ltd. (TCPL USA) and in Mexico by a wholly-owned Mexican subsidiary.
At December 31, 2021, total committed revolving and demand credit facilities were $12.4 billion (2020 – $12.4 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)
2021
Borrower
Description
Matures
Total
Facilities
Unused
Capacity 1
2020
Total
Facilities
Committed, syndicated, revolving, extendible, senior unsecured credit facilities2:
TCPL
Supports TCPL's Canadian dollar
commercial paper program and for general
corporate purposes
December
2026
TCPL / TCPL USA / Columbia /
TransCanada American
Investments Ltd.
TCPL / TCPL USA / Columbia /
TransCanada American
Investments Ltd.
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
2022
For general corporate purposes of the
borrowers, guaranteed by TCPL
December
2024
3.0
1.0
3.0
US 4.5
US 2.1
US 4.5
US 1.0
US 1.0
US 1.0
Demand senior unsecured revolving credit facilities2:
TCPL / TCPL USA
Supports the issuance of letters of credit
and provides additional liquidity; TCPL USA
facility guaranteed by TCPL
Demand
2.1 3
1.0
2.1 3
Mexico subsidiary
For Mexico general corporate purposes,
guaranteed by TCPL
Demand
MXN 5.0 3
MXN 2.6
MXN 5.0 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, 2021, the Company was in compliance with all debt covenants.
Or the U.S. dollar equivalent.
For the year ended December 31, 2021, the cost to maintain the above facilities was $17 million (2020 – $21 million;
2019 – $11 million).
162 | TC Energy Consolidated Financial Statements 2021
16. ACCOUNTS PAYABLE AND OTHER
at December 31
(millions of Canadian $)
Trade payables
Fair value of derivative contracts (Note 26)
Regulatory liabilities (Note 12)
Contract liabilities (Note 5)
Class C Interests (Note 6)
Other
17. OTHER LONG-TERM LIABILITIES
at December 31
(millions of Canadian $)
Operating lease obligations (Note 9)
Long-term contract liabilities (Note 5)
Employee post-retirement benefits (Note 25)
Asset retirement obligations
Fair value of derivative contracts (Note 26)
Other
18. INCOME TAXES
Provision for Income Taxes
year ended December 31
(millions of Canadian $)
Current
Canada
Foreign1
Deferred
Canada
Foreign
Income Tax Expense
2021
4,183
221
200
90
75
330
2020
3,057
72
153
129
—
405
5,099
3,816
2021
2020
380
184
174
61
47
213
1,059
427
203
503
54
59
229
1,475
2021
2020
2019
29
276
305
(327)
142
(185)
120
(54)
306
252
(224)
166
(58)
194
84
615
699
(29)
84
55
754
1
The 2019 current foreign income tax expense mainly relates to the sale of certain Columbia Midstream assets in August 2019. Refer to Note 28, 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
2021
(292)
2,458
2,166
2020
691
4,416
5,107
2019
1,144
4,043
5,187
TC Energy Consolidated Financial Statements 2021 | 163
2021
2,166
23.0%
498
(8)
(230)
(139)
(70)
—
—
—
32
37
120
2020
5,107
24.0%
1,226
(400)
(258)
(228)
(141)
—
(62)
—
7
50
194
2019
5,187
26.5%
1,375
(259)
(180)
(159)
(78)
(32)
(28)
154
13
(52)
754
2021
2020
1,163
1,389
537
130
—
46
1,876
229
1,647
5,616
1,219
333
112
7,280
5,633
532
154
48
70
2,193
243
1,950
6,124
1,087
287
81
7,579
5,629
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 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
Impact of Mexico inflationary adjustments
Other
Income Tax Expense
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
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
164 | TC Energy Consolidated Financial Statements 2021
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 14)
Deferred Income Tax Liabilities
Deferred income tax liabilities
Net Deferred Income Tax Liabilities
2021
2020
509
177
6,142
5,633
5,806
5,629
At December 31, 2021, the Company has recognized the benefit of non-capital loss carryforwards of $4,067 million
(2020 – $3,671 million) for federal and provincial purposes in Canada, which expire from 2030 to 2041. The Company has not yet
recognized the benefit of capital loss carryforwards of $21 million (2020 – $253 million) for federal and provincial purposes in
Canada which have no expiry date. The Company also has Ontario minimum tax credits of $113 million (2020 – $106 million),
which expire from 2026 to 2041.
At December 31, 2021, the Company has fully recognized the benefit of net operating loss carryforwards of US$446 million
(2020 – US$849 million) for federal purposes in the U.S., which expire in 2037.
At December 31, 2021, the Company has recognized the benefit of net operating loss carryforwards of US$10 million
(2020 – US$13 million) in Mexico, which expire from 2024 to 2031.
TC Energy recorded an income tax valuation allowance of $229 million and $243 million against the deferred income tax asset
balances at December 31, 2021 and 2020, respectively. 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, 2021, 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.
At December 31, 2020, the Company recorded $400 million in valuation allowance releases 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 per cent equity interest in Coastal GasLink LP. Refer to Note 28, Acquisitions and
dispositions, for additional information on the sale of the Ontario natural gas-fired power plants and Coastal GasLink LP equity
sale.
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, 2021 by approximately
$896 million (2020 – $684 million) if there had been a provision for these taxes.
TC Energy Consolidated Financial Statements 2021 | 165
Income Tax Payments
Income tax payments of $371 million, net of refunds, were made in 2021 (2020 – payments, net of refunds, of $252 million;
2019 – payments, net of refunds, of $713 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
2021
2020
2019
52
5
(1)
26
(2)
80
29
26
(2)
1
(2)
52
19
13
(1)
—
(2)
29
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, 2021 reflects $1 million interest expense (2020 – $4 million; 2019 – $4 million). At
December 31, 2021, the Company had accrued $12 million in interest expense (2020 – $11 million; 2019 – $7 million). The
Company incurred no penalties associated with income tax uncertainties related to Income tax expense for the years ended
December 31, 2021, 2020 and 2019 and no penalties were accrued as at December 31, 2021, 2020 and 2019.
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 2013. 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, except as further described below.
Mexico Tax Audit
In 2019, the Mexican tax authority, Tax Administration Services (SAT), completed an audit of the 2013 tax return of one of the
Company’s subsidiaries in Mexico. The audit resulted in a tax assessment which denied the deduction for all interest expense and
an assessment of additional tax, penalties and financial charges totaling less than US$1 million. The Company disagreed with this
assessment and commenced litigation. In January 2022, the Company received the tax court’s ruling on the 2013 tax return,
which was in favour of the SAT. The Company believes this ruling is unreasonable and did not conform with Mexican tax
regulations and will appeal this decision. In support of the Company’s position, the Mexican Tax Ombudsman (the PRODECON),
previously determined that this subsidiary’s tax filings were appropriate.
From September 2021 to February 2022, the SAT issued assessments for tax years 2014 through 2017 which denied the deduction
of all interest expense as well as assessed incremental withholding tax on the interest. These assessments totaled approximately
US$490 million in tax, interest, penalties and financial charges. If the SAT continues to reassess the tax filings of this subsidiary
for subsequent years on a similar basis, there is a risk of a material increase to the Company’s exposure.
Based on recent discussions with the SAT, the Company believes that the areas of concern are confined to a subset of matters
within these assessments. The Company will defend its position on these assessments and pursue all available legal tax remedies.
Based on the Company’s own judgment, as well as that of third-party advisors, management believes it is more likely than not
that the Company’s tax position will be sustained and no provision with respect to this matter has been recognized in the
consolidated financial statements.
166 | TC Energy Consolidated Financial Statements 2021
19. LONG-TERM DEBT
Outstanding amounts
(millions of Canadian $, unless otherwise noted)
TRANSCANADA PIPELINES LIMITED
Debentures
U.S. (2021 – nil; 2020 – US$400)
Medium Term Notes
Canadian
Senior Unsecured Notes
2021
2020
Maturity
Dates
Outstanding at
December 31
Interest
Rate1
Outstanding at
December 31
Interest
Rate1
—
—
510
9.9%
2022 to 2049
12,491
4.2%
11,491
4.5%
U.S. (2021 – US$16,542; 2020 – US$14,292)
2022 to 2049
20,936
33,427
4.8%
18,227
30,228
5.3%
NOVA GAS TRANSMISSION LTD.
Debentures and Notes
Canadian
U.S. (2021 and 2020 – US$200)
Medium Term Notes
Canadian
U.S. (2021 and 2020 – US$33)
COLUMBIA PIPELINE GROUP, INC.
Senior Unsecured Notes
2024
2023
2025 to 2030
2026
9.9%
7.9%
7.4%
7.5%
100
254
504
41
899
9.9%
7.9%
7.4%
7.5%
100
255
504
42
901
U.S. (2021 and 2020 – US$1,500)2
2025 to 2045
1,898
4.9%
1,913
4.9%
TC PIPELINES, LP
Unsecured Term Loan
U.S. (2021 – nil; 2020 – US$450)
Senior Unsecured Notes
U.S. (2021 – US$850; 2020 – US$1,200)
2025 to 2027
ANR PIPELINE COMPANY
Senior Unsecured Notes
—
—
574
1.4%
1,076
1,076
4.2%
1,530
2,104
4.4%
U.S. (2021 – US$372; 2020 – US$672)
2024 to 2026
472
5.3%
858
7.2%
GAS TRANSMISSION NORTHWEST LLC
Senior Unsecured Notes
U.S. (2021 and 2020 – US$325)
2030 to 2035
411
4.3%
415
4.3%
TC Energy Consolidated Financial Statements 2021 | 167
Outstanding amounts
(millions of Canadian $, unless otherwise noted)
PORTLAND NATURAL GAS TRANSMISSION SYSTEM
Unsecured Loan Facility
2021
2020
Maturity
Dates
Outstanding at
December 31
Interest
Rate1
Outstanding at
December 31
Interest
Rate1
U.S. (2021 – nil; 2020 – US$25)
2023
—
—
32
1.3%
Senior Unsecured Notes
U.S. (2021 – US$250; 2020 – US$125)
2030 to 2031
GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP
Senior Unsecured Notes
2.8%
316
316
2.8%
159
191
U.S. (2021 – US$167; 2020 – US$198)
2028 to 2030
211
7.6%
253
7.6%
TUSCARORA GAS TRANSMISSION COMPANY
Unsecured Term Loan
U.S. (2021 – US$36; 2020 – US$23)
2024
46
1.3%
29
2.2%
NORTH BAJA PIPELINE, LLC
Unsecured Term Loan
U.S. (2021 – nil; 2020 – US$50)
Current portion of long-term debt
Unamortized debt discount and issue costs
Fair value adjustments3
—
—
64
1.2%
38,756
(1,320)
(243)
148
37,341
36,956
(1,972)
(238)
167
34,913
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.
Related to the acquisition of Columbia.
Principal Repayments
At December 31, 2021, 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
2022
1,320
2023
1,823
2024
2,657
2025
2,698
2026
1,778
168 | TC Energy Consolidated Financial Statements 2021
Long-Term Debt Issued
The Company issued long-term debt over the three years ended December 31, 2021 as follows:
(millions of Canadian $, unless otherwise noted)
Company
Issue Date
Type
Maturity Date
Amount
TRANSCANADA PIPELINES LIMITED
October 2021
Senior Unsecured Notes
October 2024
US 1,250
October 2021
Senior Unsecured Notes
October 2031
US 1,000
June 2021
June 2021
June 2021
April 2020
April 2020
Medium Term Notes
Medium Term Notes
June 2024
June 2031
Medium Term Notes
September 2047
Senior Unsecured Notes
Medium Term Notes
April 2030
April 2027
September 2019 Medium Term Notes
September 2029
September 2019 Medium Term Notes
July 2048
750
500
250
US 1,250
2,000
700
300
Interest
Rate
1.00%
2.50%
Floating
2.97%
4.33% 1
4.10%
3.80%
3.00%
4.18% 2
PORTLAND NATURAL GAS TRANSMISSION SYSTEM
April 2019
Medium Term Notes
October 2049
1,000
4.34%
October 2021
Senior Unsecured Notes
October 2031
October 2020
Senior Unsecured Notes
October 2030
US 125
US 125
2.68%
2.84%
TUSCARORA GAS TRANSMISSION COMPANY
August 2021
Unsecured Term Loan
August 2024
US 13
Floating
KEYSTONE XL SUBSIDIARIES3
COLUMBIA PIPELINE GROUP, INC.4
GAS TRANSMISSION NORTHWEST LLC
Various
Project-Level Credit Facility
June 2021
US 849
Floating
January 2021
Unsecured Term Loan
June 2022
US 4,040
Floating
June 2020
Senior Unsecured Notes
June 2030
US 175
3.12%
COASTAL GASLINK PIPELINE LIMITED PARTNERSHIP5
NORTHERN COURIER PIPELINE LIMITED PARTNERSHIP6
April 2020
Senior Secured Credit Facilities
April 2027
1,603
Floating
July 2019
Senior Secured Notes
June 2042
1,000
3.365%
1
2
3
4
5
6
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 4.186 per cent.
Reflects coupon rate on re-opening of a pre-existing MTN issue. The MTNs were issued at a premium to par, resulting in a re-issuance yield of 3.991 per cent.
On January 4, 2021, the Company established a US$4.1 billion project-level credit facility to support the construction of the Keystone XL pipeline, which was
fully guaranteed by the Government of Alberta and non-recourse to TC Energy. The availability of this credit facility was subsequently reduced to US$1.6 billion
and all amounts outstanding were fully repaid by the Government of Alberta in June 2021. Refer to Note 6, Keystone XL, for additional information.
In December 2020, Columbia entered into a US$4.2 billion Unsecured Term Loan agreement. In January 2021, US$4.0 billion was drawn on the Unsecured Term
Loan and the total availability under the loan agreement was reduced accordingly. The loan was fully repaid and retired in December 2021.
In April 2020, Coastal GasLink LP entered into secured long-term project financing credit facilities. In May 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 28, 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 accounted for its remaining interest using the equity method. On November 30, 2021, the Company sold its remaining 15 per cent equity interest
in Northern Courier. Refer to Note 28, Acquisitions and dispositions, for additional information.
TC Energy Consolidated Financial Statements 2021 | 169
Long-Term Debt Retired/Repaid
The Company retired/repaid long-term debt over the three years ended December 31, 2021 as follows:
(millions of Canadian $, unless otherwise noted)
Company
TRANSCANADA PIPELINES LIMITED
COLUMBIA PIPELINE GROUP, INC.
NORTH BAJA PIPELINE, LLC
TC PIPELINES, LP
ANR PIPELINE COMPANY
Retirement/
Repayment Date
Type
Amount
Interest Rate
November 2021
Medium Term Notes
January 2021
Debentures
November 2020
Debentures
500
US 400
250
October 2020
Senior Unsecured Notes
US 1,000
March 20201
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
US 750
US 700
US 550
13
100
US 750
US 400
December 2021
Unsecured Term Loan2
June 2020
Senior Unsecured Notes
US 4,040
US 750
3.65%
9.875%
11.80%
3.80%
4.60%
2.125%
Floating
9.35%
10.50%
7.125%
3.125%
Floating
3.30%
December 2021
Unsecured Term Loan
US 50
Floating
November 2021
Unsecured Term Loan
March 2021
Senior Unsecured Notes
June 2019
Unsecured Term Loan
US 450
US 350
US 50
Floating
4.65%
Floating
November 2021
Senior Unsecured Notes
US 300
9.625%
GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP
November 2021
Senior Unsecured Notes
US 10
9.09%
PORTLAND NATURAL GAS TRANSMISSION SYSTEM
KEYSTONE XL SUBSIDIARIES3
GAS TRANSMISSION NORTHWEST LLC
October 2021
Unsecured Loan Facility
October 2020
Unsecured Loan Facility
US 93
US 99
Floating
Floating
June 2021
Project-Level Credit Facility
US 849
Floating
June 2020
May 2019
Senior Unsecured Notes
Unsecured Term Loan
US 100
US 35
5.29%
Floating
1
2
3
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.
In December 2020, Columbia entered into a US$4.2 billion Unsecured Term Loan agreement. In January 2021, US$4.0 billion was drawn on the Unsecured Term
Loan and the total availability under the loan agreement was reduced accordingly. The loan was fully repaid and retired in December 2021. Related unamortized
debt issue costs of $5 million were included in Interest expense in the Consolidated statement of income for the year ended December 31, 2021.
In June 2021, in accordance with the terms of the guarantee, the Government of Alberta repaid the US$849 million outstanding balance under the
Keystone XL project-level credit facility bearing interest at a floating rate, subsequent to which it was terminated, resulting in no cash impact to TC Energy.
Refer to Note 6, Keystone XL, for additional information.
170 | TC Energy Consolidated Financial Statements 2021
On March 4, 2021, the Company's subsidiary, TC PipeLines, LP, terminated its US$500 million Unsecured Loan Facility bearing
interest at a floating rate on which no amount was outstanding.
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
Amortization and other financial charges1
2021
1,841
453
10
(22)
78
2020
1,963
470
46
(294)
43
2019
1,931
427
106
(186)
55
2,360
2,228
2,333
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.
The Company made interest payments of $2,299 million in 2021 (2020 – $2,203 million; 2019 – $2,295 million) on long-term
debt, junior subordinated notes and short-term debt, net of interest capitalized.
20. JUNIOR SUBORDINATED NOTES
Outstanding loan amount
(millions of Canadian $, unless otherwise noted)
Maturity
Date
Outstanding at
December 31
Effective
Interest Rate1
Outstanding at
December 31
Effective
Interest Rate1
2021
2020
TRANSCANADA PIPELINES LIMITED
US$1,000 notes issued 2007 at 6.35%2
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
$500 notes issued 2021 at 4.45%3,4
Unamortized debt discount and issue costs
2067
2075
2076
2077
2077
2079
2081
4.0%
5.0%
5.8%
4.7%
4.5%
5.4%
4.0%
1,265
949
1,519
1,899
1,500
1,392
500
9,024
(85)
8,939
1,275
957
1,530
1,913
1,500
1,403
—
8,578
(80)
8,498
4.1%
5.0%
5.8%
4.7%
4.5%
5.4%
—
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.
TC Energy Consolidated Financial Statements 2021 | 171
In March 2021, TransCanada Trust (the Trust) issued $500 million of Trust Notes – Series 2021-A to investors with a fixed interest
rate of 4.20 per cent per annum for the first 10 years and resetting on the 10th anniversary and every five years thereafter. All of
the proceeds of the issuance by the Trust were loaned to TCPL for $500 million of junior subordinated notes of TCPL at an initial
fixed rate of 4.45 per cent per annum, including a 0.25 per cent administration charge. The rate on the junior subordinated
notes of TCPL will reset every five years commencing March 2031 until March 2051 to the then Five-Year Government of Canada
Yield, as defined in the document governing the subordinated notes, plus 3.316 per cent per annum; from March 2051 until
March 2081, the interest rate will reset to the then Five-Year Government of Canada Yield plus 4.066 per cent per annum. The
junior subordinated notes are callable at TCPL's option at any time from December 4, 2030 to March 4, 2031 and on each interest
payment and reset date thereafter at 100 per cent of the principal amount plus accrued and unpaid interest to the date of
redemption.
In September 2019, 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 per annum 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 3, Accounting changes, for additional information
regarding the expected impact to the Company with certain rate settings of LIBOR which ceased to be published at the end of
2021 with full cessation 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.
21. NON-CONTROLLING INTERESTS
TC PipeLines, LP
Acquisition
In December 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. Upon
close of the transaction on March 3, 2021, TC PipeLines, LP common unitholders received 0.70 TC Energy common shares for each
issued and outstanding publicly-held TC PipeLines, LP common unit representing, in aggregate, 37,955,093 TC Energy common
shares. As a result, TC PipeLines, LP became an indirect, wholly-owned subsidiary of TC Energy.
As the Company controlled TC PipeLines, LP, this acquisition was accounted for as an equity transaction with the following
impact reflected on the Consolidated balance sheet:
(millions of Canadian $)
Common shares
Additional paid-in-capital
Accumulated other comprehensive loss
Non-controlling interests
Deferred income tax liabilities
Other
172 | TC Energy Consolidated Financial Statements 2021
March 3, 2021
2,063
(398)
353
(1,563)
(443)
(12)
Non-controlling interests
Prior to the March 3, 2021 acquisition described above, the non-controlling interests in TC PipeLines, LP were 74.5 per cent
(2020 and 2019 – 74.5 per cent). Subsequent to this acquisition, the remaining non-controlling interest on the Consolidated
balance sheet is related to the Company's 61.7 per cent investment in Portland Natural Gas Transmission System (PNGTS), which
is held by TC PipeLines, LP.
The Company's Net income attributable to non-controlling interests included in the Consolidated statement of income were
as follows:
year ended December 31
(millions of Canadian $)
Non-controlling interest in TC PipeLines, LP
Non-controlling interest in PNGTS
Redeemable non-controlling interest (Note 6)
22. COMMON SHARES
Outstanding at January 1, 2019
Dividend reinvestment and share purchase plan
Exercise of options
Outstanding at December 31, 2019
Exercise of options
Outstanding at December 31, 2020
Acquisition of TC PipeLines, LP, net of transaction costs (Note 21)
Exercise of options
Outstanding at December 31, 2021
2021
2020
2019
60
30
1
91
284
23
(10)
297
270
23
—
293
Number of Shares
Amount
(thousands)
(millions of Canadian $)
918,097
15,165
5,138
938,400
1,664
940,064
37,955
2,797
980,816
23,174
931
282
24,387
101
24,488
2,063
165
26,716
Common Shares Issued and Outstanding
The Company is authorized to issue an unlimited number of common shares without par value.
Acquisition of TC PipeLines, LP
On March 3, 2021, TC Energy issued 37,955,093 common shares to acquire all the outstanding publicly-held common units of
TC PipeLines, LP. Refer to Note 21, Non-controlling interests, for additional information.
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.
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. From January 1, 2019
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.
TC Energy Corporation At-the-Market Equity Issuance Program
In December 2020, the Company established an At-the-Market Program (ATM Program) that allows, 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 is effective for a 25-month period and will be utilized as appropriate to assist in managing the Company's capital
structure. Under this program the Company could issue up to $1.0 billion in common shares or the U.S. dollar equivalent. No
common shares were issued under this program in 2021 or 2020.
TC Energy Consolidated Financial Statements 2021 | 173
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, 2021
Options granted
Options exercised
Options forfeited/expired
Options Outstanding at December 31, 2021
Options Exercisable at December 31, 2021
2021
973
974
2020
940
940
2019
929
931
Number of
Options
(thousands)
Weighted
Average
Exercise Prices
Weighted
Average
Remaining
Contractual Life
(years)
8,996
1,679
(2,797)
(109)
7,769
4,410
$59.55
$56.86
$53.10
$59.96
$61.29
$60.13
4.2
3.2
At December 31, 2021, an additional 4,826,189 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
Expected life (years)1
Interest rate
Volatility2
Dividend yield
2021
$7.39
5.4
0.5%
25%
6.0%
2020
$7.73
5.7
1.5%
17%
4.2%
2019
$6.37
5.7
1.9%
19%
5.0%
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.
The amount expensed for stock options, with a corresponding increase in Additional paid-in capital was $12 million in 2021
(2020 – $12 million; 2019 – $13 million). At December 31, 2021, unrecognized compensation costs related to non-vested stock
options were $13 million. The cost is expected to be fully recognized over a weighted average period of 1.8 years.
174 | TC Energy Consolidated Financial Statements 2021
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
2021
28
110
2020
31
101
2019
75
143
1.9 million
2.0 million
2.1 million
As at December 31, 2021, the aggregate intrinsic value of the total options exercisable was $7 million and the aggregate intrinsic
value of options outstanding was $12 million.
Shareholder Rights Plan
TC Energy's Shareholder Rights Plan is designed to provide the Board of Directors (Board) 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.
23. PREFERRED SHARES
at
December 31,
2021
Number of
Shares
Outstanding
(thousands)
Cumulative First Preferred Shares
Current
Yield
Annual
Dividend
Per Share1,2
Redemption
Price Per
Share
Redemption and
Conversion Option
Date
Right to
Convert
Into
Carrying Value
December 313
2021
2019
2020
(millions of Canadian $)
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
$25.00
December 31, 2024
Series 2
360
360
360
7,423
Floating
9,997
1.694%
4,003
Floating
12,071
1.949%
1,929
Floating
4
4
5
4
Floating
$25.00
December 31, 2024
Series 1
179
179
179
$0.4235
Floating
$25.00
$25.00
June 30, 2025
Series 4
246
246
209
June 30, 2025
Series 3
97
97
134
$0.48725
$25.00
January 30, 2026
Series 6
294
310
310
Floating
$25.00
January 30, 2026
Series 5
48
32
32
24,000
3.903%
$0.97575
$25.00
April 30, 2024
Series 8
589
589
589
18,000
3.762%
$0.9405
$25.00
October 30, 2024
Series 10
442
442
442
10,000
3.351%
$0.83775
$25.00
November 28, 2025
Series 12
244
244
244
—
—
—
—
—
—
—
493
493
40,000
4.90%
$1.225
$25.00
May 31, 2022
Series 16
988
988
988
3,487 3,980 3,980
1
2
3
4
5
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), 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),
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 2.049 per cent for the period starting December 31, 2021 to, but excluding,
March 31, 2022. The floating quarterly dividend rate for the Series 4 preferred shares is 1.409 per cent for the period starting December 31, 2021 to, but
excluding, March 31, 2022. The floating quarterly dividend rate for the Series 6 preferred shares is 1.686 per cent for the period starting October 30, 2021 to,
but excluding, January 30, 2022. These rates will reset each quarter going forward.
The fixed rate dividend for Series 5 preferred shares decreased from 2.263 per cent to 1.949 per cent on January 30, 2021 and is due to reset on every fifth
anniversary thereafter.
TC Energy Consolidated Financial Statements 2021 | 175
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.
On May 31, 2021, TC Energy redeemed all 20,000,000 issued and outstanding Series 13 preferred shares at a redemption price of
$25.00 per share and paid the final quarterly dividend of $0.34375 per Series 13 preferred share for the period up to but
excluding May 31, 2021, as previously declared on May 6, 2021. The Company used the proceeds from the March 2021 issuance of
$500 million of Junior Subordinated Notes through the Trust to finance this preferred share redemption.
On February 1, 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.
176 | TC Energy Consolidated Financial Statements 2021
24. OTHER COMPREHENSIVE INCOME/(LOSS) AND ACCUMULATED OTHER COMPREHENSIVE LOSS
Components of other comprehensive income/(loss), including the portion attributable to non-controlling interests and related
tax effects, were as follows:
year ended December 31, 2021
(millions of Canadian $)
Before Tax
Amount
Income Tax
Recovery/
(Expense)
Net of Tax
Amount
Foreign currency translation gains and 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 income on equity investments
Other Comprehensive Income
(100)
(3)
(13)
68
208
20
714
894
(8)
1
3
(13)
(50)
(6)
(179)
(252)
(108)
(2)
(10)
55
158
14
535
642
year ended December 31, 2020
(millions of Canadian $)
Before Tax
Amount
Income Tax
Recovery/
(Expense)
Net of Tax
Amount
Foreign currency translation gains and 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
(609)
36
(583)
489
12
17
(280)
(918)
year ended December 31, 2019
(millions of Canadian $)
Before Tax
Amount
Income Tax
Recovery/
(Expense)
Net of Tax
Amount
Foreign currency translation gains and losses on net investment in foreign
operations
Reclassification 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
(944)
(13)
35
(62)
14
(10)
10
(82)
(1,052)
TC Energy Consolidated Financial Statements 2021 | 177
The changes in AOCI by component were as follows:
(millions of Canadian $)
AOCI balance at January 1, 2019
Other comprehensive loss before reclassifications2
Amounts reclassified from AOCI
Net current period other comprehensive loss
AOCI balance at December 31, 2019
Other comprehensive (loss)/income before reclassifications2
Amounts reclassified from AOCI
Net current period other comprehensive (loss)/income
AOCI balance at December 31, 2020
Other comprehensive (loss)/income before reclassifications2
Amounts reclassified from AOCI3
Net current period other comprehensive (loss)/income
Acquisition of TC PipeLines, LP4
AOCI balance at December 31, 2021
Currency
Translation
Adjustments
Cash Flow
Hedges
Pension and
Other Post-
Retirement
Benefit Plan
Adjustments
Equity
Investments
107
(824)
(13)
(837)
(730)
(543)
—
(543)
(1,273)
(98)
—
(98)
362
(1,009)
(23)
(49)
14
(35)
(58)
(567)
482
(85)
(143)
(11)
55
44
(13)
(112)
(314)
(10)
10
—
(314)
12
17
29
(285)
158
14
172
—
(376)
(86)
5
(81)
(457)
(292)
11
(281)
(738)
506
28
534
4
Total1
(606)
(969)
16
(953)
(1,559)
(1,390)
510
(880)
(2,439)
555
97
652
353
(113)
(200)
(1,434)
1
2
3
4
All amounts are net of tax. Amounts in parentheses indicate losses recorded to OCI.
Other comprehensive (loss)/income before reclassifications on currency translation adjustments, cash flow hedges and equity investments are net of
non-controlling interest losses of $12 million (2020 – losses of $30 million; 2019 – losses of $85 million), gains of $1 million (2020 – losses of $16 million;
2019 – losses of $13 million), and gains of $1 million (2020 – gains of $1 million; 2019 – losses of $1 million ), 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 $62 million
($47 million, net of tax) at December 31, 2021. 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.
Represents the AOCI attributable to non-controlling interests of TC PipeLines, LP which was reclassified to AOCI on the Consolidated balance sheet upon
completion of the acquisition of all the outstanding publicly-held common units of TC PipeLines, LP on March 3, 2021. Refer to Note 21, Non-controlling
interests, for additional information.
178 | TC Energy Consolidated Financial Statements 2021
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 gain
Equity investments
Equity income
Currency translation adjustments
Foreign currency translation gains on disposal of foreign
operations
Amounts Reclassified
From AOCI
2021
2020
2019
Affected Line Item in the Consolidated
Statement of Income1
(22)
(46)
—
(68)
13
(55)
(22)
2
(20)
6
(14)
(37)
9
(28)
—
—
—
(1)
(28)
(613)
(642)
160
(482)
(23)
—
(23)
6
(17)
(15)
4
(11)
—
—
—
(7) Revenues (Power and Storage)
(12)
Interest expense
— Net gain/(loss) on assets sold/held for sale2
(19) Total before tax
5
Income tax expense2
(14) Net of tax3
(14) Plant operating costs and other4
— Plant operating costs and other4
(14) Total before tax
4
Income tax expense
(10) Net of tax
(8)
Income from equity investments
3
Income tax expense
(5) Net of tax3
13 Net gain/(loss) on assets sold/held for sale
—
Income tax expense
13 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 28, Acquisitions and dispositions, for additional information.
Amounts reclassified from AOCI on cash flow hedges are net of non-controlling interest of nil (2020 – losses of $7 million; 2019 – nil).
These AOCI components are included in the computation of net benefit cost. Refer to Note 25, Employee post-retirement benefits, for additional information.
TC Energy Consolidated Financial Statements 2021 | 179
25. 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
ten years at December 31, 2021 (2020 and 2019 – 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, 2021 (2020 and 2019 – 11 years). In 2021, the
Company expensed $58 million (2020 – $58 million; 2019 – $61 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
2021
105
8
58
171
2020
124
9
58
191
2019
122
22
61
205
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 $20 million letter of credit to the Canadian DB Plan in 2021 (2020 – $13 million; 2019 – $12 million), resulting
in a total of $322 million provided to the Canadian DB Plan under letters of credit at December 31, 2021.
The most recent actuarial valuation of the pension plans for funding purposes was as at January 1, 2021 and the next required
valuation will be as at January 1, 2022.
In mid-2021, the Company offered a one-time Voluntary Retirement Program (VRP) to eligible employees. Participants in the
program retired by December 31, 2021 and received a transition payment along with existing retirement benefits. In 2021, the
Company expensed $81 million mainly related to VRP transition payments which were included in Plant operating costs and
other. In addition, $18 million was recorded in Revenues related to costs that are recoverable through regulatory and tolling
structures on a flow-through basis.
As a result of employee participation in the VRP, a settlement and curtailment occurred for the U.S. DB Plan in December 2021.
The impact of these amounts were determined using actuarial assumptions consistent with those employed at
December 31, 2021. The settlement gain decreased the U.S. DB Plan's unrealized actuarial gain by $2 million which was included
in OCI, while the curtailment gain decreased the U.S. DB Plan's benefit obligation by $5 million, both of which were recorded in
net benefit cost in 2021.
Employee participation in the VRP also resulted in a curtailment in the U.S. other post-retirement benefits plan (OPEB) in
December 2021. The curtailment loss decreased the Plan's unrealized actuarial gain by $3 million which was included in OCI and
increased the OPEB obligation by $3 million, resulting in no adjustment to net benefit cost in 2021.
180 | TC Energy Consolidated Financial Statements 2021
The Company's funded status at December 31 was comprised of the following:
at December 31
Pension
Benefit Plans
Other Post-Retirement
Benefit Plans
(millions of Canadian $)
2021
2020
2021
2020
Change in Benefit Obligation1
Benefit obligation – beginning of year
Service cost
Interest cost
Employee contributions
Benefits paid
Actuarial (gain)/loss
Curtailment
Foreign exchange rate changes
Benefit obligation – end of year
Change in Plan Assets
4,326
4,058
171
119
6
(372)
(208)
(5)
(10)
155
133
6
(249)
242
—
(19)
4,027
4,326
Plan assets at fair value – beginning of year
4,038
3,693
Actual return on plan assets
Employer contributions2
Employee contributions
Benefits paid
Foreign exchange rate changes
Plan assets at fair value – end of year
Funded Status – Plan Surplus/(Deficit)
376
105
6
(372)
(8)
4,145
118
485
124
6
(249)
(21)
4,038
(288)
457
6
12
1
(21)
(35)
3
(4)
419
441
5
8
1
(21)
(3)
431
12
427
6
14
—
(21)
36
—
(5)
457
406
56
9
—
(21)
(9)
441
(16)
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 $20 million letter of credit provided to the Canadian DB Plan for funding purposes (2020 – $13 million).
The actuarial gain realized on the defined benefit plan obligation is primarily attributable to an increase in the weighted average
discount rate from 2.70 per cent in 2020 to 3.05 per cent in 2021.
The actuarial gain realized on the other post-retirement benefit plan obligation is primarily due to the increase in the weighted
average discount rate from 2.75 per cent in 2020 to 3.10 per cent in 2021.
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 14)
Accounts payable and other
Other long-term liabilities (Note 17)
Pension
Benefit Plans
Other Post-Retirement
Benefit Plans
2021
119
—
(1)
118
2020
29
—
(317)
(288)
2021
193
(8)
(173)
12
2020
178
(8)
(186)
(16)
TC Energy Consolidated Financial Statements 2021 | 181
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 $)
Projected benefit obligation1
Plan assets at fair value
Funded Status – Plan Deficit
Pension
Benefit Plans
Other Post-Retirement
Benefit Plans
2021
(2,687)
2,686
(1)
2020
(3,292)
2,975
(317)
2021
(183)
—
(183)
2020
(194)
—
(194)
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
2021
(3,714)
4,145
431
2020
(3,957)
4,038
81
The Company's DB Plans with respect to accumulated benefit obligations and the fair value of plan assets were fully funded as at
December 31, 2021 and 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
2021
34%
53%
13%
100%
2020
33%
57%
10%
100%
Target
Allocations
2021
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
2021
7
5
2020
13
5
Percentage of
Plan Assets
2021
0.2%
0.1%
2020
0.3%
0.1%
182 | TC Energy Consolidated Financial Statements 2021
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.
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 26, Risk management and financial instruments.
at December 31
Quoted Prices in
Active Markets
(Level I)
Significant Other
Observable Inputs
(Level II)
Significant
Unobservable
Inputs
(Level III)
Total
Percentage of
Total Portfolio
(millions of Canadian $)
2021
2020
2021
2020
2021
2020
2021
2020
2021
2020
Asset Category
Cash and Cash Equivalents
68
87
2
—
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
269
649
126
111
25
—
—
—
—
276
594
114
116
35
—
—
—
—
433
444
—
67
6
—
42
—
—
—
—
—
72
8
—
47
—
—
—
—
Funds held on deposit
150
145
148
164
354
313
120
226
331
16
147
15
1
177
211
380
368
125
207
283
13
151
14
2
143
143
7
73
5
—
—
—
—
—
6
48
4
—
—
—
(8)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
283
281
1
—
—
213
203
1
—
—
70
87
2
2
417
813
480
424
145
226
331
16
147
448
1
210
13
73
47
283
281
1
—
453
805
494
484
160
207
283
13
151
458
2
215
14
48
51
213
203
1
(8)
150
145
9
18
10
9
3
5
7
—
4
10
—
5
10
18
11
11
4
5
6
—
3
10
—
5
—
—
2
1
6
6
—
—
3
1
1
5
5
—
—
3
1,946
1,938
2,065
2,124
565
417
4,576
4,479
100
100
TC Energy Consolidated Financial Statements 2021 | 183
The following table presents the net change in the Level III fair value category:
(millions of Canadian $, pre-tax)
Balance at December 31, 2019
Purchases and sales
Realized and unrealized losses
Balance at December 31, 2020
Purchases and sales
Realized and unrealized gains
Balance at December 31, 2021
379
42
(4)
417
100
48
565
The Company's expected funding contributions in 2022 are approximately $76 million for the DB Plans, approximately $7 million
for the other post-retirement benefit plans and approximately $55 million for the savings plans and DC Plans. The Company
expects to provide an additional estimated $20 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 $)
2022
2023
2024
2025
2026
2027 to 2031
Pension Benefits
Other Post-Retirement
Benefits
208
211
216
220
224
1,171
25
25
24
24
24
114
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, 2021. 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
2021
3.05%
2.95%
2020
2.70%
2.60%
2021
3.10%
—
2020
2.75%
—
The significant weighted average actuarial assumptions adopted in measuring the Company's net benefit plan costs were
as follows:
year ended December 31
Pension
Benefit Plans
Other Post-Retirement
Benefit Plans
2021
2020
2019
2021
2020
2019
Discount rate
Expected long-term rate of return on plan assets
Rate of compensation increase
2.70%
6.15%
2.60%
3.20%
6.40%
3.00%
3.90%
6.60%
3.00%
2.80%
3.00%
—
3.35%
3.50%
—
4.10%
4.30%
—
184 | TC Energy Consolidated Financial Statements 2021
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 5.60 per cent weighted-average annual rate of increase in the per capita cost of covered health care benefits was assumed for
2022 measurement purposes. The rate was assumed to decrease gradually to 5.00 per cent by 2029 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:
year ended December 31
(millions of Canadian $)
Service cost1
Other components of net benefit cost1
Interest cost
Expected return on plan assets
Amortization of actuarial loss
Amortization of regulatory asset
Curtailment gain
Settlement gain – AOCI
Net Benefit Cost Recognized
Pension
Benefit Plans
Other Post-Retirement
Benefit Plans
2021
171
119
(234)
23
27
(5)
(2)
(72)
99
2020
155
133
(230)
21
25
—
—
(51)
104
2019
126
142
(222)
12
14
—
—
(54)
72
2021
2020
2019
6
6
5
12
(13)
2
2
—
—
3
9
14
(14)
2
2
—
—
4
10
17
(15)
2
2
—
—
6
11
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:
at December 31
2021
2020
2019
(millions of Canadian $)
Pension
Benefits
Other Post-
Retirement
Benefits
Pension
Benefits
Other Post-
Retirement
Benefits
Pension
Benefits
Other Post-
Retirement
Benefits
Net loss
147
5
358
22
398
20
Pre-tax amounts recognized in OCI were as follows:
at December 31
2021
2020
2019
(millions of Canadian $)
Amortization of net loss from
AOCI to net income
Curtailment
Settlement
Funded status adjustment
Pension
Benefits
Other Post-
Retirement
Benefits
Pension
Benefits
Other Post-
Retirement
Benefits
Pension
Benefits
Other Post-
Retirement
Benefits
(23)
—
2
(190)
(211)
(2)
3
—
(18)
(17)
(21)
—
—
(18)
(39)
(2)
—
—
3
1
(12)
—
—
52
40
(2)
—
—
(37)
(39)
TC Energy Consolidated Financial Statements 2021 | 185
26. 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 its 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, internal audit and business segment 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- 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, cash flows 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 the Company's exposure to market risk resulting from commodity price risk
management activities 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 businesses, TC Energy manages the exposure to fluctuating commodity prices through long-term
contracts and hedging activities including selling and purchasing electricity 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.
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 the Company's asset base and/or re-contract with TC Energy's shippers and customers as contractual agreements expire.
Climate change also presents a potential financial impact to commodity prices and volumes. TC Energy's exposure to climate
change risk and resulting policy changes is managed through the Company's business model, which is based on a long-term,
low-risk strategy whereby the majority of TC Energy's earnings are underpinned by regulated cost-of-service arrangements
and/or long-term contracts. In addition, scenario planning against several demand outlooks and monitoring of key signposts is
also considered as part of the Company's long-term corporate strategic planning process.
186 | TC Energy Consolidated Financial Statements 2021
Interest rate risk
TC Energy utilizes short- 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 short-term debt including 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 U.S. dollar LIBOR,
of which certain rate settings have ceased to be published at the end of 2021 with full cessation by mid-2023. Refer to Note 3,
Accounting changes, for additional information on Reference Rate Reform.
Foreign exchange risk
Certain of TC Energy's businesses generate all or most of their earnings in U.S. dollars and, 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 basis up to three
years in advance 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 in foreign operations
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 interest rate swaps, foreign exchange forwards and foreign exchange options as appropriate.
The fair values and notional amounts for the derivatives designated as a net investment hedge were as follows:
at December 31
2021
2020
(millions of Canadian $, unless otherwise noted)
U.S. dollar foreign exchange options (maturing 2022 to 2023)
U.S. dollar cross-currency interest rate swaps (maturing 2022 to 2025)3
Fair
Value1,2
Notional
Amount
Fair
Value1,2
(4)
23
19
US 3,800
US 400
US 4,200
45
23
68
Notional
Amount
US 2,200
US 400
US 2,600
1
2
3
Fair value equals carrying value.
No amounts have been excluded from the assessment of hedge effectiveness.
In 2021, Net income includes net realized gains of $1 million (2020 – gains of $1 million) 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)
2021
2020
Notional amount
Fair value
30,700 (US 24,200)
27,700 (US 21,800)
35,500 (US 28,100)
33,800 (US 26,500)
TC Energy Consolidated Financial Statements 2021 | 187
Counterparty Credit Risk
TC Energy's exposure to counterparty credit risk includes its cash and cash equivalents, accounts receivable and certain
contractual recoveries, 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 and communication with those counterparties
experiencing greater financial pressures.
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, 2021 and 2020, 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, Loans receivable from affiliates,
Other current assets, Long-term loans receivable from affiliates, Restricted investments, Other long-term assets, Notes payable,
Accounts payable and other, 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 19)
Junior subordinated notes (Note 20)
2021
2020
Carrying
Amount
(38,661)
(8,939)
(47,600)
Fair
Value
Carrying
Amount
(45,615)
(9,236)
(54,851)
(36,885)
(8,498)
(45,383)
Fair
Value
(46,054)
(8,908)
(54,962)
188 | TC Energy Consolidated Financial Statements 2021
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 securities2,3
Maturing within 1 year
Maturing within 1-5 years
Maturing within 5-10 years
Maturing after 10 years
Fair value of equity securities2,4
2021
2020
LMCI Restricted
Investments
Other Restricted
Investments1
LMCI Restricted
Investments
Other Restricted
Investments1
—
8
1,150
84
817
2,059
26
107
—
—
—
133
—
—
985
85
736
1,806
17
66
—
—
—
83
1
2
3
4
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
2021
2020
2019
(millions of Canadian $)
Net unrealized gains/(losses)
Net realized gains3
LMCI
restricted
investments1
Other
restricted
investments2
LMCI
restricted
investments1
Other
restricted
investments2
LMCI
restricted
investments1
Other
restricted
investments2
45
3
(2)
—
130
20
1
1
32
60
3
—
1
2
3
Gains 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 as regulatory assets.
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.
TC Energy Consolidated Financial Statements 2021 | 189
Balance Sheet Presentation of Derivative Instruments
The balance sheet classification of the fair value of derivative instruments was as follows:
at December 31, 2021
(millions of Canadian $)
Other current assets (Note 7)
Commodities2
Foreign exchange
Other long-term assets (Note 14)
Commodities2
Foreign exchange
Interest rate3
Total Derivative Assets
Accounts payable and other (Note 16)
Commodities2
Foreign exchange
Interest rate3
Other long-term liabilities (Note 17)
Commodities2
Foreign exchange
Interest rate3
Total Derivative Liabilities
Total Derivatives
Cash Flow
Hedges
Net
Investment
Hedges
Held for
Trading
Total Fair
Value of
Derivative
Instruments1
—
—
—
—
—
2
2
2
(23)
—
(10)
(33)
(4)
—
(8)
(12)
(45)
(43)
—
10
10
—
32
—
32
42
—
(4)
—
(4)
—
(19)
—
(19)
(23)
19
122
37
159
8
6
—
14
173
(138)
(46)
—
(184)
(6)
(10)
—
(16)
(200)
(27)
122
47
169
8
38
2
48
217
(161)
(50)
(10)
(221)
(10)
(29)
(8)
(47)
(268)
(51)
1
2
3
Fair value equals carrying value.
Includes purchases and sales of power, natural gas and liquids.
For the year ended December 31, 2021, a $10 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.
190 | TC Energy Consolidated Financial Statements 2021
The balance sheet classification of the fair value of derivative instruments was as follows:
at December 31, 2020
(millions of Canadian $)
Other current assets (Note 7)
Commodities2
Foreign exchange
Other long-term assets (Note 14)
Foreign exchange
Total Derivative Assets
Accounts payable and other (Note 16)
Commodities2
Foreign exchange
Interest rate3
Other long-term liabilities (Note 17)
Commodities2
Interest rate3
Total Derivative Liabilities
Total Derivatives
Cash Flow
Hedges
Net
Investment
Hedges
Total Fair
Value of
Derivative
Instruments1
Held for
Trading
—
—
—
—
—
—
(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.
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.
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, 2021
Purchases1
Sales1
Millions of U.S. dollars
Millions of Mexican pesos
Maturity dates
Power
Natural Gas
Liquids
Foreign
Exchange
Interest Rate
553
1,043
—
—
104
52
—
—
34
38
—
—
—
—
6,636
5,500
—
—
650
—
2022-2026
2022-2027
2022
2022-2026
2024-2026
1
Volumes for power, natural gas and liquids derivatives are in GWh, Bcf and MMBbls, respectively.
TC Energy Consolidated Financial Statements 2021 | 191
at December 31, 2020
Purchases1
Sales1
Millions of U.S. dollars
Millions of Mexican pesos
Maturity dates
Power
Natural Gas
Liquids
Foreign
Exchange
Interest Rate
185
1,786
—
—
13
14
—
—
26
30
—
—
—
—
4,432
1,700
—
—
1,100
—
2021-2025
2021-2027
2021
2021-2022
2022-2026
1
Volumes for power, natural gas and liquids derivatives are in GWh, Bcf and MMBbls, respectively.
Unrealized and Realized Gains/(Losses) on Derivative Instruments
The following summary does not include hedges of the net investment in foreign operations:
year ended December 31
(millions of Canadian $)
Derivative instruments held for trading1
Amount of unrealized gains/(losses) in the year
Commodities
Foreign exchange
Amount of realized gains/(losses) in the year
Commodities
Foreign exchange
Derivative instruments in hedging relationships2
Amount of realized (losses)/gains in the year
Commodities
Interest rate
2021
2020
2019
9
(203)
287
240
(44)
(32)
(23)
126
183
(33)
6
(16)
(111)
245
378
(70)
(6)
2
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 2021, 2020 and 2019, 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.
Derivatives in cash flow hedging relationships
The components of OCI (Note 24) 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)
Change in fair value of derivative instruments recognized in OCI1
Commodities
Interest rate
2021
2020
2019
(35)
22
(13)
(5)
(766)
(771)
(15)
(63)
(78)
1
No amounts have been excluded from the assessment of hedge effectiveness. Amounts in parentheses indicate losses recorded to OCI and AOCI.
192 | TC Energy Consolidated Financial Statements 2021
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
Interest rate contracts1
Hedged items
Derivatives designated as hedging instruments
Cash Flow Hedges
Reclassification of losses on derivative instruments from AOCI to net income2,3
Interest rate contracts1
Commodity contracts4
2021
2020
2019
—
—
(46)
(22)
(3)
1
(648)
(1)
(19)
1
(12)
(7)
1
2
3
4
Presented within Interest expense in the Consolidated statement of income, except for a loss of $613 million recorded in May 2020 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 was included in Net gain/(loss) on assets
sold/held for sale. Refer to Note 28, Acquisitions and dispositions, for additional information.
Refer to Note 24, Other comprehensive income/(loss) 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.
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, 2021
(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 Offset1
Net Amounts
130
85
2
217
(171)
(79)
(18)
(268)
(91)
(54)
(1)
(146)
91
54
1
146
39
31
1
71
(80)
(25)
(17)
(122)
1
Amounts available for offset do not include cash collateral pledged or received.
TC Energy Consolidated Financial Statements 2021 | 193
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 Offset1
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.
With respect to the derivative instruments presented above, the Company provided cash collateral of $144 million and letters of
credit of $130 million at December 31, 2021 (2020 – $54 million and $15 million, respectively) to its counterparties. At
December 31, 2021, the Company held no cash collateral and a $6 million balance in letters of credit (2020 – 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.
Based on contracts in place and market prices at December 31, 2021, the aggregate fair value of all derivative instruments with
credit-risk-related contingent features that were in a net liability position was $5 million (2020 – $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, 2021, 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.
194 | TC Energy Consolidated Financial Statements 2021
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, 2021
(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
Significant
Unobservable
Inputs
Inputs
(Level III)1
(Level II)1
39
—
—
(49)
—
—
(10)
91
85
2
(116)
(79)
(18)
(35)
—
—
—
(6)
—
—
(6)
Total
130
85
2
(171)
(79)
(18)
(51)
1
There were no transfers from Level II to Level III for the year ended December 31, 2021.
TC Energy Consolidated Financial Statements 2021 | 195
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
Inputs
(Level II)1
Significant
Unobservable
Inputs
(Level III)1
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.
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
Total (losses)/gains included in Net income
Settlements
Balance at end of year1
2021
2020
(4)
(3)
1
(6)
(7)
3
—
(4)
1
Revenues include unrealized losses of $3 million attributed to derivatives in the Level III category that were still held at December 31, 2021 (2020 – unrealized
gains of $3 million).
27. CHANGES IN OPERATING WORKING CAPITAL
year ended December 31
(millions of Canadian $)
(Increase)/decrease in Accounts receivable
Increase in Inventories
Increase in Other current assets
Increase/(decrease) in Accounts payable and other
Decrease in Accrued interest
(Increase)/Decrease in Operating Working Capital
2021
(925)
(93)
(141)
890
(18)
(287)
2020
129
(55)
(221)
(162)
(18)
(327)
2019
31
(42)
(15)
352
(33)
293
196 | TC Energy Consolidated Financial Statements 2021
28. ACQUISITIONS AND DISPOSITIONS
Canadian Natural Gas Pipelines
Coastal GasLink LP
In May 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 included $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 incorporated 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 reflected the utilization of previously
unrecognized tax loss benefits. The pre-tax gain was included in Net gain/(loss) on assets sold/held for sale in the Consolidated
statement of income. As part of this transaction, TC Energy was 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.
Immediately preceding the equity sale, Coastal GasLink LP drew down $1.6 billion on the secured long-term project financing
credit facilities, of which approximately $1.5 billion was paid to TC Energy.
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 was not deductible for income tax purposes. The pre-tax gain was included in
Net gain/(loss) 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 was included in Net gain/(loss) on assets sold/held for sale in the
Consolidated statement of income. On an after-tax basis, the gain of $115 million reflected 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.
On November 30, 2021, TC Energy completed the sale of its remaining 15 per cent equity interest in Northern Courier to a third
party for gross proceeds of approximately $35 million resulting in a pre-tax gain of $13 million ($19 million after tax). The pre-tax
gain was included in Net gain/(loss) on assets sold/held for sale in the Consolidated statement of income.
TC Energy Consolidated Financial Statements 2021 | 197
Power and Storage
TransCanada Turbines Ltd.
In November 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
In April 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. The total pre-tax loss of $676 million ($470 million after tax) on this transaction included losses
accrued during 2019 while classified as an asset held for sale and a 2021 post-close adjustment and also reflected utilization of
previously unrecognized tax loss benefits. The pre-tax loss was included in Net gain/(loss)on assets sold/held for sale 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 May 2019, the Company completed the sale of its Coolidge generating station in Arizona to Salt River Project Agriculture
Improvement and Power District (SRP), the PPA counterparty, as per the terms of SRP’s contractual right of first refusal, 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 was included in Net gain/(loss) on assets sold/held for sale in the Consolidated
statement of income.
198 | TC Energy Consolidated Financial Statements 2021
29. 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 2021 were $239 million (2020 – $224 million; 2019 – $236 million).
The Company has entered into PPAs with solar and wind-power generating facilities ranging from eight to 15 years, that require
the purchase of 100 per cent of the generated energy and associated environmental attributes. Future payments cannot be
reasonably estimated as they are dependent on the amount of energy generated.
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, 2021, TC Energy had the following capital expenditure
commitments:
• approximately $1.5 billion for its Canadian natural gas pipelines, primarily related to construction costs associated with
NGTL System expansion projects
• approximately $0.1 billion for its U.S. natural gas pipelines, primarily related to construction costs associated with ANR and
Columbia Gas pipeline projects
• approximately $0.1 billion for its Mexico natural gas pipelines, primarily related to construction of the Tula and
Villa de Reyes pipelines
• approximately $0.1 billion for its Liquids pipelines, primarily related to capital projects in the U.S. Gulf Coast
• approximately $0.1 billion for its Power and Storage business, primarily related to the Company's proportionate share of
commitments for Bruce Power's life extension program.
Contingencies
TC Energy is subject to laws and regulations governing environmental quality and pollution control. As at December 31, 2021,
the Company had accrued approximately $30 million (2020 – $24 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, excluding the legal proceeding related to Keystone XL described below, will not have a material impact on the
Company's consolidated financial position or results of operations.
On November 22, 2021, TC Energy filed a Request for Arbitration to formally initiate a legacy North American Free Trade
Agreement (NAFTA) claim to recover economic damages resulting from the revocation of the Presidential Permit for the
Keystone XL pipeline project. The Company will be seeking to recover more than US$15 billion in damages as a result of the
U.S. Government's breach of its NAFTA obligations. This claim is in a preliminary stage and the timing of outcome is unknown at
present.
Guarantees
On November 30, 2021, TC Energy completed the sale of its remaining 15 per cent equity interest in the Northern Courier pipeline
and subsequently released all associated guarantees. Refer to Note 28, Acquisitions and dispositions, for additional information.
As part of its role as operator of the Northern Courier pipeline prior to the sale, TC Energy had guaranteed the financial
performance of the pipeline related to delivery and terminalling of bitumen and diluent and contingent financial obligations
under sub-lease agreements.
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.
TC Energy Consolidated Financial Statements 2021 | 199
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 Other long-term liabilities on the Consolidated balance sheet.
Information regarding the Company’s guarantees were as follows:
at December 31
(millions of Canadian $)
Sur de Texas
Bruce Power
Other jointly-owned entities
Northern Courier pipeline2
Term
to 2043
to 2023
to 2043
2021
Potential
Exposure1
Carrying Value
2020
Potential
Exposure1
Carrying Value
93
88
80
—
261
—
—
4
—
4
100
88
78
300
566
—
—
4
26
30
1
2
TC Energy's share of the potential estimated current or contingent exposure.
On November 30, 2021, TC Energy completed the sale of its remaining 15 per cent equity interest in the Northern Courier pipeline and subsequently released all
associated guarantees. Refer to Note 28, Acquisitions and dispositions, for additional information.
200 | TC Energy Consolidated Financial Statements 2021
30. 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 current assets
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
2021
2020
72
70
28
13
183
3,672
890
421
—
5,166
232
—
17
29
278
66
1
13
2,025
2,383
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
TC Energy Consolidated Financial Statements 2021 | 201
At December 31, 2020, certain consolidated VIEs had a redeemable non-controlling interest that ranked above the Company's
equity interest. Refer to Note 6, Keystone XL, 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
2021
2020
Loan receivable from affiliate (Note 11)
1
—
Equity investments
Bruce Power
Pipeline equity investments and other1
Long-term loan receivable from affiliate (Note 11)
Off-balance sheet2
Coastal GasLink3
Bruce Power
Pipeline equity investments1
Maximum exposure to loss
4,493
1,605
238
3,037
974
171
10,519
3,306
1,371
—
1,107
1,183
399
7,366
1
2
3
On November 30, 2021, TC Energy sold its remaining 15 per cent equity interest in Northern Courier. Refer to Note 28, Acquisitions and dispositions, for
additional information.
Includes maximum potential exposure to guarantees and future funding commitments.
Represents the total capacity of $3,275 million committed under a subordinated loan agreement with Coastal GasLink LP less the $238 million balance
outstanding under this loan agreement as at December 31, 2021. Refer to Note 11, Loans receivable from affiliates, for additional information.
202 | TC Energy Consolidated Financial Statements 2021
Shareholder information
TC Energy welcomes questions from shareholders and investors.
Please contact:
Gavin Wylie
Vice-President, Investor Relations
Phone: 1-403-920-7911
Toll free: 1-800-361-6522
Email: investor_relations@tcenergy.com
Website: 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 15: TRP.PR.K
Join our online conversation
Facebook:
@TCEnergyCorporation
Instagram:
@TCEnergy
LinkedIn:
@TC Energy
Twitter:
@TCEnergy
Transfer agent
Computershare Investor Services, Inc.
100 University Avenue, 8th Floor, Toronto, ON
Canada, M5J 2Y1
Phone: 1-514-982-7959
Toll free: 1-800-340-5024
Fax: 1-888-453-0330
Email: tcenergy@computershare.com
Corporate head office
TC Energy Corporation
450 – 1st Street S.W. Calgary, AB
Canada, T2P 5H1
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Visit our website for more information:
TCEnergy.com
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TCEnergy.com/AnnualReport
Printed in Canada
February 2022