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2023
ANNUAL
REPORT
Delivering on our priorities
ANNUAL REPORT 2023
FINANCIAL
HIGHLIGHTS
24
CONSECUTIVE
YEARS OF
ANNUAL DIVIDEND
INCREASES
Comparable earnings per common share1
(dollars)
Comparable EBITDA1 (millions of dollars)
Comparable earnings1 (millions of dollars)
2021
2022
2023
4.26
4.30
4.52
2021
2022
2023
9,368
9,901
10,988
2021
2022
2023
4,142
4,279
4,652
Net income per common share (dollars)
Total segmented earnings
(millions of dollars)
Net income attributable to common shares
(millions of dollars)
2021
2022
2023
1.87
0.64
2021
2022
2023
2.75
4,059
3,632
2021
2022
2023
6,136
1,815
641
2,829
Comparable funds generated from
operations1 (millions of dollars)
Net cash provided by operations
(millions of dollars)
Dividends declared per common share
(dollars)
2021
2022
2023
7,406
7,353
7,980
2021
2022
2023
6,890
6,375
7,268
2021
2022
2023
3.48
3.60
3.72
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
2024E
2000
2023
1 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 2023 Annual MD&A (incorporated by reference herein) for more information and
a reconciliation to the U.S. GAAP equivalents.
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 2023 Annual Report filed with Canadian securities regulators, the U.S. Securities and Exchange
Commission and available at TCEnergy.com.
ABOUT
TC ENERGY
DELIVERING RESULTS – PROVIDING ENERGY SOLUTIONS
We’re a team of 7,000+ energy problem solvers working
to safely move, generate and store the energy North
America relies on. Today, we’re delivering solutions
to the world’s toughest energy challenges – from
innovating to deliver the natural gas that feeds LNG
to global markets, to working to reduce emissions
from our assets, to partnering with our neighbours,
customers and governments to build the energy system
of the future. It’s all part of how we continue to deliver
sustainable returns for our investors and create value
for communities.
TC Energy’s common shares trade on the Toronto (TSX)
and New York (NYSE) stock exchanges under the symbol
TRP. To learn more, visit us at TCEnergy.com.
OUR VALUES
Our corporate values form the foundation of how we
do business.
SAFETY
INNOVATION
RESPONSIBILITY
COLLABORATION
INTEGRITY
DELIVERING ENERGY SUSTAINABLY
Our industry is experiencing unprecedented change
as we collectively tackle the central challenge that
unites us all: meeting growing global energy demand
while reducing GHG emissions. TC Energy is working to
solve this problem as we deliver responsibly produced
energy every day.
Our highly integrated asset base delivers energy
across Canada, the U.S. and Mexico. TC Energy’s
assets enable the global export of LNG, one of the
most immediate and enduring solutions for displacing
and reducing global emissions. We also have power
assets and opportunities anchored by our investment
in Bruce Power, the largest operating nuclear facility
in the world. We are proud to invest in safe, reliable,
affordable energy that enables the energy transition.
We continue to focus on our sustainability
commitments, which reflect the topics most relevant
to our business and stakeholders and help position
us for long-term success. To learn more about our
role in the energy transition and how we engrain
sustainability within our business decision-making,
please read our 2023 Report on Sustainability.
LAND ACKNOWLEDGEMENT
TC Energy acknowledges the Indigenous ancestral
lands on which the company operates across
North America and affirms our commitment to
understanding how the histories, cultures and
rich traditions of the peoples of these lands have
been shaped by the past, how they influence our
present and what we can learn to prosper together
in the future. We are committed to working with
the original keepers of the land to advance shared
ownership and prosperity.
1
1
DELIVERING RESULTS –
PROVIDING ENERGY
SOLUTIONS
A MESSAGE FROM JOHN AND FRANÇOIS
Our collective efforts in 2023 continued to set the stage
for a transformative period for TC Energy. Our leadership
team outlined clear strategic priorities, successfully
aligned our resources and continued to deliver strong
results. These efforts translated into another record year
for the company as we continued to safely and efficiently
move, generate and store the energy North America and
the world rely on.
2 Comparable EBITDA, Comparable earnings per share and Comparable funds generated
from operations are non-GAAP measures used throughout this document. These
measures do not have any standardized meaning under GAAP and therefore are unlikely
to be comparable to similar measures presented by other companies. The most directly
comparable GAAP measures are segmented earnings (losses), net income (loss) per
common share and net cash provided by operations, respectively. Refer to the About
this document – Non-GAAP measures section of the 2023 Annual MD&A (incorporated
by reference) for more information about the non-GAAP measures we use and for a
reconciliation to the U.S. GAAP equivalent. Our 2023 Annual MD&A is available under
TC Energy’s profile on SEDAR+ at www.sedarplus.ca.
We leveraged our $100+ billion asset base and delivered
solid 2023 results for our shareholders, including:
Generating record comparable EBITDA2 of $11.0 billion,
11 per cent higher than 2022
Achieving record comparable earnings per share2 of
$4.52, five per cent higher than 2022
Producing comparable funds generated from
operations2 of $8.0 billion
Placing $5.3 billion of assets into service on budget
Safely and reliably achieving record throughput
volumes on our natural gas assets
Delivering strong availability across our power assets.
John Lowe
Chair of the Board
François Poirier
President and CEO
2
ANNUAL REPORT 2023 DELIVERING ON OUR
2023 PRIORITIES
PROJECT EXECUTION
Our team accomplished multiple milestones throughout
the year, including safely executing major projects and
bringing additional capacity projects into service. Notably,
we achieved mechanical completion ahead of our
year-end 2023 target on the Coastal GasLink pipeline
project, Canada’s first pipeline to the West Coast in
70 years and the country’s first direct path to global
LNG markets. This marked a monumental step forward
toward the export of LNG from Canada. Applying safety
and operational excellence and strong Indigenous and
community engagement along the way, we delivered
this nation-building infrastructure with over 55 million
hours worked. We applied learnings from this project
to our capital allocation process, project preparation
and execution and are already seeing strong results. In
Mexico, our Southeast Gateway pipeline project was the
first major project sanctioned under our revised process,
and the project continues to track to cost and schedule.
Highlighting our shared commitment to project execution,
Bruce Power announced the successful completion of
the Unit 6 Major Component Replacement on budget
and ahead of schedule, achieving a significant milestone
in Ontario’s largest clean-energy initiative and one of
Canada’s largest infrastructure projects.
During the year, we also placed $5.3 billion of assets
into service on budget, further supporting sustainable
comparable EBITDA growth.
ENHANCING BALANCE SHEET STRENGTH
To accelerate deleveraging, we completed our $5+ billion
asset divestiture program with the sale of a 40 per cent
non-controlling equity interest in our Columbia Gas and
Columbia Gulf systems to Global Infrastructure Partners
for total cash proceeds of $5.3 billion (US$3.9 billion).
Our teams continue to evaluate an incremental $3 billion
of capital rotation opportunities to further support our
deleveraging targets, which we aim to complete by the end
of 2024.
3 To learn more about our leadership positions, see page 7.
4 Net capital expenditures is a non-GAAP measure used throughout this document. This
measure does not have any standardized meaning under GAAP and therefore is unlikely
to be comparable to similar measures presented by other companies. The most directly
comparable GAAP measure is capital expenditures. Refer to the About this document
– Non-GAAP measures section of the 2023 Annual MD&A (incorporated by reference)
for more information about the non-GAAP measures we use. Our 2023 Annual MD&A is
available under TC Energy’s profile on SEDAR+ at www.sedarplus.ca.
MAXIMIZING THE VALUE OF OUR ASSETS
We continue to maximize the value and performance of
our assets through safe and reliable operations. Our 2023
comparable EBITDA was 11 per cent higher than 2022,
demonstrating that at every stage of the economic cycle,
our asset base continues to generate strong operational
and financial results.
In July 2023, following a two-year strategic review, our
Board of Directors approved our plans to spin off our
Liquids Pipelines business and separate into two industry-
leading, investment-grade companies. The separation of
our Natural Gas Pipelines and Power and Energy Solutions
businesses from our Liquids Pipelines business aims to
maximize the value of our assets and unlock the full
potential of our five leadership positions3 for shareholders.
TC Energy: A low-risk, diversified, growth-oriented
natural gas and power and energy solutions company,
uniquely positioned to meet growing industry and
consumer demand for reliable, lower-carbon energy
sources, including natural gas.
South Bow Corporation: A critical oil infrastructure
company, with an unrivalled market position to
connect resilient, safe and secure supply to the highest
demand markets with incremental growth and value
creation opportunities.
WHY INVEST: TC ENERGY
SHAREHOLDER VALUE
PROPOSITION
While our business continually evolves, our value
proposition remains unchanged:
Long-term view: Our strategy remains grounded in
energy fundamentals, policy direction and the evolving
energy mix
Disciplined capital allocation: Managing to a
$6 to $7 billion annual net capital expenditure4 limit,
post-2024, with a bias toward the lower end of the range
Financial strength and flexibility: Achieving strong
financial performance at all points of the economic cycle
Conservative risk preferences: Diversified, utility-like
business with approximately 97 per cent of comparable
EBITDA underpinned by rate regulation or long-term
contracts.
3
TC ENERGY Over the past few years, we have strategically pivoted
capital toward our complementary natural gas and power
and energy solutions businesses, further leveraging
organic synergies and capturing long-term growth.
We will continue to strengthen our unparalleled asset base by:
REINFORCING OUR POSITION AS A
GROWTH-ORIENTED NATURAL GAS COMPANY
As we address the energy trilemma — balancing security,
affordability and sustainability — natural gas, including
LNG, is a key solution. We will continue to invest in
our natural gas pipelines and storage business to meet
customer demand and strengthen our diversified,
industry-leading position.
FOCUSING OUR POWER PORTFOLIO
Our strategy in Power and Energy Solutions is to focus
our portfolio on nuclear generation and pumped hydro
opportunities. We will continue to invest modest capital in
other energy solutions, such as carbon capture, utilization
and storage and hydrogen, to develop our capabilities in
areas where we are likely to build a strong competitive
position in the future.
COMMITTING TO DISCIPLINED CAPITAL
ALLOCATION
We expect that adhering to our $6 to $7 billion net capital
expenditure limit post-2024, with a bias toward the lower
end of the range, will position us to continue delivering
an attractive and sustainable dividend growth rate while
enhancing our financial strength and flexibility. We will
continue to be disciplined in our allocation of capital while
aligning to our 4.75 times debt-to-EBITDA upper limit by the
end of 2024. Further, we are committed to sanctioning the
highest-value projects from our opportunity set, ensuring
both financial and strategic value and minimizing risk.
Post-spinoff, TC Energy will continue to cultivate a highly
regulated, low-risk portfolio that balances sustainable
dividend growth and disciplined capital spending. We will
look increasingly utility-like with a strategy and portfolio
mix that further capture the benefits shared by our utility
peers while capitalizing on strong demand growth in the
markets we serve.
OUR 2024 STRATEGIC
PRIORITIES
As we move into 2024, we are guided by the following
priorities:
Maximize the value of our assets through safety and
operational excellence: We will continue to safely,
responsibly and reliably deliver energy. We will pursue
the spinoff of our Liquids Pipelines business, which
will be called South Bow, while further integrating our
natural gas business to capture synergies.
Project execution on time and on budget: We
will safely execute our high-quality, secured capital
program and expect to place approximately $7 billion
of assets into service.
Enhance our balance sheet strength and flexibility:
We will continue our clearly defined path to achieving
and sustaining our 4.75 times debt-to-EBITDA5
upper limit by the end of 2024 by pursuing our asset
divestiture program and continuing to streamline our
business and identify efficiencies.
TC ENERGY’S RENEWED
STRATEGIC VISION
Driven by our longstanding value proposition, our renewed
strategic vision for TC Energy is to maximize the value of
our four leadership positions, post-spinoff, to provide
energy solutions the world needs.
As the external environment, stakeholder expectations
and energy landscape continue to evolve — influenced
by policy and regulatory developments, climate impacts,
technology advancements and geopolitical forces — our
strategy and business remain adaptable. We continue
to anchor our capital allocation decisions in energy
fundamentals and policy direction while abiding by a
conservative set of risk preferences. With this approach,
we are well-prepared to navigate these shifts in the energy
landscape and external environment.
5 Debt-to-EBITDA is a non-GAAP ratio. Adjusted debt and adjusted comparable EBITDA are
non-GAAP measures used to calculated debt-to-EBITDA. These measures do not have any
standardized meaning under GAAP and therefore are unlikely to be comparable to similar
measures presented by other companies. The most directly comparable GAAP measure for
adjusted debt is debt and for adjusted comparable EBITDA is segmented earnings (losses).
We believe that debt-to-EBITDA provides investors with useful information as it reflects
our ability to service our debt and other long-term commitments. Refer to TC Energy’s
2023 Quarterly Report to Shareholders (Q4) for information on how debt-to-EBITDA is
calculated and reconciliations of adjusted debt and adjusted comparable EBITDA for the
years ended December 31, 2022 and 2023.
4
ANNUAL REPORT 2023 LOOKING AHEAD
We have great expectations as we look to 2024. Driven
by continued demand for our assets and services, we
expect our 2024 comparable EBITDA to be higher than the
record amount we delivered in 2023 prior to adjustments
for potential asset sales and the spinoff of our Liquids
Pipelines business that remains subject to a shareholder
vote expected in mid-2024.
Given the confidence in the strength of our financial and
operational performance, in February 2024, our Board of
Directors increased our common share dividend for the
twenty-fourth consecutive year to $3.84 per share on an
annualized basis, an increase of 3.2 per cent. By remaining
aligned with our value proposition and focusing on our
strategic priorities, we expect to continue to grow the
dividend at a rate of three to five per cent annually.
Our skilled team consistently works safely and reliably to
ensure that people’s daily energy needs are met. They
undertake this work with the utmost responsibility and
care for the communities in which we operate while being
responsive to Indigenous rights holders and stakeholders.
In the face of increasing complexities and challenges, our
team showcases adaptability and resilience. We express
our gratitude for their relentless efforts.
At the helm of these efforts is an unparalleled senior
management team. Their combined skills, determination
and innovative thinking set TC Energy apart. Guided by
strong governance principles and oversight of our Board of
Directors, this management team consistently delivers results
in line with TC Energy's established history of solid returns.
We thank Siim A. Vanaselja, former Chair of the Board, for
his extensive contributions to the growth and success of
TC Energy. Mr. Vanaselja will continue to serve as a valued
member of the Board to ensure an orderly succession and
allow TC Energy the continued benefit of his expertise.
On behalf of the Board of Directors and our employees,
we thank our shareholders for your continued trust and
investment in TC Energy and look forward to our ongoing
engagement.
Sincerely,
François Poirier
President and CEO
John Lowe
Chair of the Board
5
TC ENERGY A NORTH AMERICAN
ENERGY SOLUTIONS
COMPANY
NATURAL GAS
In the three jurisdictions in
which we operate, we're leaders
in natural gas transportation
and storage. Our strategic
93,600-kilometre (58,100-mile)
network connects the most
competitive, low-cost natural gas
basins to premium value markets
in Canada, the U.S. and Mexico.
We safely transport approximately
30 per cent of the natural gas
required to meet energy demand
across the continent every day.
Natural gas is essential to
navigating the energy trilemma
— balancing security, affordability
and sustainability.
Our infrastructure also provides
the foundation to bring natural
gas to LNG export terminals in
North America. In the U.S., our
natural gas system currently moves
approximately 30 per cent of the
feed-gas destined for LNG export.
In Canada, we have completed
construction of the Coastal GasLink
pipeline, enabling the first direct
path between Canada and global
LNG markets to deliver responsibly
produced natural gas to the
world. In Mexico, to meet the
country's growing demand, we are
advancing the Southeast Gateway
project, a dedicated pipeline with
state-of-the-art technology for
transportation.
6
POWER AND
ENERGY SOLUTIONS
Our power business continues to
supply reliable, affordable and
sustainable energy. We own or
have interests in facilities that
generate approximately 4,600
megawatts of power-generation
capacity, over 75 per cent of
which is emissions-less.
To backstop the forecasted
growth in renewable power
generation by 2050, our
strategy in Power and Energy
Solutions focuses our portfolio
on world-class nuclear power
generation and pumped hydro
opportunities, critical for
maintaining grid reliability. We
expect our investments to be
underpinned by rate-regulated
and long-term contracts,
allowing us to deliver low-risk
utility-like returns. Our portfolio
provides diversification to our
business and is well-positioned
to deliver geographically
focused, reliable, emission-less
electricity to customers.
LIQUIDS
Our 4,900-kilometre (3,000-mile)
liquids pipeline system, consisting
of our Keystone Pipeline System,
directly connects one of the largest
global oil reserves, the Western
Canadian Sedimentary Basin (WCSB),
to the largest refining markets with
approximately 14 million bbl/d of
capacity in the U.S. Midwest and Gulf
Coast. Additionally, our Grand Rapids
and White Spruce assets in Alberta
provide market diversification to
serve global markets from Canada’s
West Coast. Underpinned by
long-term commercial structures
and 96 per cent investment-grade
or equivalent customers, this
unparalleled network serves as a
highly strategic corridor.
North American oil production is
expected to remain a robust and
important part of the energy mix
for decades to come. A stable and
reliable WCSB crude oil supply is
forecasted to grow by 500,000
bbl/d through the end of the
decade, with refining utilization
in our key markets forecasted to
remain strong through 2050.
To maximize the value of this
portfolio, provide growth optionality
and unlock its full potential, we
intend to spin off our Liquids
Pipelines business in the second half
of 2024, following a shareholder vote
to approve the transaction. Learn
more on page 8.
OUR LEADERSHIP
POSITIONS
We have an unparalleled asset base that spans Canada, the U.S. and Mexico. Our
extensive infrastructure provides the energy connections that unite North America.
It is this very infrastructure that has enabled us to secure five leadership positions:
1
2
3
4
DELIVERING CANADA'S
NATURAL GAS SUPPLY
Transporting natural gas from one of the world’s
most prolific basins, the WCSB, to Canadian and
U.S. markets, expanding our reach to global
markets through LNG with Coastal GasLink.
DELIVERING U.S.
NATURAL GAS SUPPLY
Transporting natural gas from the Appalachian
Basin in the Eastern U.S. down to the U.S. Gulf
Coast and other premier U.S. markets and moving
approximately 30 per cent of LNG feed-gas.
IMPORTING NATURAL
GAS TO MEET MEXICO'S
DEMAND
Transporting natural gas from U.S. markets
to meet the growing demand for lower
carbon-intensive energy in Mexico.
GENERATING POWER
AND ENERGY SOLUTIONS
Developing secure, affordable and sustainable
low-carbon energy solutions, with a focus on
nuclear and pumped hydro.
EXPORTING CANADIAN
CRUDE OIL SUPPLY
The fastest, most cost-competitive route to transport WCSB
crude oil to the largest North American refining markets in
the U.S. Midwest and Gulf Coast.
These leadership positions are enabled by
our unwavering commitment to safety and
operational excellence and set us apart from our
peers. By continuing to be selective and strategic
about where we allocate capital, we can further
enhance our competitive advantage, making
TC Energy the partner of choice.
7
SOUTH BOW'S VISION
As a smaller entity, South Bow can be lean,
nimble and opportunistic. We are pleased to
offer our shareholders a strong, sustainable
base common share dividend fully funded
by high-quality cash flow generation, with
an expected two to three per cent long-term
dividend growth rate.
Bevin Wirzba,
Intended President and CEO, South Bow
With an expected investment-grade rating, South Bow
will have the agility needed to quickly respond to market
shifts, while delivering continued shareholder value.
Pairing its attractive base dividend and unrivaled path
to key demand markets, we also expect the company's
highly contracted take-or-pay, low-risk cash flow profile
to offer a premium valuation relative to its peer group.
Leveraging its advantages, South Bow will continue to be
one of the continent's most competitive liquids platforms.
EXPECTED NEXT STEPS
Spring 2024: proxy circular filed
Mid-2024: shareholder vote on Liquids spinoff
transaction
Second half of 2024: Liquids spinoff expected to
be completed
Combined dividends of the two companies will
remain whole following the Liquids spinoff.
SOUTH BOW
MAXIMIZING THE VALUE OF
OUR ASSETS
INTENTION TO SPIN OFF OUR LIQUIDS
PIPELINES BUSINESS
Following a two-year strategic review of our Liquids
Pipelines business, we announced in July 2023
the proposed plan to separate TC Energy into two
independent, investment-grade, publicly listed
companies to maximize the value of our assets.
TC Energy’s Board of Directors and management team
are confident that this strategic decision will unlock the
full potential of our strategic corridor to enhance
long-term value for shareholders.
STRATEGIC RATIONALE
TC Energy and South Bow offer distinct value propositions
to customers and investors. As stand-alone entities, each
will have the ability to pursue and achieve greater success
by executing tailored strategies to fully capture the
incremental value of their unique opportunity sets.
As the world renews its focus on energy security,
our Liquids Pipelines business has experienced
increased customer demand, presenting immediate
opportunities that require more financial flexibility
to maintain its notable competitive advantages. To
protect the leadership position currently held by the
Liquids Pipelines business, it must have the flexibility
to prudently invest today and deliver on incremental
customer demands.
As a separate entity, South Bow will have the autonomy
to access the capital needed for opportunistic growth
and execute its focused strategy. As investments must
be contemplated years in advance, South Bow must
have the flexibility to strengthen its industry-leading
corridor before re-contracting at the end of the decade.
Separating in 2024 gives South Bow the time to identify
and advance the accretive opportunities that will make
it the most successful in the long run.
8
Management's discussion and analysis
February 15, 2024
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, 2023.
This MD&A should also be read in conjunction with our December 31, 2023 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
• 2023 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 ENERGY SOLUTIONS
CORPORATE
FOREIGN EXCHANGE
FINANCIAL CONDITION
OTHER INFORMATION
• Risk oversight and enterprise risk management
• Controls and procedures
• Critical accounting estimates
• Financial instruments
• Related party transactions
• Accounting changes
• Quarterly results
GLOSSARY
10
14
15
16
20
28
29
34
43
48
52
57
67
77
84
86
99
99
115
116
118
120
121
122
134
TC Energy Management's discussion and analysis 2023 | 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 134. All information is as of February 15, 2024
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 along with portfolio management
• expectations about the new Liquids Pipelines Company, South Bow Corporation, following the anticipated completion of the
proposed spinoff transaction of our Liquids Pipelines business into a separate publicly listed company, including the
management and credit ratings thereof
• expectations regarding the size, structure, timing, conditions and outcome of ongoing and future transactions, including the
proposed spinoff transaction and our asset divestiture program
• expected dividend growth
• expected access to and cost of capital
• expected energy demand levels
• expected costs and schedules for planned projects, including projects under construction and in development
• expected capital expenditures, contractual obligations, commitments and contingent liabilities, including environmental
remediation costs
• 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
• expected impact of future tax and accounting changes
• commitments and targets contained in our Report on Sustainability and GHG Emissions Reduction Plan
• expected industry, market and economic conditions, including their impact on our customers and suppliers.
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, the proposed spinoff transaction and energy transition
• regulatory decisions and outcomes
• planned and unplanned outages and the use of our pipelines, 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, including the impact of these on our customers and suppliers
• inflation rates, commodity and labour prices
• interest, tax and foreign exchange rates
• nature and scope of hedging.
10 | TC Energy Management's discussion and analysis 2023
Risks and uncertainties
• realization of expected benefits from acquisitions, divestitures, the proposed spinoff transaction and energy transition
• terms, timing and completion of the proposed spinoff transaction, including the timely receipt of all necessary approvals and
tax rulings
• that market or other conditions are no longer favourable to completing the proposed spinoff transaction
• business disruption during the period prior to or directly following the proposed spinoff transaction
• our ability to successfully implement our strategic priorities, including the Focus Project, and whether they will yield the
expected benefits
• our ability to implement a capital allocation strategy aligned with maximizing shareholder value
• operating performance of our pipelines, power generation and storage assets
• amount of capacity sold and rates achieved in our pipeline businesses
• amount of capacity payments and revenues from power generation assets due to plant availability
• production levels within supply basins
• construction and completion of capital projects
• cost, availability of, and inflationary pressures on, labour, equipment and materials
• 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
• our ability to realize the value of tangible assets and contractual recoveries
• competition in the businesses in which we operate
• unexpected or unusual weather
• acts of civil disobedience
• cybersecurity and technological developments
• sustainability-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, and the 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.sedarplus.ca).
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
• net capital expenditures.
TC Energy Management's discussion and analysis 2023 | 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 are
consistent with the factors that impact net income (loss) attributable to common shares, except where noted otherwise.
Discussions throughout this MD&A on the factors impacting comparable earnings before interest, taxes, depreciation and
amortization (comparable EBITDA) and comparable earnings before interest and taxes (comparable EBIT) are consistent with the
factors that impact segmented earnings, 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
• expected credit loss provisions on net investment in leases and certain contract assets in Mexico
• legal, contractual, bankruptcy and other settlements
• impairment of goodwill, plant, property and equipment, equity investments and other assets
• acquisition, integration and restructuring costs
• unrealized fair value adjustments related to risk management activities of Bruce Power's funds invested for post-retirement
benefits
• unrealized gains and losses from changes in the fair value of derivatives related to financial and commodity price risk
management activities.
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. The changes in fair value, including our proportionate share of changes in fair value
related to Bruce Power 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.
In third quarter 2023, we announced plans to separate into two independent, investment-grade, publicly listed companies
through the proposed spinoff of our Liquids Pipelines business (the spinoff Transaction). A separation management office was
established to guide the successful coordination and governance between the two entities, including the development of a
separation agreement and transition service agreement. Liquids Pipelines business separation costs related to the spinoff
Transaction include internal costs related to separation activities, legal, tax, audit and other consulting fees, which are
recognized in the results of our Liquids Pipelines and Corporate segments. These items have been excluded from comparable
measures as we do not consider them reflective of our ongoing underlying operations.
In second quarter 2023, we accrued an additional amount for environmental remediation costs related to the Milepost 14
incident. We have appropriate insurance policies in place and we believe that it remains probable that the majority of the
environmental remediation costs will be eligible for recovery under our existing insurance coverage. We expect to receive a
portion of these insurance proceeds from our wholly-owned captive insurance subsidiary, which resulted in an impact to net
income in the consolidated financial results of TC Energy in second quarter 2023. This amount has been excluded from
comparable measures as it is not reflective of our ongoing underlying operations.
In first quarter 2023, TransCanada PipeLines Limited (TCPL) entered into an unsecured revolving credit facility with
Transportadora de Gas Natural de la Huasteca (TGNH). The loan receivable and loan payable are eliminated upon consolidation;
however, due to differences in the currency that each entity reports its financial results, there is an impact to net income
reflecting the translation of the loan receivable and payable to TC Energy's reporting currency. As the amounts do not accurately
reflect what will be realized at settlement, beginning in second quarter 2023, we excluded from comparable measures the
unrealized foreign exchange gains and losses on the loan receivable, as well as the corresponding unrealized foreign exchange
gains and losses on the loan payable.
12 | TC Energy Management's discussion and analysis 2023
In 2022, we launched the Focus Project to identify opportunities to improve safety, productivity and cost-effectiveness and to
date have identified a broad set of opportunities expected to improve safety and financial performance over the long term.
Certain initiatives have been implemented and we expect to continue designing and implementing additional initiatives beyond
2023, with benefits in the form of enhanced safety, productivity and cost-effectiveness expected to be realized in the future.
Beginning in 2023, we recognized expenses in Plant operating costs and other, primarily related to Focus Project costs for
external consulting and severance, some of which are not recoverable through regulatory and commercial tolling structures.
These amounts have been excluded from comparable measures as they are not reflective of our ongoing underlying operations.
Prior to full repayment in first quarter 2022, we excluded from comparable measures the unrealized foreign exchange gains and
losses on the peso-denominated loan receivable from an affiliate, as well as the corresponding proportionate share of
Sur de Texas foreign exchange gains and losses, as the amounts did not accurately reflect the gains and losses that would be
realized at settlement. These amounts offset within each reporting period, resulting in no impact on net income.
The following table identifies our non-GAAP measures against their most directly comparable GAAP measures:
Comparable measure
comparable EBITDA
comparable EBIT
comparable earnings
GAAP measure
segmented earnings (losses)
segmented earnings (losses)
net income (loss) attributable to common shares
comparable earnings per common share
net income (loss) per common share
funds generated from operations
comparable funds generated from operations
net capital expenditures
net cash provided by operations
net cash provided by operations
capital expenditures
Comparable EBITDA and comparable EBIT
Comparable EBITDA represents segmented earnings (losses) adjusted for certain specific items, excluding charges for
depreciation and amortization. We use comparable EBITDA as a measure of our earnings from ongoing operations as it is a useful
indicator of our performance and is also presented on a consolidated basis. Comparable EBIT represents segmented
earnings (losses) 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 (losses).
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 (losses), Interest expense, AFUDC, Foreign exchange gains
(losses), net, Interest income and other, Income tax (expense) recovery, Net (income) loss attributable to non-controlling
interests and Preferred share dividends, adjusted for specific items. Refer to the Financial highlights section for reconciliations to
Net income (loss) attributable to common shares and Net income (loss) 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. The
components of changes in working capital are disclosed in Note 30, Changes in operating working capital, of our 2023
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.
Net capital expenditures
Net capital expenditures represents capital expenditures, including growth projects, maintenance capital expenditures,
contributions to equity investments, and projects under development, adjusted for the portion attributed to non-controlling
interests in the entities we control. We use net capital expenditures as we believe it is a useful measure of our cash flow used for
capital reinvestment.
TC Energy Management's discussion and analysis 2023 | 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 2023
THREE CORE BUSINESSES
We operate in three core businesses – Natural Gas Pipelines, Liquids Pipelines and Power and Energy Solutions. 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 Energy Solutions. 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 Energy Solutions
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 Energy Solutions
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 Energy Solutions
Corporate
2023
2022
29,782
50,499
12,003
15,490
9,525
7,735
27,456
50,038
9,231
15,587
8,272
3,764
125,034
114,348
2023
2022
5,173
6,229
846
2,667
1,019
4,764
5,933
688
2,668
924
15,934
14,977
2023
2022
3,335
4,385
805
1,457
1,020
(14)
10,988
2,806
4,089
753
1,366
907
(20)
9,901
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 2023 | 15
OUR STRATEGY
Our vision is to be the premier energy infrastructure company in North America today and in the future by safely generating,
storing and delivering the energy people need every day. Our goal is to develop, build and safely operate a portfolio of
infrastructure assets that enable us to prosper irrespective of the pace and direction of energy transition and at all points in the
economic cycle. We are a team of energy problem solvers working to deliver this energy in a safe, reliable, secure and affordable
manner through lower carbon energy solutions including natural gas, nuclear energy and pumped hydro.
Our business consists of natural gas and crude oil transportation, storage and delivery systems, as well as power generation
assets that produce electricity. These long-life infrastructure assets cover all strategic North American corridors, are anchored by
our conservative risk preferences and are supported by long-term commercial arrangements and/or rate regulation. Our assets
generate predictable and sustainable cash flows and earnings providing the cornerstones of our low-risk, utility-like 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 and support global GHG emissions reduction
• crude oil will remain an important part of the fuel mix
• the need for reliable, on-demand energy sources to support electric grid stability will grow significantly
• existing infrastructure assets will become more valuable given the challenges in developing new greenfield, linear-energy
infrastructure; in particular, pipelines.
On July 27, 2023, we announced plans to separate into two independent, investment-grade, publicly listed companies through
the spinoff Transaction and on November 8, 2023, we communicated that the name of the new Liquids Pipelines business will be
South Bow Corporation. In addition to shareholder and court approvals, the spinoff Transaction is subject to receipt of
favourable tax rulings from Canadian and U.S. tax authorities, receipt of necessary regulatory approvals, and satisfaction of other
customary closing conditions. We expect that the spinoff Transaction will be completed in the second half of 2024.
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 Energy Solutions
2023
2022
31%
40%
7%
13%
9%
28%
41%
8%
14%
9%
100%
100%
1
Refer to Note 5, Segmented information, of our 2023 Consolidated financial statements for an allocation of segmented earnings by business segment.
Our asset mix will continue to evolve to align with the North American energy mix. We anticipate the following shifts in capital
allocation as the world progresses towards a low-carbon future while balancing energy security and affordability needs:
• Natural Gas Pipelines will continue to attract capital driven by coal to gas conversion and LNG exports
• Power and Energy Solutions weighting in our portfolio is expected to gradually grow over time, heavily weighted to nuclear
and pumped hydro. Measured investment in emerging technologies will develop capabilities that are complementary to our
core businesses, without taking significant commodity price, volumetric or technology risk
• The separation of the Liquids Pipelines business will allow it to pursue growth opportunities to capture incremental value.
16 | TC Energy Management's discussion and analysis 2023
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 $31 billion in secured
projects, largely underpinned by long-term contracts or commercial rate regulation. We expect that these investments will contribute to
incremental earnings and cash flows as they are placed in service
• Our extensive asset footprint offers significant in-corridor growth opportunities that support our current incumbent positions in natural
gas, liquids and nuclear energy. This also includes possible future opportunities to deploy lower GHG emission infrastructure technologies
such as pumped hydro, hydrogen and carbon capture, which will help reduce our GHG emissions footprint and that of our customers,
while supporting longevity of our existing assets
• We strive 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 policy, 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 sustainability 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, protects and grows our
franchise businesses, enhances future resilience under a changing energy mix, and diversifies access to attractive supply and market
regions within our risk preferences. Refer to the Risk oversight and enterprise risk management section for an overview of our enterprise
risks
• We focus on commercially rate-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 lower carbon growth initiatives in emerging sub-sectors where we are likely to build a
strong competitive position in the future, to full development and construction when market conditions are appropriate, technology is
proven, and project risks and returns are known and acceptable
• We monitor trends specific to energy supply and demand fundamentals, in addition to analyzing how our portfolio performs under
different energy mix scenarios. 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 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 while
protecting and growing our incumbencies. We allocate capital in a manner that improves the breadth and cost competitiveness of the
services we provide, extends the life of our assets, increases diversification and strengthens the carbon-competitiveness of our assets
• We believe that our high-quality, diversified portfolio of incumbent assets results in predictable, low risk cash flows and positions us well
to succeed under any energy transition scenario and across all economic cycles
• A strong focus on talent management ensures that we have the necessary capabilities to execute and deliver on our strategy.
TC Energy Management's discussion and analysis 2023 | 17
Our competitive advantage
The need for safe, reliable, secure and affordable energy solutions has become increasingly important. 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.
We will do this 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: the strategic advantage supporting our vision is our extensive asset footprint and franchises with
high barriers to entry. Our low-risk portfolio of assets offers the scale to provide essential and highly competitive infrastructure
services, enabling us to maximize the full-life value of our investments throughout all points of the business cycle. We have
five incumbent franchise businesses – transporting natural gas from the WCSB; transporting natural gas from the Appalachian
basin; importing natural gas into Mexico; exporting crude oil to the U.S. Midwest and Gulf Coast markets; and our nuclear
business in Ontario through Bruce Power. These platforms not only provide a diversified portfolio but also position TC Energy
as a leader in the energy infrastructure sector. Our synergistic footprint supports both molecules and electrons, providing us
flexibility to allocate capital towards natural gas, electrification or other emerging low-carbon technologies that are
complementary to our core businesses
• disciplined operations: our 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
investments while preserving financial flexibility, including asset divestitures, to fund our operations in all market conditions.
We deliver a balance of dividend income and growth. 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, re-purposing the underutilized Canadian Mainline pipeline capacity from natural gas to crude oil service,
installing electric compression and/or switching gas compression to electrification such as the Valhalla North and Berland
River (VNBR) and WR projects in Canada and the U.S., respectively, and currently assessing development of grid-scale, flexible
and clean energy storage through the proposed Ontario Pumped Storage Project
• commitment to sustainability: 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. We publish our GHG emissions intensity on a corporate-wide basis in our annual Report on Sustainability, and in
2023, we issued reports on the Reliability of Methane Emissions Disclosure and Climate-related Lobbying to provide more
transparency and insight into our climate-related goals and efforts. We continue to assess our emission reduction targets and
major components of our longer-term reduction plan against various criteria, including policy, regulatory, commercial and
economic developments, the outcomes of our capital rotation program and the proposed spin-off of our Liquids Pipelines
business. Aligned with our Commitment Statement and integrated throughout our 2023 Report on Sustainability, our
refreshed sustainability commitments reflect the material topics most relevant to our business and our stakeholders. We
continue to focus on our nine sustainability commitments, and associated metrics and targets, including positioning to
achieve net zero emissions from our operations by 2050, that help ensure our business is well positioned for long-term success
• open communication: we carefully manage relationships with our customers, suppliers, regulators and other stakeholders
and offer clear, candid communication to investors in order to build trust and support.
18 | TC Energy Management's discussion and analysis 2023
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 asset divestitures to finance new initiatives.
Known and acceptable project risks
• Select investments with known, acceptable and manageable project execution risk, including stakeholder considerations, partnership
agreements, human capital and capabilities constraints.
Business underpinned by strong fundamentals and policy support
• Invest in assets that are investment-grade on a stand-alone basis with stable cash flows supported by strong underlying macroeconomic
fundamentals, conducive policy and regulations 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.
TC Energy Management's discussion and analysis 2023 | 19
2023 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 23 and 88, as well as the Financial results section in each business segment for reconciliations to the most directly
comparable GAAP measures.
year ended December 31
(millions of $, except per share amounts)
2023
2022
2021
Income
Revenues
Net income (loss) 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
Acquisitions, net of cash acquired
Proceeds from sales of assets, net of transaction costs
Disposition of equity interest, net of transaction costs3
Balance sheet4
Total assets
Long-term debt, including current portion
Junior subordinated notes
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
14,977
13,387
15,934
2,829
$2.75
10,988
4,652
$4.52
7,268
7,980
12,298
(307)
33
5,328
641
$0.64
9,901
4,279
$4.30
6,375
7,353
8,961
—
—
—
125,034
114,348
52,914
10,287
2,499
9,455
27,054
41,543
10,495
2,499
126
31,491
1,815
$1.87
9,368
4,142
$4.26
6,890
7,406
7,134
—
35
—
104,218
38,661
8,939
3,487
125
29,784
$3.72
$3.60
$3.48
1,030
1,037
995
1,018
973
981
1
2
3
4
Additional information on Segmented earnings (losses), the most directly comparable GAAP measure, can be found on page 11.
Capital spending reflects cash flows associated with our Capital expenditures, Capital projects in development and Contributions to equity investments. Refer to
Note 5, Segmented information, of our 2023 Consolidated financial statements for the financial statement line items that comprise total capital spending.
Included in the Financing activities section of the Consolidated statement of cash flows.
At December 31.
20 | TC Energy Management's discussion and analysis 2023
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 Energy Solutions
Corporate
Total segmented earnings (losses)
Interest expense
Allowance for funds used during construction
Foreign exchange gains (losses), net
Interest income and other
Income (loss) before income taxes
Income tax (expense) recovery
Net income (loss)
Net (income) loss attributable to non-controlling interests
Net income (loss) attributable to controlling interests
Preferred share dividends
Net income (loss) attributable to common shares
Net income (loss) per common share – basic
2023
(90)
3,531
796
1,011
1,004
(116)
6,136
(3,263)
575
320
242
4,010
(942)
3,068
(146)
2,922
(93)
2,829
$2.75
2022
(1,440)
2,617
491
1,123
833
8
3,632
(2,588)
369
(185)
146
1,374
(589)
785
(37)
748
(107)
641
$0.64
2021
1,449
3,071
557
(1,600)
628
(46)
4,059
(2,360)
267
10
190
2,166
(120)
2,046
(91)
1,955
(140)
1,815
$1.87
Net income attributable to common shares in 2023 was $2.8 billion or $2.75 per share (2022 – $0.6 billion or $0.64 per share;
2021 – $1.8 billion or $1.87 per share), an increase of $2.2 billion or $2.11 per share compared to 2022. The significant increase for
the year ended December 31, 2023 compared to 2022, as well as the significant decrease in Net income attributable to common
shares of $1.2 billion or $1.23 per share in 2022 compared to 2021 are primarily due to the net effect of specific items mentioned
below. Net income per common share in all years also reflects the impact of common shares issued, including common shares
issued for the acquisition of TC PipeLines, LP in first quarter 2021.
The following specific items were recognized in Net income (loss) attributable to common shares and were excluded from
comparable earnings:
2023
• an after-tax impairment charge of $1.9 billion related to our equity investment in Coastal GasLink Pipeline Limited
Partnership (Coastal GasLink LP). Refer to Note 8, Coastal GasLink, of our 2023 Consolidated financial statements for additional
information
• a $52 million after-tax charge as a result of the FERC Administrative Law Judge initial decision on Keystone issued in
February 2023 in respect of a tolling-related complaint pertaining to amounts recognized from 2018 to 2022, which consists of
a one-time pre-tax charge of $57 million and included accrued pre-tax carrying charges of $10 million
• a $48 million after-tax expense related to Focus Project costs. Refer to the Corporate – Significant events section for additional
information
• an after-tax unrealized foreign exchange loss of $44 million on the peso-denominated intercompany loan between TCPL and
TGNH
• a $36 million after-tax accrued insurance expense related to the Milepost 14 incident. Refer to the Liquids Pipelines –
Significant events section for additional information
• an after-tax charge of $34 million due to Liquids Pipelines business separation costs related to the spinoff Transaction. Refer to
the Liquids Pipelines – Significant events section for additional information
TC Energy Management's discussion and analysis 2023 | 21
• preservation and other costs for Keystone XL pipeline project assets of $14 million after tax, which could not be accrued as part
of the Keystone XL asset impairment charge
• a $55 million after-tax recovery on the expected credit loss provision related to the TGNH net investment in leases and certain
contract assets in Mexico
• an $18 million after-tax recovery related to the net impact of a U.S. minimum tax recovery on the 2021 Keystone XL asset
impairment charge and other and a gain on the sale of Keystone XL project assets, offset partially by adjustments to the
estimate for contractual and legal obligations related to termination activities.
2022
• an after-tax impairment charge of $2.6 billion related to our equity investment in Coastal GasLink LP
• an after-tax goodwill impairment charge of $531 million related to Great Lakes
• a $196 million income tax expense for the settlement related to prior years' income tax assessments in Mexico
• $114 million after-tax expected credit loss provision related to the TGNH net investment in leases and certain contract assets in
Mexico
• $20 million after-tax charge due to the CER decision on Keystone issued in December 2022 in respect of a tolling-related
complaint pertaining to amounts reflected in 2021 and 2020
• preservation and other costs for Keystone XL pipeline project assets of $19 million after tax, which could not be accrued as part
of the Keystone XL asset impairment charge
• a $5 million after-tax expense related to the net impact of a U.S. minimum tax on the 2021 Keystone XL asset impairment
charge and other, partially offset by a gain on the sale of Keystone XL project assets and adjustments to the estimate for
contractual and legal obligations related to termination activities.
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 2021 revocation of the
Presidential Permit
• a $48 million after-tax expense with respect to transition payments incurred as part of the Voluntary Retirement
Program (VRP)
• preservation and other 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 15 per cent 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.
Refer to the Financial results section in each business segment and the Financial condition section of this MD&A for additional
information.
Net income in all years included unrealized gains and losses on our proportionate share of Bruce Power's fair value adjustment on
funds invested for post-retirement benefits and derivatives related to its risk management activities, as well as unrealized gains
and losses from changes in our risk management activities, all of which we exclude along with the above noted items, to arrive
at comparable earnings. A reconciliation of Net income (loss) attributable to common shares to comparable earnings is shown in
the following table.
22 | TC Energy Management's discussion and analysis 2023
Reconciliation of net income (loss) attributable to common shares to comparable earnings
year ended December 31
(millions of $, except per share amounts)
Net income (loss) attributable to common shares
Specific items (net of tax):
Coastal GasLink impairment charge
Keystone regulatory decisions
Focus Project costs
Foreign exchange (gains) losses, net – intercompany loan
Milepost 14 insurance expense
Liquids Pipelines business separation costs
Keystone XL preservation and other
Expected credit loss provision on net investment in leases
and certain contract assets in Mexico
Keystone XL asset impairment charge and other
Great Lakes goodwill impairment charge
Settlement of Mexico prior years' income tax assessments
Voluntary Retirement Program
Gain on sale of Northern Courier
Gain on sale of Ontario natural gas-fired power plants
Bruce Power unrealized fair value adjustments
Risk management activities1
Comparable earnings
Net income (loss) per common share
Coastal GasLink impairment charge
Keystone regulatory decisions
Focus Project costs
Foreign exchange (gains) losses, net – intercompany loan
Milepost 14 insurance expense
Liquids Pipelines business separation costs
Keystone XL preservation and other
Expected credit loss provision on net investment in leases
and certain contract assets in Mexico
Keystone XL asset impairment charge and other
Great Lakes goodwill impairment charge
Settlement of Mexico prior years' income tax assessments
Voluntary Retirement Program
Gain on sale of Northern Courier
Gain on sale of Ontario natural gas-fired power plants
Bruce Power unrealized fair value adjustments
Risk management activities
Comparable earnings per common share
2023
2,829
2022
641
2021
1,815
1,943
2,643
52
48
44
36
34
14
(55)
(18)
—
—
—
—
—
(5)
(270)
4,652
$2.75
1.89
0.05
0.05
0.04
0.03
0.03
0.01
(0.05)
(0.02)
—
—
—
—
—
—
(0.26)
$4.52
20
—
—
—
—
19
114
5
531
196
—
—
—
13
97
4,279
$0.64
2.66
0.02
—
—
—
—
0.02
0.11
0.01
0.53
0.20
—
—
—
0.01
0.10
$4.30
—
—
—
—
—
—
37
—
2,134
—
—
48
(19)
(7)
(11)
145
4,142
$1.87
—
—
—
—
—
—
0.04
—
2.19
—
—
0.05
(0.02)
(0.01)
(0.01)
0.15
$4.26
TC Energy Management's discussion and analysis 2023 | 23
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 tax attributable to risk management activities
Total unrealized gains (losses) from risk
management activities
2023
2022
2021
80
(34)
(31)
9
91
246
(91)
(15)
20
4
—
11
(149)
32
6
(3)
12
—
(6)
(203)
49
270
(97)
(145)
Comparable EBITDA to comparable earnings
Comparable EBITDA represents segmented earnings (losses) adjusted for the specific items described above and excludes
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)
2023
2022
2021
Comparable EBITDA
Canadian Natural Gas Pipelines
U.S. Natural Gas Pipelines
Mexico Natural Gas Pipelines
Liquids Pipelines
Power and Energy Solutions
Corporate
Comparable EBITDA
Depreciation and amortization
Interest expense included in comparable earnings
Allowance for funds used during construction
Foreign exchange gains (losses), net included in comparable earnings
Interest income and other included in comparable earnings
Income tax (expense) recovery included in comparable earnings
Net (income) loss attributable to non-controlling interests
Preferred share dividends
Comparable earnings
Comparable earnings per common share
3,335
4,385
805
1,457
1,020
(14)
10,988
(2,778)
(3,253)
575
118
278
(1,037)
(146)
(93)
4,652
$4.52
2,806
4,089
753
1,366
907
(20)
9,901
(2,584)
(2,588)
369
(8)
146
(813)
(37)
(107)
4,279
$4.30
2,675
3,856
666
1,526
669
(24)
9,368
(2,522)
(2,354)
267
254
190
(830)
(91)
(140)
4,142
$4.26
24 | TC Energy Management's discussion and analysis 2023
Comparable EBITDA – 2023 versus 2022
Comparable EBITDA in 2023 increased by $1,087 million compared to 2022 primarily due to the net result of the following:
• increased EBITDA from Canadian Natural Gas Pipelines primarily due to higher flow-through costs and increased rate-base
earnings on the NGTL System and higher earnings from Coastal GasLink related to the recognition of a $200 million incentive
payment upon meeting certain milestones
• increased Power and Energy Solutions EBITDA primarily attributable to higher contributions from Bruce Power as a result of a
higher contract price, fewer planned outage days and lower depreciation expense, partially offset by increased business
development activities across the segment
• higher U.S. dollar-denominated EBITDA from U.S. Natural Gas Pipelines due to incremental earnings from growth projects
placed in service, a net increase in earnings from ANR resulting from an increase in transportation rates effective August 2022,
higher realized margins related to our U.S. natural gas marketing business, partially offset by higher operational costs
reflective of increased system utilization and lower commodity prices related to our mineral rights business
• increased EBITDA from Liquids Pipelines due to higher volumes on the Keystone Pipeline System and the foreign exchange
impact of a stronger U.S. dollar on the translation of our U.S. dollar-denominated operations
• higher U.S. dollar-denominated EBITDA from Mexico Natural Gas Pipelines primarily related to certain sections of the
Villa de Reyes and Tula pipelines that were placed in commercial service in third quarter 2022 and 2023, partially offset by
lower equity earnings from Sur de Texas primarily due to peso-denominated financial exposure and higher interest expense
• the positive foreign exchange impact of a stronger U.S. dollar on the Canadian dollar equivalent comparable EBITDA in our
U.S. dollar-denominated operations. As detailed on page 84, U.S. dollar-denominated comparable EBITDA increased by
US$142 million compared to 2022, which was translated to Canadian dollars at an average rate of 1.35 in 2023 versus 1.30 in
2022. Refer to the Foreign exchange section for additional information.
Comparable EBITDA – 2022 versus 2021
Comparable EBITDA in 2022 increased by $533 million compared to 2021 primarily due to the net result of the following:
• increased Power and Energy Solutions EBITDA primarily attributable to higher contributions from Bruce Power due to a higher
contract price, higher realized power prices and increased contributions from Natural Gas Storage and Other as a result of
higher realized spreads in 2022
• higher U.S. dollar-denominated EBITDA from U.S. Natural Gas Pipelines largely due to incremental earnings from growth
projects placed in service, higher commodity prices from our mineral rights business, as well as increased net earnings from
Columbia Gas primarily due to an increase in transportation rates effective February 2021
• increased EBITDA from Canadian Natural Gas Pipelines largely attributable to the impact of higher flow-through costs and
increased rate-base earnings on the NGTL System; and lower flow-through costs, partially offset by higher incentive earnings
on Canadian Mainline
• higher EBITDA from Mexico Natural Gas Pipelines primarily related to certain sections of the Villa de Reyes and Tula pipelines
that were placed in commercial service in third quarter 2022
• decreased EBITDA from Liquids Pipelines as a result of lower rates and contracted volumes on the U.S. Gulf Coast section of the
Keystone Pipeline System, as well as reduced contributions from liquids marketing activities and the foreign exchange impact
of a stronger U.S. dollar on the translation of our U.S. dollar-denominated operations
• the positive foreign exchange impact of a stronger U.S. dollar on the Canadian dollar equivalent comparable EBITDA in our
U.S. dollar-denominated operations. As detailed on page 84, U.S. dollar-denominated comparable EBITDA decreased by
US$63 million compared to 2021; however, this was translated to Canadian dollars at an average rate of 1.30 in 2022 versus
1.25 in 2021. Refer to the Foreign exchange section for additional information.
Due to the flow-through treatment of certain costs including income taxes, financial charges and depreciation in our Canadian
rate-regulated pipelines, changes in these costs impact our comparable EBITDA despite having no significant effect on net
income.
TC Energy Management's discussion and analysis 2023 | 25
Comparable earnings – 2023 versus 2022
Comparable earnings in 2023 were $373 million or $0.22 per common share higher than in 2022, and were primarily the net
result of:
• changes in comparable EBITDA described above
• higher interest expense primarily due to long-term debt issuances, net of maturities, the foreign exchange impact of a
stronger U.S. dollar in 2023 compared to 2022 and higher interest rates on our long-term debt
• increased income tax expense due to the impact of higher comparable earnings subject to income tax, Mexico foreign
exchange exposure, lower foreign tax rate differentials, partially offset by lower flow-through income taxes and lower Mexico
inflation adjustments
• higher depreciation and amortization reflecting expansion facilities and new projects placed in service and the acquisitions of
the Fluvanna Wind Farm and Blue Cloud Wind Farm (Texas Wind Farms), partially offset by the discontinuance of depreciation
expense on TGNH assets in Mexico accounted for as leases
• higher net income attributable to non-controlling interests primarily due to the net effect of the sale of a 40 per cent
non-controlling equity interest in Columbia Gas Transmission, LLC (Columbia Gas) and Columbia Gulf Transmission, LLC
(Columbia Gulf) and the acquisition of the Texas Wind Farms
• higher AFUDC predominantly due to the Southeast Gateway pipeline project, as well as the reactivation of AFUDC on the TGNH
assets under construction, partially offset by projects placed in service
• higher interest income and other due to higher interest earned on short-term investments
• the impact of activities to manage our foreign exchange exposure to net liabilities in Mexico, partially offset by derivatives
used to manage our net exposure to foreign exchange rate fluctuation on U.S. dollar-denominated income and the revaluation
of our peso-denominated net monetary liabilities to U.S. dollars.
Comparable earnings – 2022 versus 2021
Comparable earnings in 2022 were $137 million or $0.04 per common share higher than in 2021, and were primarily the net result
of:
• changes in comparable EBITDA described above
• the impact of derivatives used to manage our net exposure to foreign exchange rate fluctuation on U.S. dollar-denominated
income and the revaluation of our peso-denominated net monetary liabilities to U.S. dollars, partially offset by activities to
manage our foreign exchange exposure to net liabilities in Mexico
• increased interest expense primarily due to higher interest rates on increased levels of short-term borrowings, long-term debt
and junior subordinated note issuances, net of maturities, as well as the foreign exchange impact of a stronger U.S. dollar in
2022
• lower interest income and other due to the repayment of the inter-affiliate loan receivable by the Sur de Texas joint venture
on July 29, 2022
• higher AFUDC predominantly due to the reactivation of AFUDC on the TGNH assets under construction, partially offset by the
impact of decreased capital expenditures and projects placed in service
• higher depreciation and amortization reflecting new assets placed in service and a stronger U.S. dollar in 2022
• lower Net income attributable to non-controlling interests following the March 2021 acquisition of all outstanding common
units of TC PipeLines, LP not beneficially owned by TC Energy
• decreased Income tax expense primarily due to lower flow-through income taxes and higher foreign tax rate differentials,
partially offset by higher earnings subject to tax and other various valuation allowances
• lower Preferred share dividends due to the redemption of preferred shares in 2022 and 2021.
Comparable earnings per common share reflect the dilutive effect of common shares issued in 2023 and 2022 and the impact of
common shares issued for the acquisition of the remaining ownership interests in TC PipeLines, LP in March 2021. Refer to the
Financial Condition section for additional information.
26 | TC Energy Management's discussion and analysis 2023
Cash flows
Net cash provided by operations of $7.3 billion in 2023 was 14 per cent higher than 2022 primarily due to the amount and timing
of working capital changes and higher funds generated from operations. Comparable funds generated from operations of
$8.0 billion in 2023 were nine per cent higher than 2022 primarily due to higher comparable earnings and increased distributions
from 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 Energy Solutions
Corporate
2023
6,184
2,660
2,292
49
1,080
33
2022
4,719
2,137
1,027
143
894
41
2021
2,737
2,820
129
571
842
35
12,298
8,961
7,134
1
Capital spending reflects cash flows associated with our Capital expenditures, Capital projects in development and Contributions to equity investments. Refer to
Note 5, Segmented information, of our 2023 Consolidated financial statements for the financial statement line items that comprise total capital spending.
In 2023 and 2022, we invested $12.3 billion and $9.0 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 2023 and
2022 included contributions of $4.1 billion and $2.2 billion, respectively, to our equity investments, predominantly related to
Coastal GasLink LP and Bruce Power.
Acquisitions
In 2023, we acquired 100 per cent of the Class B Membership Interests in Texas Wind Farms for US$224 million, before
post-closing adjustments.
Proceeds from sales of assets
In 2023, we completed the sale of a 20.1 per cent equity interest in Port Neches Link LLC to its joint venture partner, Motiva
Enterprises, for gross proceeds of US$25 million.
In 2021, we completed the sale of our remaining 15 per cent equity interest in Northern Courier for gross proceeds of $35 million.
Balance sheet
We continue to maintain a solid financial position while growing our total assets by $10.7 billion in 2023. At December 31, 2023,
common shareholders' equity and non-controlling interests, represented 37 per cent (2022 – 35 per cent) of our capital
structure, while other subordinated capital, in the form of junior subordinated notes and preferred shares, represented an
additional 13 per cent (2022 – 14 per cent). Refer to the Financial Condition section for additional information.
Dividends
We increased the quarterly dividend on our outstanding common shares by 3.2 per cent to $0.96 per common share for the
quarter ending March 31, 2024, which equates to an annual dividend of $3.84 per common share. This was the twenty-fourth
consecutive year we have increased the dividend on our common shares and is consistent with our goal of growing our common
share dividend at an average annual rate of three to five per cent.
TC Energy Management's discussion and analysis 2023 | 27
Dividend reinvestment and share purchase plan
Under the DRP, eligible holders of common and preferred shares of TC Energy can reinvest their dividends and make optional
cash payments to obtain additional TC Energy common shares. From August 31, 2022 to July 31, 2023, common shares were
issued from treasury at a discount of two per cent to market prices over a specified period. The participation rate by common
shareholders in the DRP in 2023 was approximately 39 per cent (2022 – 33 per cent), resulting in $737 million
(2022 – $607 million) reinvested in common equity under the program.
Commencing with the dividends declared on July 27, 2023, common shares purchased under TC Energy's DRP are acquired on
the open market at 100 per cent of the weighted average purchase price.
Cash dividends paid
year ended December 31
(millions of $)
Common shares
Preferred shares
OUTLOOK
2023
2,787
92
2022
3,192
106
2021
3,317
141
Comparable EBITDA and comparable earnings
Our 2024 comparable EBITDA and comparable earnings per common share outlooks do not take into consideration the impact of
the spinoff Transaction as it is subject to TC Energy shareholder approval, court approval, favourable tax rulings, other regulatory
approvals and satisfaction of other customary closing conditions.
We expect our 2024 comparable EBITDA to be higher than 2023 primarily due to the following:
• growth in the NGTL System from advancement of expansion programs
• full-year impact of Bruce Power Unit 6 return to service in September 2023
• new projects anticipated to be placed in service in 2024, along with the full-year impact of projects placed in service in 2023.
Our 2024 comparable earnings per common share is expected to be lower than 2023 due to the net impact of the following:
• higher net income attributable to non-controlling interests as a result of the sale of a 40 per cent non-controlling equity
interest in Columbia Gas and Columbia Gulf in 2023
• increase in comparable EBITDA described above
• higher AFUDC related to the Southeast Gateway pipeline.
We continue to monitor developments in energy markets, our construction projects, regulatory proceedings and our asset
divestiture program for any potential impacts on the above outlooks.
Consolidated capital expenditures
In 2023, we incurred approximately $12.4 billion in capital expenditures on our secured capital program and projects under
development. Prior to adjustments for non-controlling interests, we expect to incur gross capital expenditures, including
capitalized interest, of approximately $8.5 to $9.0 billion in 2024 on growth projects, maintenance capital expenditures,
contributions to equity investments and projects under development. We anticipate our net capital expenditures in 2024 to be
approximately $8.0 to $8.5 billion after considering capital expenditures attributable to the non-controlling interests of entities
we control.
The majority of our 2024 capital program is expected to be focused on the advancement of secured projects including the
Southeast Gateway pipeline, U.S. Natural Gas Pipelines projects, the Coastal GasLink pipeline project, Bruce Power Major
Component Replacement (MCR) programs and normal course maintenance capital expenditures.
Refer to the Outlook section in each business segment for additional details on expected earnings and capital expenditures for
2024.
28 | TC Energy Management's discussion and analysis 2023
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 are expected to advance our goals to reduce
our own carbon footprint, as well as that of our customers.
Our capital program consists of approximately $31 billion of secured projects that 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 2023, we placed approximately $5.3 billion of projects in service, which included natural gas pipeline capacity capital
projects along our extensive North American asset footprint, as well as the Bruce Power Unit 6 MCR, which was declared
commercially operational on September 14, 2023. In addition, approximately $2.2 billion of maintenance and modernization
capital expenditures were incurred.
All projects are subject to cost and timing adjustments due to factors including weather, market conditions, route refinement,
land acquisition, permitting conditions, scheduling and timing of regulatory permits, as well as other potential restrictions and
uncertainties, including inflationary pressures on labour and materials. Amounts exclude capitalized interest and AFUDC, where
applicable.
TC Energy Management's discussion and analysis 2023 | 29
Secured projects
Estimated and incurred project costs referred to in the following table include 100 per cent of the capital expenditures related to
projects within entities that we own or partially own and fully consolidate, as well as our share of equity contributions to fund
projects within our equity investments, primarily Coastal GasLink and Bruce Power.
(billions of $)
Expected in-service date
Estimated project cost
Project costs incurred
at December 31, 2023
Canadian Natural Gas Pipelines
NGTL System
Coastal GasLink1
2024
2026+
2024
Regulated maintenance capital expenditures
2024-2026
U.S. Natural Gas Pipelines
Modernization and other2
Delivery market projects
Heartland project
Other capital
Regulated maintenance capital expenditures
Mexico Natural Gas Pipelines
Villa de Reyes – south section3
Tula4
Southeast Gateway
Liquids Pipelines
2024-2026
2025
2027
2024-2028
2024-2026
2024
—
2025
Recoverable maintenance capital expenditures
2024-2026
Power and Energy Solutions
Bruce Power – Unit 3 MCR
Bruce Power – Unit 4 MCR
Bruce Power – life extension5
Other
2026
2028
2024-2027
Non-recoverable maintenance capital expenditures6
2024-2026
Foreign exchange impact on secured projects7
Total secured projects (Cdn$)
0.7
0.7
5.5
2.3
US 1.7
US 1.5
US 0.9
US 1.5
US 2.2
US 0.3
US 0.4
US 4.5
0.3
1.1
0.9
1.8
0.4
26.7
4.2
30.9
0.5
0.1
4.6
—
US 0.9
US 0.2
—
US 0.5
—
US 0.3
US 0.3
US 2.4
—
0.6
0.1
0.7
—
11.2
1.5
12.7
1
2
3
4
5
6
7
The estimated project cost noted above represents our share of anticipated partner equity contributions to the project. Mechanical completion was achieved in
November 2023. Commercial in-service of the Coastal GasLink pipeline will occur after completion of plant commissioning activities at the LNG Canada facility
and upon receiving notice from LNG Canada. Refer to the Canadian Natural Gas Pipelines – Significant events section for additional information.
Includes 100 per cent of the capital expenditures related to our modernization program on Columbia Gas, as well as certain large-scope maintenance projects
across our U.S. natural gas pipelines footprint due to their discrete nature and timing for regulatory recovery. Refer to the U.S. Natural Gas Pipelines –
Significant events section for additional information.
We are working with the CFE on completing the remaining section of the Villa de Reyes pipeline, with an anticipated commercial in-service date in the second
half of 2024. Refer to the Mexico Natural Gas Pipelines – Significant events section for additional information.
Estimated project cost as per contracts signed in 2022 as part of the TGNH strategic alliance between TC Energy and the CFE. We continue to evaluate the
development and completion of the Tula pipeline, with the CFE, subject to a future FID and updated cost estimate. Refer to the Mexico Natural Gas Pipelines –
Significant events section for additional information.
Reflects amounts to be invested under the Asset Management program, other life extension projects and the incremental uprate initiative. Refer to the Power
and Energy Solutions – 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 assets.
Reflects U.S./Canada foreign exchange rate of 1.32 at December 31, 2023.
30 | TC Energy Management's discussion and analysis 2023
Projects under development
In addition to our secured projects, we are pursuing a portfolio of quality projects in various stages of development across each
of our business units. 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. While each business segment also has additional
areas of focus for further ongoing business development activities and growth opportunities, new opportunities will be assessed
within our capital allocation framework in order to fit within our annual capital expenditure parameters. As these projects
advance and reach 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, connections to growing shale gas supplies and other
opportunities supporting our reduction in GHG emissions intensity.
U.S. Natural Gas Pipelines
Delivery Market Projects
Projects are in development that are expected to replace, upgrade and expand certain U.S. Natural Gas Pipelines facilities while
reducing emissions along portions of our pipeline systems in principal delivery markets. The enhanced facilities are expected to
improve reliability of our systems and allow for additional transportation services under long-term contracts to address growing
demand in the U.S. Midwest and the Mid-Atlantic regions, while reducing direct GHG emissions.
Other Opportunities
We are currently pursuing a variety of projects, including compression replacement, while furthering the electrification of our
fleet, power generation and LDCs, expanding our modernization programs and in-corridor expansion opportunities on our
existing systems. These projects are expected to improve the reliability of our systems with a focus on cleaner energy.
We are actively developing RNG transportation hubs within our U.S. Natural Gas Pipelines footprint. These hubs are designed to
provide centralized access to existing energy transportation infrastructure for RNG sources, such as farms, wastewater treatment
facilities and landfills. We believe that the development of these hubs is an important step towards the acceleration of methane
capture projects and the concurrent reduction of GHG emissions.
We are also developing multiple transmission projects to link gas supply to the facilities that will serve the growing global
demand for North American LNG.
Mexico Natural Gas Pipelines
On August 4, 2022, we announced a strategic alliance with the CFE, Mexico’s state-owned electric utility, to accelerate the
development of natural gas infrastructure in the central and southeast regions of Mexico.
Liquids Pipelines
We remain focused on maximizing the value of our liquids assets by finding solutions to enable flexible and tailored solutions for
our customers. We continue to seek ways of optimizing our existing assets by extending connectivity between supply and
delivery markets. We are pursuing selective growth opportunities to add incremental value to our business and expansions that
leverage latent 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.
TC Energy Management's discussion and analysis 2023 | 31
Power and Energy Solutions
Bruce Power
Life Extension Program
The continuation of Bruce Power’s life extension program will require the investment of our proportionate share of both the MCR
program costs on Units 5, 7 and 8 and the remaining Asset Management program costs, which continue beyond 2033, extending
the life of Units 3 to 8 and the Bruce Power site to 2064. Preparation work for the Unit 5, 7 and 8 MCRs is underway and 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 $4.0 billion for our proportionate share of the Bruce Power MCR program costs for
Units 5, 7 and 8 and the remaining Asset Management program costs beyond 2027, as well as the incremental uprate initiative
discussed below.
Uprate Initiative
Bruce Power's Project 2030 has 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 is focused 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. 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, which began in early 2022, is targeting another 200 MW.
Ontario Pumped Storage
Along with the Saugeen Ojibway Nation, our prospective partner, we continue to advance the Ontario Pumped Storage Project
(OPSP), an energy storage facility located near Meaford, Ontario designed to provide 1,000 MW of flexible, clean energy to
Ontario's electricity system using a process known as pumped hydro storage. Next steps to advance the OPSP include:
• working with the Ministry of Energy (Ministry) and Ontario Energy Board on the establishment of a potential long-term
revenue framework by July 2024
• providing a breakdown of estimated development costs and schedule to the Ministry after which the Ministry will provide a
recommendation to proceed with pre-development work within 45 days
• negotiation of cost recovery agreement with the IESO to recover eligible, prudently incurred expenses associated with
pre-development work. A follow up report from the IESO to the Ministry to be provided within 60 days of estimates submission
• provide further information to assist with the Ontario government's assessment of OPSP societal and economic benefits.
A final decision to fund development costs of OPSP is subject to Cabinet approvals and Ministerial directive to the IESO to
execute agreements with us.
Once in service, this project would store emission-free energy when available and provide that energy to Ontario during periods
of peak demand, thereby maximizing the value of existing emission-free generation in the province.
The OPSP remains subject to approval by our Board of Directors and the Saugeen Ojibway Nation. Construction would begin in
the latter part of this decade with in-service in the early 2030s, subject to receipt of regulatory and corporate approvals.
Canyon Creek Pumped Storage
We are utilizing the existing site infrastructure from a decommissioned coal mine, located near Hinton, Alberta, to develop a
pumped hydro storage project that is expected to have a generating capacity of 75 MW. The facility is expected to 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 Government of Alberta for hydro projects under
the Dunvegan Hydro Development Act (Alberta).
32 | TC Energy Management's discussion and analysis 2023
Alberta Carbon Grid
In June 2021, we announced a partnership with Pembina Pipeline Corporation to jointly develop a world-scale system which,
when fully constructed, is expected to be capable of transporting and sequestering more than 20 million tonnes of CO2 annually.
As an open-access system, the Alberta Carbon Grid (ACG) is intended to serve as the backbone for Alberta’s emerging carbon
capture utilization and storage industry. In October 2022, ACG entered into a carbon sequestration evaluation agreement with
the Government of Alberta to further evaluate one of the largest Areas of Interest (AOI) for safely storing carbon from industrial
emissions in Alberta. ACG continues to progress an appraisal program needed to evaluate the suitability of our AOI, including the
advancement and completion of well drilling and testing activities to support the development of a detailed Measurement,
Monitoring and Verification plan required to apply for a sequestration permit.
Other Carbon Capture
We are collaborating with Minnkota Power Cooperative (Minnkota), Mitsubishi Heavy Industries and Kiewit on Project Tundra, a
next-generation technology carbon capture and storage project. Project Tundra would be our first carbon capture and
sequestration project in the U.S., capturing up to approximately four million tons of CO2 per annum from Minnkota’s Milton R.
Young Generating Station. When constructed, Project Tundra is expected to be the largest post-combustion carbon capture
project in North America and would support the continuation of baseload, reliable, power generation in the region. In December
2023, the U.S. Department of Energy and Office for Clean Energy Demonstrations announced up to US$350 million in funding for
Project Tundra.
Hydrogen Hubs
We are advancing multiple hydrogen production opportunities to potentially serve long-haul transportation, power generation,
large industrials and heating customers across the U.S. and Canada. We believe that measured investment in emerging
technologies like hydrogen will help us expand our capabilities through energy transition, focusing on opportunities that
complement our core business and where we can obtain favourable and strategically-consistent commercial arrangements such
as rate regulation and/or long-term contracts.
TC Energy Management's discussion and analysis 2023 | 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 – 64,207 km (39,896 miles)
• partially-owned natural gas pipelines – 29,372 km (18,251 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 532 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
Our strategy is to 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 in North America and developing new projects to provide connectivity to LNG export
terminals, both operating and proposed
• connections to growing Canadian and U.S. shale gas and other supplies
• decarbonizing our energy consumption, thereby reducing overall GHG emissions 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 emissions intensity reduction target, 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 RNG customers are connecting to our system. Our business model 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.
34 | TC Energy Management's discussion and analysis 2023
Recent highlights
Canadian Natural Gas Pipelines
• approximately $2.8 billion of capital projects placed in service in 2023 primarily related to the NGTL System and NGTL System/
Foothills West Path expansions, as well as spending on maintenance capital
• mechanical completion of the Coastal GasLink pipeline project in fourth quarter 2023
• CER approved the VNBR project in fourth quarter 2023
• achieved record throughput volumes on the NGTL System and Canadian Mainline.
U.S. Natural Gas Pipelines
• placed approximately US$1.6 billion of capital projects in service in 2023, including the North Baja XPress project, as well as
spending on modernization and maintenance capital
• sanctioned an additional US$1.6 billion of capital projects including the Heartland project on ANR and the Bison XPress project
on Northern Border
• sale of a 40 per cent non-controlling equity interest in Columbia Gas and Columbia Gulf for proceeds of $5.3 billion
(US$3.9 billion), which closed on October 4, 2023
• ANR, Columbia Gulf and Tuscarora rate case settlements approved by FERC
• achieved record throughput volumes on a number of our pipelines.
Mexico Natural Gas Pipelines
• the Southeast Gateway pipeline project is progressing according to planned milestones and began construction on all facilities
and installations in Veracruz and Tabasco, as well as offshore pipe laying at the end of 2023
• the lateral section of the Villa de Reyes pipeline was placed in commercial service in third quarter 2023
• in December 2023, TGNH and the CFE obtained from Mexico's Federal Economic Competition Commission (COFECE) a
favourable merger ruling and a determination that the proposed minority CFE equity participation in TGNH did not require a
favourable cross participation opinion given that the CFE would not have a controlling interest in TGNH. TGNH and the CFE
subsequently requested the CRE to confirm that a cross participation permit is not required given that the CFE would not have
a controlling interest in TGNH
• overall pipeline utilization continued to increase.
TC Energy Management's discussion and analysis 2023 | 35
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 39 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 and Foothills System: These are 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 or expansions of the system or future connections to other pipelines serving that
area.
Canadian Mainline: This pipeline supplies markets in the Canadian Prairies, Ontario, Québec, the Canadian Maritimes, as well as
to the U.S. markets including Great Lakes, Midwest, Gulf Coast and U.S. Northeast 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. We own a 60 per cent equity interest and are the operator of this pipeline.
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. We own a 60 per cent equity interest and are
the operator of this pipeline.
Other U.S. Natural Gas Pipelines: We have ownership interests in ten wholly-owned or partially-owned natural gas pipelines
serving major markets in the U.S.
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 2023 supplied approximately 17 per cent of Mexico's total
natural gas imports via pipelines. We own a 60 per cent equity interest 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.
36 | TC Energy Management's discussion and analysis 2023
TGNH System: This system is located in the central region of Mexico and is comprised of the existing Tamazunchale pipeline, the
Tula, Villa de Reyes and Southeast Gateway pipelines with sections that are either in-service or currently under construction. This
system supplies, or will supply, several power plants and industrial facilities in Veracruz, Tabasco, San Luis Potosí, Querétaro and
Hidalgo. It has interconnects with upstream pipelines that bring in supply from the Agua Dulce and Waha hubs 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 the 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 135 Bcf/d by 2027, reflecting an increase of approximately 28 Bcf/d
from 2022 levels.
As the world shifts toward lower GHG emission-intensive fuel sources, we believe that 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. We expect that this projected growth in demand for natural gas, coupled with the anticipated
increases in key producing areas like WCSB, onshore Gulf Coast, Appalachian and the Permian basin, will provide investment
opportunities for pipeline infrastructure companies to build new facilities or increase utilization of their existing footprint.
Modernizing our existing systems and assets, and decarbonizing energy consumption along our natural gas pipeline systems is
expected to provide ongoing additional capital investment opportunities that will meet our risk preferences while supporting our
GHG emissions intensity reduction goal.
TC Energy Management's discussion and analysis 2023 | 37
Changing demand
The abundant supply of natural gas has supported increased demand, particularly in the following areas:
• natural gas-fired power generation
• global LNG exports
• 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, and the east and west coasts of
Canada, the U.S. and Mexico. The increasing export of natural gas to Mexico is driven by the CFE’s need to serve existing markets
and requires pipelines to serve new regions. We believe that natural gas is a key energy transition fuel for Mexico.
Overall, we are forecasting significant gas demand growth in the future to support economic expansion and industrial load
growth, conversion to lower GHG emission-intensive fuels for industrial and power generation use, and LNG export prospects.
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.
Commodity prices
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 commitments and targets, including GHG
emissions intensity reduction.
In 2024, we will continue to focus on the execution of our existing capital program that includes progressing construction on our
Southeast Gateway pipeline in Mexico, investment in the NGTL System, as well as the completion and initiation of new pipeline
projects in the United States. We will remain focused on capital discipline as we 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,
the environment and the general public impacted by the construction and operation of these facilities.
Our marketing entities will complement our natural gas 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.
38 | TC Energy Management's discussion and analysis 2023
TC Energy Management's discussion and analysis 2023 | 39
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
6 Great Lakes Canada
U.S. pipelines and gas storage assets
7
Columbia Gas
24,386 km
(15,153 miles)
14,082 km
(8,750 miles)
1,284 km
(798 miles)
651 km
(405 miles)
133 km
(83 miles)
60 km
(37 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 Canadian and
U.S. markets.
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.
18,692 km
(11,615 miles)
Transports natural gas primarily from the Appalachian basin
to markets and pipeline interconnects throughout the U.S.
Northeast, Midwest and Atlantic regions.
7a Columbia Storage
285 Bcf
Provides regulated underground natural gas storage service
from several facilities (not all shown) to customers in key
eastern markets. We own a 60 per cent interest in the
273 Bcf Columbia Storage facility and a 50 per cent interest
in the 12 Bcf Hardy Storage facility.
100%
100%
100%
50%
100%
100%
60%
Various
8
ANR3
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%
8a ANR Storage
247 Bcf
9
Columbia Gulf
10 Great Lakes
11 Northern Border
12 Gas Transmission Northwest (GTN)
13 Iroquois
14 Tuscarora
15 Bison
16 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.
60%
100%
50%
100%
50%
100%
100%
61.7%
40 | TC Energy Management's discussion and analysis 2023
17 Millennium
18 Crossroads
19 North Baja3
Mexico pipelines
20 Sur de Texas
21 Topolobampo
22 Mazatlán
23 Tamazunchale
24 Villa de Reyes – north and lateral section
25 Guadalajara
26 Tula – east section
Under construction
Canadian pipelines
27 Coastal GasLink
NGTL System 2024 Facilities1
U.S. pipelines
East Lateral XPress1,3
Gillis Access Project2
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)
326 km
(203 miles)
313 km
(194 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.
The north and lateral sections of the Villa de Reyes pipeline
are interconnected to our Tamazunchale pipeline and third-
party systems, supporting gas deliveries to power plants in
Villa de Reyes, San Luis Potosí and Salamanca, Guanajuato.
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.
114 km
(71 miles)
The east section of the Tula pipeline transports natural gas
from Sur de Texas to power plants in Tuxpan, Veracruz.
670 km
(416 miles)
n/a
n/a
A greenfield project to deliver natural gas from the Montney
gas producing region to LNG Canada's liquefaction facility
near Kitimat, British Columbia. Coastal GasLink pipeline was
mechanically complete in November 2023 and is ready to
deliver gas to the LNG Canada facility. Commercial in-service
of the Coastal GasLink pipeline will occur after completion
of plant commissioning activities at the LNG Canada facility
and upon receiving notice from LNG Canada.
Compressor station components of the 2023 NGTL System
Intra-Basin Expansion expected to be placed in service in
2024.
An expansion project on Columbia Gulf through compressor
station modifications and additions expected to be placed in
service in 2025.
68 km
(42 miles)
A greenfield pipeline system project that will connect
supplies from the Haynesville basin at Gillis, Louisiana to
markets elsewhere in Louisiana. The project is expected to
be placed in service in 2024.
Ownership
47.5%
100%
100%
60%
100%
100%
100%
100%
100%
100%
35%
100%
60%
100%
TC Energy Management's discussion and analysis 2023 | 41
Under construction (continued)
GTN XPress3
Length
n/a
Description
An expansion project of GTN through compressor station
modifications and additions with the remaining sections
expected to be placed in service in 2024.
Ownership
100%
Mexico pipelines
28
Southeast Gateway
29
Villa de Reyes – south section
30
Tula2
715 km
(444 miles)
110 km
(68 miles)
n/a
Offshore pipeline that will connect to the Tula pipeline and
transport gas to delivery points in Coatzacoalcos, Veracruz
and Paraíso, Tabasco in Mexico’s southeast region.
This pipeline section will connect to the operational north
and lateral sections of the Villa de Reyes pipeline and to the
Tula pipeline.
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. TC Energy and CFE are assessing options to
complete the remaining sections of the pipeline, which are
subject to an FID.
100%
100%
100%
Permitting and pre-construction phase
Canadian pipelines
NGTL System 2025+ Facilities1,2
U.S. pipelines
Bison XPress Project3
VR Project3
WR Project3
Ventura XPress Project3
Heartland Project3
50 km
(31 miles)
The VNBR project, along with other facilities expected to be
placed in service in 2026.
100%
n/a
n/a
n/a
n/a
n/a
A project with Northern Border, a 50 per cent owned
subsidiary, and Bison, a wholly-owned subsidiary, that will
replace and upgrade certain facilities while improving
reliability, which is expected to be placed in service in 2026
A delivery market project on Columbia Gas that will replace
and upgrade certain facilities while improving reliability and
reducing emissions, which is expected to be placed in service
in 2025.
A delivery market project on ANR that will replace and
upgrade certain facilities while improving reliability and
reducing emissions, which is expected to be placed in service
in 2025.
A project on ANR that will replace and upgrade certain
facilities improving base system reliability, which is expected
to be placed in service in 2025.
Expansion project on ANR that will increase capacity and
improve system reliability with upgrades to compression
facilities, expected to be placed in service in 2027.
Various
60%
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.
Includes compressor station modifications, additions and/or expansion projects with no additional pipe length.
42 | TC Energy Management's discussion and analysis 2023
Canadian Natural Gas Pipelines
UNDERSTANDING OUR CANADIAN NATURAL GAS PIPELINES SEGMENT
The Canadian Natural Gas Pipelines 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 the Coastal GasLink pipeline, which reached mechanical completion in
fourth quarter 2023 and is regulated by the BC Energy Regulator (formerly the BC Oil & Gas Commission).
For the interprovincial natural gas pipelines it regulates, the CER approves tolls, facilities and services that are in the public
interest and provide a reasonable opportunity for the 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 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.
Subject to approval by the CER, we and our customers can also establish settlement arrangements 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. 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
The 670 km (416 mile) Coastal GasLink pipeline project successfully achieved mechanical completion, completed required
commissioning activities and was ready to deliver gas to the LNG Canada facility in fourth quarter 2023. These milestones entitle
Coastal GasLink LP to receive a $200 million incentive payment from LNG Canada. In accordance with the contractual terms
between the Coastal GasLink LP partners, this amount accrues in full to TC Energy as the project developer and was settled
through a cash distribution on February 12, 2024. We recognized the incentive payment as Income (loss) from equity
investments in the Consolidated statement of income for the year ended December 31, 2023 and recorded a corresponding
amount in Accounts receivable on the Consolidated balance sheet.
Through 2024, Coastal GasLink LP will continue post-construction reclamation activities. Coastal GasLink LP also continues to
pursue cost recovery, including certain arbitration proceedings which involve claims by, and the defense of certain claims
against, Coastal GasLink LP. These claims have not yet been conclusively determined, but our expectation is that these
proceedings are likely to result in cost recoveries. For more information on these proceedings, refer to Note 32, Commitments,
contingencies and guarantees, of our 2023 Consolidated financial statements for additional information. The project remains on
track with its cost estimate of approximately $14.5 billion.
Commercial in-service of the Coastal GasLink pipeline will occur after completion of plant commissioning activities at the
LNG Canada facility and upon receiving notice from LNG Canada. Once in service, the pipeline will transport natural gas from a
receipt point in the Dawson Creek area of British Columbia to LNG Canada's natural gas liquefaction facility near Kitimat, British
Columbia. Transportation service on the pipeline is underpinned by 25-year TSAs (with renewal provisions) with each of the five
LNG Canada participants. We hold a 35 per cent ownership interest in Coastal GasLink LP, the partnership entity that owns the
pipeline and that has been contracted to develop, construct and operate the pipeline.
TC Energy Management's discussion and analysis 2023 | 43
In 2022, Coastal GasLink LP executed definitive agreements with LNG Canada, TC Energy and the other Coastal GasLink LP
partners (collectively, the July 2022 agreements) that amended existing project agreements to address and resolve disputes over
certain incurred and anticipated costs of the Coastal GasLink pipeline project. Project costs are funded by existing project-level
credit facilities and equity contributions from the Coastal GasLink LP partners, including us. Beginning in 2023, the equity
financing required to fund construction of the pipeline to completion is initially provided through a subordinated loan
agreement between TC Energy and Coastal GasLink LP. Draws by Coastal GasLink LP on this loan will be repaid with funds from
equity contributions to the partnership by the Coastal GasLink LP partners, including us, subsequent to the in-service date of the
Coastal GasLink pipeline when final project costs are known. We expect that, in accordance with contractual terms, the
additional equity contributions required will be predominantly funded by us, except under certain conditions, but will not result
in a change to our 35 per cent ownership. At December 31, 2023, committed capacity under this subordinated loan agreement
was $3,375 million, on which $2,520 million was drawn.
The expectation that additional equity contributions will predominantly be funded by us was an indicator during the first three
quarters of 2023 that a decrease in the value of our equity investment had occurred. As a result, we completed valuation
assessments and concluded that there was an other-than-temporary impairment of our investment, resulting in a pre-tax
impairment charge on our investment in Coastal GasLink LP of $2,100 million ($1,943 million after tax) for the year ended
December 31, 2023. The impairment charge reflected the net impact of changes in the subordinated loan for the nine months
ended September 30, 2023, along with TC Energy’s proportionate share of unrealized gains and losses on interest rate derivatives
in Coastal GasLink LP and other changes to the equity investment. The impairment of the subordinated loan resulted in
unrealized non-taxable capital losses that are not recognized. The cumulative pre-tax impairment charge recognized to date at
December 31, 2023 is $5,148 million ($4,586 million after tax). Refer to Note 8, Coastal GasLink, of our 2023 Consolidated
financial statements for additional information.
At December 31, 2023, the carrying value of our equity investment was $294 million. There was no indicator that there was an
other-than-temporary impairment of this investment, and no impairment charge was recognized in fourth quarter 2023.
NGTL System and Foothills
In the year ended December 31, 2023, the NGTL System and Foothills placed approximately $2.0 billion and $0.8 billion,
respectively, of capacity projects in service. The details of the significant capacity programs are listed below.
2021 NGTL System Expansion Program
The 2021 NGTL System Expansion Program consists of 344 km (214 miles) of new pipeline, three new compressor units and
associated facilities and is expected to add 1.59 PJ/d (1.45 Bcf/d) of incremental capacity to the NGTL System. Construction of
the expansion program is nearing completion with an estimated capital cost of the program of $3.6 billion. As of
December 31, 2023, $3.4 billion of the program's facilities have been placed in service, including all facilities required to declare
contracts.
2022 NGTL System Expansion Program
The 2022 NGTL System Expansion Program was completed in 2023 and consists of approximately 166 km (103 miles) of new
pipeline, one compressor unit and associated facilities and provides incremental capacity of approximately 773 TJ/d
(722 MMcf/d) to meet firm-receipt and intra-basin delivery requirements with eight-year minimum terms. The capital cost of the
program was $1.4 billion with all assets placed in service.
NGTL System/Foothills West Path Delivery Program
The NGTL System/Foothills West Path Delivery Program was a multi-year expansion of the NGTL System and Foothills system to
facilitate incremental contracted export capacity connecting to the GTN pipeline system. The combined NGTL System and
Foothills program consists of approximately 107 km (66 miles) of pipeline and associated facilities and is underpinned by
275 TJ/d (258 MMcf/d) of new firm-service contracts with terms that exceed 30 years. The capital cost of the program was
$1.6 billion with all remaining assets placed in service in 2023.
2023 NGTL System Intra-Basin Expansion
The NGTL System Intra-Basin Expansion consists 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. The estimated capital
cost of the expansion is $0.5 billion. Construction activities commenced in 2022 with the pipeline placed in service in late 2023
and construction of the compressor stations is underway with anticipated in-service by second quarter 2024.
44 | TC Energy Management's discussion and analysis 2023
Valhalla North and Berland River Project
The VNBR project will serve aggregate system requirements and connect migrating supply to key demand markets, providing
incremental capacity on the NGTL System of approximately 428 TJ/d (400 MMcf/d) and is expected to contribute to lower
GHG emission intensity for the overall system. With an estimated capital cost of $0.6 billion, the project consists of
approximately 33 km (21 miles) of new pipeline, one new non-emitting electric compressor unit and associated facilities. On
December 21, 2023, we received approval from the CER to construct, own and operate the VNBR project with an anticipated
in-service date in second quarter 2026.
FINANCIAL RESULTS
The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings
(losses)(the most directly comparable GAAP measure). Refer to page 11 for more information on non-GAAP measures we use.
year ended December 31
(millions of $)
NGTL System
Canadian Mainline
Other Canadian pipelines1
Comparable EBITDA
Depreciation and amortization
Comparable EBIT
Specific item:
Coastal GasLink impairment charge
Segmented earnings (losses)
2023
2,201
789
345
3,335
(1,325)
2,010
(2,100)
(90)
2022
1,853
770
183
2,806
(1,198)
1,608
(3,048)
(1,440)
2021
1,649
838
188
2,675
(1,226)
1,449
—
1,449
1
Includes results from Foothills, Ventures LP, Great Lakes Canada and our proportionate share of income related to investments in TQM and Coastal GasLink, as
well as general and administrative and business development costs related to our Canadian Natural Gas Pipelines.
Canadian Natural Gas Pipelines segmented losses in 2023 decreased by $1.4 billion compared to 2022. Canadian Natural Gas
Pipelines segmented losses were $1.4 billion in 2022 compared to segmented earnings of $1.4 billion in 2021. A pre-tax
impairment charge in 2023 of $2.1 billion (2022 – $3.0 billion) related to our equity investment in Coastal GasLink LP was
recognized, which has been excluded from our calculation of comparable EBITDA and comparable EBIT. Refer to Note 8, Coastal
GasLink, of our 2023 Consolidated financial statements for additional information.
Net income and comparable EBITDA for our rate-regulated Canadian natural gas pipelines are primarily affected by our approved
ROE, 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
2023
2022
2021
770
230
19,008
3,709
708
223
17,493
3,735
631
213
15,560
3,724
TC Energy Management's discussion and analysis 2023 | 45
Net income for the NGTL System increased by $62 million in 2023 compared to 2022 and by $77 million in 2022 compared to 2021
mainly due to a higher average investment base resulting from continued system expansions. The NGTL System is operating
under the 2020-2024 Revenue Requirement Settlement, which includes an approved 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 $7 million in 2023 compared to 2022 and by $10 million in 2022 compared to
2021 mainly as a result of higher incentive earnings. 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.
Comparable EBITDA
Comparable EBITDA for Canadian Natural Gas Pipelines was $529 million higher in 2023 compared to 2022 primarily due to the
net effect of:
• higher flow-through financial charges, depreciation and income taxes, as well as higher rate-base earnings on the NGTL
System
• earnings from Coastal GasLink related to the recognition of a $200 million incentive payment upon meeting certain
milestones, partially offset by lower development fee revenue resulting from timing of revenue recognition. Refer to the
Canadian Natural Gas Pipelines – Significant events section for additional information
• higher flow-through depreciation, financial charges and higher incentive earnings, partially offset by lower flow-through
income taxes on the Canadian Mainline.
Comparable EBITDA for Canadian Natural Gas Pipelines in 2022 was $131 million higher than 2021 primarily due to the net effect
of:
• higher flow-through financial charges and depreciation, as well as increased rate-base earnings on the NGTL System
• lower flow-through depreciation, partially offset by higher flow-through income taxes and financial charges and increased
incentive earnings on the Canadian Mainline
• lower Coastal GasLink development fee revenue due to timing of revenue recognition.
Depreciation and amortization
Depreciation and amortization was $127 million higher in 2023 compared to 2022 due to higher depreciation on the NGTL System
from expansion facilities that were placed in service and on the Canadian Mainline due to assets placed in service on a section
with higher depreciation rates per the terms of the 2021-2026 Mainline Settlement. Depreciation and amortization was
$28 million lower in 2022 compared to 2021 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.
46 | TC Energy Management's discussion and analysis 2023
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 in 2024 is expected to be consistent with 2023 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; offset by the Coastal GasLink incentive payment recognized in 2023 for achieving certain milestones. Due to the
flow-through treatment of certain costs on our Canadian rate-regulated pipelines, changes in these costs can impact our
comparable EBITDA despite having no significant effect on comparable earnings. We expect our comparable earnings in 2024 for
the NGTL System and the Canadian Mainline to be consistent with 2023.
Capital expenditures
We incurred $2.6 billion in 2023 in our Canadian Natural Gas Pipelines business on growth projects and maintenance capital
expenditures. We expect to incur approximately $1.2 billion in 2024, primarily on NGTL System expansion projects and
maintenance capital expenditures, all of which are immediately reflected in investment base and related earnings.
We also contributed $3.0 billion to our investment in Coastal GasLink LP in 2023 and expect to contribute $0.9 billion in 2024.
Refer to the Canadian Natural Gas Pipelines – Significant events section for additional information.
TC Energy Management's discussion and analysis 2023 | 47
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. interstate 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 recently, and will continue to, produce new rules affecting numerous aspects of operation
and maintenance of our pipeline system. PHMSA’s priorities are generally dictated by legislation which is influenced by numerous
stakeholders and informed by learnings from recent industry incidents and stakeholder priorities. When PHMSA implements new
rules TC Energy seeks recovery of additional expenditures driven by such rules in future rate cases and modernization
settlements.
SIGNIFICANT EVENTS
Columbia Gas and Columbia Gulf Monetization
On October 4, 2023, we successfully completed the sale of a 40 per cent non-controlling equity interest in Columbia Gas and
Columbia Gulf to Global Infrastructure Partners (GIP) for proceeds of $5.3 billion (US$3.9 billion). Columbia Gas and Columbia
Gulf are held by a newly formed entity with GIP. Preceding the close of the equity sale, on August 8, 2023, Columbia Pipelines
Operating Company LLC and Columbia Pipelines Holding Company LLC issued US$4.6 billion and US$1.0 billion of long-term,
senior unsecured debt, respectively. The net proceeds from the offerings were used to repay existing intercompany indebtedness
with TC Energy entities and directed towards reducing leverage. Refer to the Financial Condition section for additional
information.
We continue to have a controlling interest in Columbia Gas and Columbia Gulf and we remain the operator of these pipelines.
TC Energy and GIP will each fund their proportionate share of annual maintenance, modernization and sanctioned growth
capital expenditures through internally generated cash flows, debt financing within the Columbia entities, or from proportionate
contributions from TC Energy and GIP.
ANR Section 4 Rate Case
ANR reached a settlement with its customers effective August 2022 and received FERC approval in April 2023. As part of the
settlement, there is a moratorium on any further rate changes until November 1, 2025. ANR must file for new rates with an
effective date no later than August 1, 2028. The settlement also included an additional rate step up effective August 2024
related to certain modernization projects. In second quarter 2023, previously accrued rate refund liabilities, including interest,
were refunded to customers.
Columbia Gulf Rate Settlement
On July 7, 2023, Columbia Gulf filed an uncontested rate settlement which would set new recourse rates for Columbia Gulf
effective March 1, 2024 and institute a rate moratorium through February 28, 2027. The revised rates are not expected to have a
significant impact on our U.S. Natural Gas Pipelines segment comparable earnings. Columbia Gulf must file for new rates no later
than March 1, 2029.
48 | TC Energy Management's discussion and analysis 2023
Line VB Strasburg
On July 25, 2023, a natural gas pipeline rupture on Columbia Gas occurred alongside Interstate 81 in Strasburg, Virginia.
Emergency response procedures were enacted and the segment of impacted pipeline was isolated shortly thereafter. There were
no reported injuries involved with this incident and no significant damage to surrounding structures. The pipeline has been
operating at reduced pressure in accordance with PHMSA’s Corrective Action Order (CAO) since July 28, 2023 and we are working
with PHMSA under the CAO to return the system to normal operations as soon as possible. The Root Cause Failure Analysis (RCFA)
findings indicated that similar pipeline segment locations within the Columbia Gas pipeline system require further testing;
however, we do not expect the Line VB Strasburg event or the additional testing to have a material impact on our financial
results.
North Baja XPress
In June 2023, the North Baja XPress project, an expansion project designed to expand capacity and meet increased customer
demand on our North Baja pipeline, was placed in service. The capital cost of this project was approximately US$0.1 billion.
Bison XPress Project
In third quarter 2023, we approved the Bison XPress project, an expansion project on our Northern Border and Bison systems that
will replace and upgrade certain facilities and provide much needed production egress from the Bakken basin to a delivery point
at the Cheyenne Hub. The project has an anticipated in-service date in 2026. Total estimated project costs are US$0.4 billion, of
which our share is US$0.2 billion, representing our 50 per cent equity investment in Northern Border and 100 per cent ownership
in Bison.
GTN XPress Project
In October 2023, FERC provided a certificate order approving our GTN XPress project. The GTN XPress project is an expansion of
the GTN system that will provide for the transport of incremental contracted export capacity facilitated by the
NGTL System/Foothills West Path Delivery Program. The anticipated in-service date is in 2024 with an estimated project cost of
US$0.1 billion.
VR and WR Projects
In November and December 2023, the FERC provided a certificate order approving our VR and WR projects, respectively. The
VR project will provide incremental capacity from Greensville County, Virginia to delivery points in Norfolk, Virginia. The
anticipated in-service date is late 2025 with an estimated project cost of US$0.7 billion. The WR project will provide mainline
capacity to multiple points of delivery on our ANR System in Wisconsin. The anticipated in-service date is late 2025 with an
estimated project cost of US$0.8 billion.
Virginia Electrification Project
In February 2024, the Virginia Electrification project, an expansion project that replaced and upgraded certain facilities through
conversion to electric compression, reducing GHG emissions intensity along portions of our Columbia Gas system, was placed in
service with a capital cost of approximately US$0.1 billion.
Heartland Project
In February 2024, we approved the Heartland project, an expansion project on our ANR system that is expected to increase
capacity and improve system reliability. The Heartland project involves pipeline looping, compressor facility additions, as well as
upgrades, and upon in-service, will increase ANR’s overall market share in the Midwest region. The anticipated in-service date is
late 2027 with an estimated project cost of US$0.9 billion.
TC Energy Management's discussion and analysis 2023 | 49
FINANCIAL RESULTS
The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings
(losses) (the most directly comparable GAAP measure). Refer to page 11 for more information on non-GAAP measures we use.
The table below reflects 100 per cent of comparable EBITDA on assets we own or partially own and fully consolidate, as well as
equity income for assets we own an equity interest in and do not consolidate.
year ended December 31
(millions of US$, unless otherwise noted)
Columbia Gas1
ANR
Columbia Gulf1
GTN2
Great Lakes2
Portland1
Other U.S. pipelines3
Comparable EBITDA
Depreciation and amortization
Comparable EBIT
Foreign exchange impact
Comparable EBIT (Cdn$)
Specific items:
Great Lakes goodwill impairment charge
Risk management activities
Segmented earnings (losses) (Cdn$)
2023
1,530
650
208
202
183
104
371
3,248
(692)
2,556
895
3,451
—
80
3,531
2022
1,511
582
207
184
178
101
379
3,142
(681)
2,461
742
3,203
(571)
(15)
2,617
2021
1,529
592
220
170
176
78
310
3,075
(630)
2,445
620
3,065
—
6
3,071
1
2
3
Includes non-controlling interest. Refer to the Corporate - Financial results section for additional information.
Reflects 100 per cent of comparable EBITDA in GTN and Great Lakes, subsequent to the TC PipeLines, LP acquisition in March 2021.
Reflects comparable EBITDA from our ownership in our mineral rights business (CEVCO), North Baja, Tuscarora, Bison, Crossroads and our share of equity income
from Northern Border, Iroquois, Millennium and Hardy Storage, our U.S. natural gas marketing business, as well as general and administrative and business
development costs related to our U.S. natural gas pipelines.
U.S. Natural Gas Pipelines segmented earnings in 2023 increased by $914 million compared to 2022 and decreased by
$454 million in 2022 compared to 2021 and included the following specific items, which have been excluded from our
calculation of comparable EBITDA and comparable EBIT:
• a pre-tax goodwill impairment charge of $571 million related to Great Lakes in first quarter 2022
• unrealized gains and losses from changes in the fair value of derivatives used in our U.S. natural gas marketing business.
A stronger U.S. dollar in 2023 and 2022 had a positive impact on the Canadian dollar equivalent segmented earnings from our
U.S. operations compared to 2022 and 2021, respectively. Refer to the Foreign Exchange section for additional information.
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 Gas 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.
50 | TC Energy Management's discussion and analysis 2023
Comparable EBITDA for U.S. Natural Gas Pipelines was US$106 million higher in 2023 than 2022 primarily due to the net effect of:
• incremental earnings from growth and modernization projects placed in service and additional contract sales on Columbia
Gas, ANR and Great Lakes
• a net increase in earnings from ANR following the FERC-approved settlement for higher transportation rates effective
August 2022, partially offset by decreased earnings due to the sale of natural gas from certain gas storage facilities in 2022
• higher realized earnings related to our U.S. natural gas marketing business primarily due to higher margins
• increased equity earnings from Iroquois and Northern Border
• decreased earnings due to higher operational costs, reflective of increased system utilization across our footprint, as well as
higher property taxes related to projects in service
• reduced earnings from our mineral rights business due to lower commodity prices.
Comparable EBITDA for U.S. Natural Gas Pipelines was US$67 million higher in 2022 than 2021 primarily due to the net effect of:
• incremental earnings from growth projects placed in service
• increased earnings from our mineral rights business due to higher commodity prices
• a net increase in earnings from Columbia Gas following the FERC-approved settlement for higher transportation rates effective
February 2021, partially offset by higher property taxes as a result of projects placed in service
• decreased earnings due to the impact of cold weather events and other discrete items recognized in 2021
• a decrease in earnings from ANR as a result of certain fourth quarter 2022 adjustments related to regulatory deferrals, partially
offset by higher transportation rates effective August 1, 2022, both pursuant to the ANR uncontested rate settlement.
Depreciation and amortization
Depreciation and amortization was US$11 million higher in 2023 compared to 2022 and US$51 million higher in 2022 compared to
2021. The increase in depreciation in both years is primarily due to the net effect of new projects placed in service, while 2023 is
partially offset by certain adjustments made in third quarter 2023.
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 2024 is expected to be higher than 2023. This is primarily due to the completion
of expansion projects in 2023 and anticipated completion of expansion projects in 2024 on the Columbia Gas and GTN systems,
as well as the in-service of the Gillis Access project and higher revenues on Columbia Gas due to return on and recovery of
modernization capital costs. Our pipeline systems continue to see historically strong demand for service and we anticipate that
during 2024, our assets will maintain the high utilization levels experienced in 2023. These positive results are expected to be
partially offset by higher operational costs, reflective of continued increases to system utilization across our footprint and an
anticipated increase in property taxes from capital projects placed in service.
Capital expenditures
We incurred a total of US$2.1 billion in 2023 on our U.S. natural gas pipelines and expect to incur approximately US$1.9 billion in
2024 primarily on our Gillis Access, Columbia Gulf, ANR and Columbia Gas expansion projects and 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. We expect net capital expenditures in 2024 to be approximately US$1.4 billion after considering
capital expenditures attributable to the non-controlling interests of entities we control.
TC Energy Management's discussion and analysis 2023 | 51
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
TGNH Strategic Alliance with the CFE
In August 2022, we announced a strategic alliance with Mexico’s state-owned electric utility, the CFE, for the development of
new natural gas infrastructure in central and southeast Mexico. In connection with the strategic alliance, we reached an FID to
develop and construct the Southeast Gateway pipeline, a 1.3 Bcf/d, 715 km (444 mile) offshore natural gas pipeline to serve the
southeast region of Mexico with an expected in-service by mid-2025 and an estimated project cost of US$4.5 billion.
We placed the lateral section of the Villa de Reyes pipeline into service in third quarter 2023. Construction of the south section of
the Villa de Reyes pipeline is targeted for mechanical completion in the second half of 2024, subject to successful resolution of
stakeholder issues. Additionally, we continue to evaluate the development and completion of the Tula pipeline with the CFE,
which is subject to a future FID. Due to the delay of an FID, effective November 1, 2023, we have suspended recording AFUDC on
the assets under construction for the Tula pipeline project.
The strategic alliance provides the CFE with the ability to hold an equity interest in TGNH, which is conditional upon the CFE
contributing capital, acquiring land and supporting permitting on the TGNH projects, subject to regulatory approvals from
COFECE and the CRE. Upon in-service of the Southeast Gateway pipeline and the completion of certain other contractual
obligations, the CFE’s equity interest in TGNH will equal approximately 15 per cent, and will increase to approximately
35 per cent upon expiry of the contract in 2055. In December 2023, TGNH and the CFE obtained from COFECE, a favourable
merger ruling and a determination that the proposed minority CFE equity participation in TGNH did not require a favourable
cross participation opinion given that the CFE would not have a controlling interest in TGNH. TGNH and the CFE subsequently
requested the CRE to confirm that a cross participation permit is not required given that the CFE would not have a controlling
interest in TGNH. TGNH anticipates receiving CRE’s approval in early 2024.
52 | TC Energy Management's discussion and analysis 2023
FINANCIAL RESULTS
The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings
(losses) (the most directly comparable GAAP measure). Refer to page 11 for more information on non-GAAP measures we use.
year ended December 31
(millions of US$, unless otherwise noted)
2023
2022
2021
TGNH1
Topolobampo
Sur de Texas2
Guadalajara
Mazatlán
Comparable EBITDA
Depreciation and amortization
Comparable EBIT
Foreign exchange impact
Comparable EBIT (Cdn$)
Specific item:
Expected credit loss provision on net investment in leases
and certain contract assets in Mexico
Segmented earnings (losses) (Cdn$)
232
157
75
61
71
596
(66)
530
186
716
80
796
164
161
112
73
67
577
(76)
501
153
654
(163)
491
118
161
113
71
70
533
(86)
447
110
557
—
557
1
2
Includes the operating sections of the Tamazunchale, Villa de Reyes and Tula pipelines.
Includes our share of 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 2023 increased by $305 million compared to 2022 and decreased by
$66 million in 2022 compared to 2021 and included the impact of an $80 million recovery in 2023 (2022 – $163 million loss) on
the expected credit loss provision related to the TGNH net investment in leases and certain contract assets in Mexico, which we
have excluded from our calculation of comparable EBITDA and comparable EBIT. Refer to Note 29, Risk management and
financial instruments, of our 2023 Consolidated financial statements for additional information.
A stronger U.S. dollar in 2023 and 2022 had a positive impact on the Canadian dollar equivalent segmented earnings from our
U.S. dollar-denominated operations in Mexico compared to 2022 and 2021, respectively. Refer to the Foreign Exchange section
for additional information.
Comparable EBITDA for Mexico Natural Gas Pipelines increased by US$19 million in 2023 compared to 2022 mainly due to:
• higher earnings in TGNH primarily related to the commercial in-service of the north section of the Villa de Reyes pipeline
(VdR North) and the east section of the Tula pipeline (Tula East) in third quarter 2022, as well as the commercial in-service of
the lateral section of the Villa de Reyes pipeline (VdR Lateral) in third quarter 2023
• lower earnings from Guadalajara primarily due to lower fixed revenue in accordance with the current transportation contract
and higher operating costs associated with a disruption of service due to a weather event
• lower equity earnings in Sur de Texas primarily due to foreign exchange impacts upon the revaluation of peso-denominated
liabilities as a result of a stronger Mexican peso and increased interest expense due to higher interest rates. We use foreign
exchange derivatives to manage this exposure, the impact of which is recognized in Foreign exchange (gains) losses, net in the
Consolidated statement of income. Refer to the Foreign exchange section for additional information.
Comparable EBITDA for Mexico Natural Gas Pipelines increased by US$44 million in 2022 compared to 2021 primarily due to
higher revenues related to the commercial in-service of VdR North and Tula East in third quarter 2022.
TC Energy Management's discussion and analysis 2023 | 53
In 2017, we entered into a MXN$21.3 billion unsecured revolving credit facility with the Sur de Texas joint venture. This
peso-denominated inter-affiliate loan was fully repaid upon maturity on March 15, 2022 and replaced with a new
U.S. dollar-denominated inter-affiliate loan. In July 2022, the Sur de Texas joint venture entered into an unsecured
U.S. dollar-denominated term loan agreement with third parties and used the proceeds to fully repay the U.S.
dollar-denominated inter-affiliate loan with TC Energy. Our share of related interest expense in Sur de Texas prior to this
refinancing was fully offset by corresponding interest income recorded in Interest income and other in the Corporate segment.
Depreciation and amortization
Depreciation and amortization was US$10 million lower in 2023 compared to 2022 and in 2022 compared to 2021 due to the
change to lease accounting for Tamazunchale subsequent to the execution of the TGNH TSA with the CFE in mid-2022. Under
sales-type lease accounting, our in-service TGNH pipeline assets are reflected on our Consolidated balance sheet within net
investment in leases with no depreciation expense being recognized.
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 in service. Comparable EBITDA for 2024 is expected to be
higher than 2023 due to full-year, incremental revenue from VdR Lateral that was placed in commercial service in third quarter
2023.
Capital expenditures
We incurred a total of US$1.8 billion in 2023 primarily related to the construction of the Southeast Gateway, Villa de Reyes and
Tula pipelines. We expect to incur approximately US$1.6 billion in 2024 to advance construction of the Southeast Gateway and
Villa de Reyes pipelines.
54 | TC Energy Management's discussion and analysis 2023
NATURAL GAS PIPELINES – BUSINESS RISKS
The following are risks specific to our Natural Gas Pipelines business. Refer to page 99 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. As part of our annual strategic planning process, we evaluate the
resilience of our asset portfolio over a range of potential energy supply and demand outcomes.
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 2023 | 55
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 recovery of 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 developing rate, facility and tariff applications that account for and
mitigate these 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.
56 | TC Energy Management's discussion and analysis 2023
Liquids Pipelines
Our Liquids Pipelines business provides safe and reliable crude oil transportation through infrastructure extending from the WCSB
in Canada to the U.S. Midwest and Gulf Coast. We offer long haul transportation from the WCSB to key refining and export
markets in the U.S., as well as domestic transportation within Alberta and from Cushing, Oklahoma to the U.S. Gulf Coast.
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 – approximately 460 km (290 miles).
Strategy
We remain focused on the safe, secure and reliable operations of our Liquids Pipelines assets, while maximizing operational
performance. We continue to expand our transportation service offerings and leverage existing infrastructure to pursue
in-corridor growth opportunities, enabling increased optionality and market access for our customers and adding value to our
business.
Recent highlights
• announced the proposed spinoff of our Liquids Pipelines business into a separate, investment-grade, publicly listed company
named South Bow Corporation, which is expected to be completed in the second half of 2024, subject to receipt of required
shareholder, court and regulatory approvals, favourable tax rulings and satisfaction of other customary closing conditions
• placed the Port Neches Link Pipeline System in service in first quarter 2023
• completed the recovery of all released volumes related to the Milepost 14 incident and returned Mill Creek to its natural
flowing state. We will maintain our commitment to long-term reclamation and environmental monitoring activities.
TC Energy Management's discussion and analysis 2023 | 57
58 | TC Energy Management's discussion and analysis 2023
We are the operator and developer of the following:
Liquids pipelines
1
Keystone Pipeline System
2 Marketlink
3 Grand Rapids
4 White Spruce
5
Port Neches
Length
Description
Ownership
4,327 km
(2,689 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.
Transports crude oil from the Keystone Pipeline System and
other liquids terminals in the Port Arthur, Texas area to the
Motiva Terminal in Port Neches, Texas.
460 km
(286 miles)
72 km
(45 miles)
6 km
(4 miles)
100%
100%
50%
100%
74.9%
TC Energy Management's discussion and analysis 2023 | 59
UNDERSTANDING OUR LIQUIDS PIPELINES BUSINESS
Our Liquids Pipelines segment consists of crude oil pipeline and terminal assets. The business safely, securely and reliably
transports crude oil from major supply sources to key refining and trading markets, where crude oil can be refined into
petroleum products or marketed into other domestic or international markets. We also offer ancillary services, including storage
at terminals, to provide our customers with increased delivery flexibility and increase the competitive position of our assets. In
addition to our crude oil pipeline and terminal assets, we conduct marketing activities through a non-regulated marketing
entity.
We provide pipeline transportation services to customers, primarily supported by long-term contracts providing certainty and
generating stable earnings over the contract term. These long-term contracts provide for the recovery of costs incurred to
construct our assets, with operating and maintenance costs primarily recovered through a variable flow-through toll.
Uncontracted pipeline capacity is offered to the market on an uncommitted spot basis and through periodic open seasons, in
accordance with regulatory requirements. Crude oil storage at terminals is offered to customers in exchange for fixed fee, term
contracts.
In Canada, our pipeline systems and associated facilities are regulated by either the CER or AER, and in the U.S., by PHMSA and
FERC or various state authorities. Combined, these entities regulate the construction, operation and abandonment of our
pipeline infrastructure, as well as oversee the reasonableness of our tolls.
Keystone Pipeline System
Keystone Pipeline
The Keystone Pipeline System, our largest liquids pipeline asset, transports crude oil exported from Western Canada to various
delivery points in the U.S. Midwest, and U.S. Gulf Coast. It also serves as the physical infrastructure for our Marketlink system,
which leases capacity for the transportation of U.S. domestic crude receipts between Cushing, Oklahoma and the U.S. Gulf
Coast. The Keystone Pipeline System operates in both Canada and the U.S. and is therefore subject to the common carrier
obligations set by the CER and FERC in those jurisdictions, respectively.
Port Neches Link Pipeline
Our Port Neches Link Pipeline System provides crude oil transportation between our Keystone Pipeline System, as well as
additional liquids terminals in the Port Arthur area, including the Phillips 66 Beaumont Terminal, to the Motiva Terminal in
Port Neches, Texas. Port Neches Link Pipeline System is regulated by the Railroad Commission of Texas.
TC Energy Liquids Marketing
Our liquids marketing business provides customers with a variety of crude oil marketing services including transportation,
storage and logistics, 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.
Intra-Alberta Pipeline Systems
Our two intra-Alberta liquids pipelines, Grand Rapids and White Spruce, provide crude oil transportation for producers in
northern Alberta to move volumes between the oil sands region and the Edmonton/Heartland areas. These pipeline systems are
regulated by the AER.
Business environment
Dynamic shifts in geopolitical events, government policy changes and various macroeconomic factors continue to impact global
crude oil supply and demand balances. While the upstream sector remains focused on balancing capital discipline and growth,
we expect crude oil demand to continue to increase this decade. Over a longer time horizon, we expect global demand to grow,
before slowly declining in later decades; however, crude oil is expected to remain a vital source in helping the world meet its
energy needs for decades to come. North America’s crude oil supply, inclusive of the WCSB, will remain critical in supporting
long-term demand.
60 | TC Energy Management's discussion and analysis 2023
Supply outlook
Canada has the world’s third largest crude oil reserves with over 160 billion barrels of proven and economically recoverable oil.
Production from the WCSB, which is the main supply source for our liquids assets, was approximately 5.0 million Bbl/d in 2023
and is expected to grow by over 500,000 Bbl/d to 5.5 million Bbl/d by 2030. The oil sands, which are located within the WCSB
and directly connected to our intra-Alberta assets, make up the majority of Canadian crude oil supply. The oil sands are
considered a world class supply source given its decades-long reserve life, low base production decline and rapidly improving
cost and environmental performance.
The U.S. is one of the largest crude oil producing countries in the world, with production exceeding 12 million Bbl/d in 2023. 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. U.S. refineries have been optimized through significant capital investments to refine a mix of light and heavy
crude oils to produce an optimized refined products slate. With our Keystone Pipeline System’s connection to key refining and
export markets, we believe we are well positioned to attract barrels from major U.S. tight oil basins, which themselves are
expected to grow through the end of the decade.
Demand
The U.S. is the primary source of crude oil demand in North America with refining capacity exceeding 18 million Bbl/d. Our
Liquids Pipelines assets serve the U.S. Midwest and U.S. Gulf Coast refining markets, PADD 2 and PADD 3, respectively.
PADD 2 represents 23 per cent and PADD 3 represents 56 per cent of U.S. refining throughput or in aggregate, 79 per cent. Many
PADD 2 and PADD 3 refineries are large-scale, complex facilities, with deep conversion capacity for heavy crude oil. These
markets are expected to remain globally competitive for decades to come due to their access to low-cost Canadian heavy and
U.S. light crude oil, as well as their proximity to abundant low-cost natural gas supply, positioning them to be among the most
profitable refineries in the world.
While domestic consumption makes up the predominance of current North American crude oil demand, exports are expected to
grow, increasing their proportion of North American crude oil demand out past the end of the decade, driven by growth in
emerging markets. Crude oil export from the U.S. Gulf Coast, a market served by our pipelines, is expected to grow from
3.2 million Bbl/d to 4.6 million Bbl/d by the early 2030s.
Strategic priorities
Our Liquids Pipelines assets strategically position our liquids business to provide competitive transportation solutions for growing
supplies of Alberta and U.S. crude oil to the U.S. Midwest and the U.S. Gulf Coast.
Within our established risk preferences, we remain committed to:
• optimizing the operational performance and commercial value of our existing assets
• expanding and leveraging our existing infrastructure for growth expansions
• progressing our energy transition goals, including system operational improvements and reducing our GHG emissions.
The long-term contract profile supporting our business model provides stable tolls for our customers and stable revenues for our
business. As we continually augment our connectivity to resilient supply and premium markets, our business is well positioned
for further growth.
We believe that our Liquids Pipelines assets are well-positioned to capture production growth from the stable and resilient
WCSB, which is needed to meet the growing U.S. Gulf Coast demand for secure Canadian heavy crude oil, as traditional offshore
imports decline. With the continued growth of U.S. light tight oil production and a satisfied demand for light oil in North
America, we will examine opportunities to expand our transportation services and extend our pipeline platform to include
last-mile delivery connectivity to refineries and terminals with storage and marine export capabilities. We will also focus on
leveraging our existing assets and development of projects to provide optionality for customers to reach new proximate supply
sources.
We continually work with existing and potential customers to enhance their customer experience and provide competitive,
reliable and efficient pipeline transportation and terminal services to meet their needs. The combination of the scale and
strategic location of our assets assists in attracting additional volumes and growing our business.
We closely monitor the marketplace for strategic asset acquisitions, as well as joint venture or joint tolling 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.
TC Energy Management's discussion and analysis 2023 | 61
SIGNIFICANT EVENTS
Spinoff of Liquids Pipelines Business
On July 27, 2023, we announced plans to separate into two independent, investment-grade, publicly listed companies through
the proposed spinoff of our Liquids Pipelines business into its own entity named South Bow Corporation. In addition to TC Energy
shareholder and court approvals, the spinoff Transaction is subject to receipt of favourable tax rulings from Canadian and U.S.
tax authorities, receipt of necessary regulatory approvals, and satisfaction of other customary closing conditions. We expect that
the spinoff Transaction will be completed in the second half of 2024.
Under the spinoff Transaction, TC Energy shareholders will retain their current ownership in TC Energy’s common shares and
receive a pro-rata allocation of common shares in South Bow Corporation. The determination of the number of common shares
in South Bow Corporation to be distributed to TC Energy shareholders will be determined prior to the closing of the spinoff
Transaction, which is expected to be tax free to TC Energy’s Canadian and U.S. shareholders.
For the year ended December 31, 2023, we incurred pre-tax Liquids Pipelines business separation costs related to the spinoff
Transaction of $40 million ($34 million after tax), of which $3 million and $37 million pre tax were included in the results of our
Liquids Pipelines and Corporate segments, respectively, and have been excluded from comparable measures.
Milepost 14 Incident
In December 2022, a pipeline incident occurred in Washington County, Kansas on the Keystone Pipeline System, releasing
12,937 barrels of crude oil. In June 2023, we completed the recovery of all released volumes and in October 2023, we returned
Mill Creek to its natural flowing state. We will maintain our commitment to long-term reclamation and environmental
monitoring activities.
A CAO was issued by PHMSA in December 2022, and later amended in March 2023. The pipeline is operating subject to the
Amended CAO (ACAO), which includes certain operating pressure restrictions. Under the ACAO, we expect to continue to fulfill
our Keystone contract commitments.
A RCFA was conducted by an independent third party and was released on April 21, 2023. The RCFA revealed that a unique set of
circumstances occurred at the rupture location, which likely originated during construction, with the primary cause of the
rupture being a fatigue crack. A comprehensive remedial work plan is being implemented, including the RCFA’s
recommendations, to enhance pipeline integrity and safety performance of the system.
At December 31, 2022, we accrued an environmental remediation liability of $650 million, before expected insurance recoveries
and not including potential fines and penalties, which was revised at June 30, 2023 to $794 million based on a review of costs
and commitments incurred. At December 31, 2023, the remediation cost estimate remains unchanged. Appropriate insurance
policies are in place and we believe that it remains probable that the majority of environmental remediation costs will be eligible
for recovery under our existing insurance coverage. As of December 31, 2023, we have received $575 million (2022 – nil) from
insurance proceeds related to the environmental remediation. The additional environmental remediation costs recognized in
second quarter 2023 included $36 million that we estimate to be recoverable from our wholly-owned captive insurance
subsidiary, which was recorded in Interest income and other in the Consolidated statement of income. This amount has been
excluded from comparable measures.
CER and FERC Proceedings
In 2019 and 2020, three Keystone customers initiated complaints before FERC and the CER regarding certain costs within the
variable toll calculation. In December 2022, the CER issued a decision in respect of the complaint that resulted in an adjustment
to previously charged tolls of $38 million. The CER has established a proceeding to consider Keystone’s compliance filing required
by the decision regarding the allocation of costs for drag reducing agent in the variable toll.
In February 2023, FERC released its initial decision in respect of the complaint. As a result, we have recorded a one-time
pre-tax charge of $57 million reflective of previously charged tolls between 2018 and 2022. This amount has been excluded from
comparable measures. A final order from FERC is expected in 2024.
62 | TC Energy Management's discussion and analysis 2023
Port Neches
In March 2023, the Port Neches Link Pipeline System was placed in service, connecting the Keystone Pipeline System to Motiva’s
Port Neches Terminal, enabling last-mile connectivity to Motiva’s 630,000 Bbl/d refinery.
In December 2023, Motiva, our partner in Port Neches LLC, exercised their option to increase their equity interest in the
company. As a result, and in exchange for approximately US$25 million in proceeds, subject to the agreed upon post-closing
adjustments, our ownership interest has decreased from 95 per cent to 74.9 per cent.
Keystone XL
In September 2022, the International Centre for Settlement of Investment Disputes formally constituted a tribunal to hear our
request for arbitration under NAFTA. In April 2023, the tribunal suspended the proceeding, granting a request from the U.S.
Department of State to decide the jurisdictional grounds of the case as a preliminary matter. A hearing on the jurisdictional
matter is set to occur in second quarter 2024. In April 2023, The Government of Alberta filed its own request for arbitration,
which will proceed separately from our claim.
Keystone XL termination activities will continue in 2024 and include asset dispositions and preservation. We will continue to
coordinate with regulators, stakeholders and Indigenous groups to meet our environmental and regulatory commitments.
TC Energy Management's discussion and analysis 2023 | 63
FINANCIAL RESULTS
The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented
earnings (losses) (the most directly comparable GAAP measure). Refer to page 11 for more information on non-GAAP measures
we use.
year ended December 31
(millions of $)
Keystone Pipeline System1
Intra-Alberta pipelines2
Other1
Comparable EBITDA
Depreciation and amortization
Comparable EBIT
Specific items:
Keystone regulatory decisions
Keystone XL preservation and other
Liquids Pipelines business separation costs
Keystone XL asset impairment charge and other
Gain on sale of Northern Courier
Risk management activities
Segmented earnings (losses)
Comparable EBITDA denominated as follows:
Canadian dollars
U.S. dollars
Foreign exchange impact
Comparable EBITDA
2023
1,389
70
(2)
1,457
(338)
1,119
(57)
(18)
(3)
4
—
(34)
2022
1,304
71
(9)
1,366
(329)
1,037
(27)
(25)
—
118
—
20
2021
1,448
87
(9)
1,526
(318)
1,208
—
(43)
—
(2,775)
13
(3)
1,011
1,123
(1,600)
382
796
279
1,457
383
754
229
1,366
417
884
225
1,526
1
2
Liquids marketing results were previously disclosed separately, but almost fully relate to marketing activities with respect to the Keystone Pipeline System. For
2022 and comparative periods, liquids marketing results have been reclassified within Keystone Pipeline System.
Intra-Alberta pipelines included Grand Rapids, White Spruce and Northern Courier. In November 2021, we sold our remaining 15 per cent interest in Northern
Courier.
Liquids Pipelines segmented earnings decreased by $112 million in 2023 compared to 2022 and increased by $2,723 million in
2022 compared to 2021 and included the following specified items, which have been excluded from our calculation of
comparable EBITDA and comparable EBIT:
• a $57 million pre-tax charge in 2023 as a result of the FERC Administrative Law Judge initial decision issued in February 2023 in
respect of a tolling-related complaint pertaining to amounts recognized from 2018 to 2022 and a $27 million pre-tax charge
due to the CER decision issued in December 2022 in respect of a tolling-related complaint pertaining to amounts reflected in
2021 and 2022. Refer to the Liquids Pipelines – Significant events section for additional information
• pre-tax preservation and other costs in 2023 of $18 million (2022 – $25 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
• a pre-tax charge of $3 million incurred in 2023 due to Liquids Pipelines business separation costs related to the spinoff
Transaction. Refer to the Liquids Pipelines – Significant events section for additional information
• a $4 million pre-tax adjustment in 2023 (2022 – $118 million) to the 2021 Keystone XL asset impairment charge and other
resulting from the net effect of the gain on sale of Keystone XL project assets and adjustments to the estimate for contractual
and legal obligations related to termination activities
• a $2.8 billion pre-tax asset impairment charge was recognized in 2021 associated with the termination of the Keystone XL
pipeline project and related projects following the January 2021 revocation of the Presidential Permit, net of expected
contractual recoveries and other contractual and legal obligations
• pre-tax gain of $13 million in 2021 related to the sale of the remaining 15 per cent interest in Northern Courier
• unrealized gains and losses from changes in the fair value of derivatives related to our liquids marketing business.
64 | TC Energy Management's discussion and analysis 2023
A stronger U.S. dollar in 2023 and 2022 had a positive impact on the Canadian dollar equivalent segmented earnings from our
U.S. operations compared to 2022 and 2021, respectively. Refer to the Foreign Exchange section for additional information.
Comparable EBITDA for Liquids Pipelines was $91 million higher in 2023 compared to 2022 primarily due to the net effect of:
• higher contracted and uncontracted volumes across the Keystone Pipeline System
• higher contributions from the Port Neches Link Pipeline System which began operations in March 2023
• a stronger U.S. dollar as described above.
Comparable EBITDA for Liquids Pipelines was $160 million lower in 2022 compared to 2021 primarily due to the net effect of:
• lower rates and volumes on the U.S. Gulf Coast section of the Keystone Pipeline System, partially offset by higher long-haul
contracted volumes and approximately 20,000 Bbl/d of long-term contracts from the 2019 Open Season that were
commercialized in April 2022, with an additional 10,000 Bbl/d in September 2022
• liquids marketing earnings for 2022 decreased relative to 2021 due to lower margins and volumes
• the CER decision on the tolling-related complaint in respect of amounts invoiced in 2022
• a stronger U.S. dollar as described above.
Depreciation and amortization
Depreciation and amortization was $9 million higher in 2023 compared to 2022 and $11 million higher in 2022 compared to 2021
primarily as a result of a stronger U.S. dollar.
OUTLOOK
Comparable EBITDA
Comparable EBITDA in 2024 is expected to be consistent with 2023. Comparable EBITDA in 2024 does not take into consideration
the impact of the spinoff Transaction as it is subject to TC Energy shareholder approval, court approval, favourable tax rulings,
other regulatory approvals and satisfaction of other customary closing conditions.
Capital expenditures
We incurred a total of $44 million in 2023 primarily related to capital projects in the U.S. Gulf Coast and on our operating
pipelines and expect to incur approximately $0.2 billion in 2024.
TC Energy Management's discussion and analysis 2023 | 65
BUSINESS RISKS
The following are risks specific to our Liquids Pipelines business. Refer to page 99 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 safely and reliably while optimizing available capacity are essential drivers of our business
success. Interruptions in our pipeline operations may impact our throughput capacity and result in our inability to deliver on our
contracted volume obligations and to capture spot volume opportunities. We manage these risks and possible impacts to local
communities using environmental risk-based preventive maintenance programs, effective capital investments and a highly
skilled workforce. We utilize in-line inspection equipment to monitor our pipelines regularly and perform repairs and
preventative maintenance whenever necessary.
Regulatory and government
Decisions by Canadian and U.S. regulators can have a significant impact on the design, construction, operations and financial
performance of our liquids pipelines. Shifts in government policy can impact the ability to grow our business. Public opinion
about crude oil development and production may also have an adverse impact on regulatory processes. In conjunction with this,
there are individuals and special interest groups that express opposition to oil usage for energy 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 policy developments to determine their possible impact on our Liquids
Pipelines business 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 products could adversely impact the price that crude oil producers receive for their product. In
the long term, lower crude oil prices could cause producers to 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.
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 demand markets, we may face competition from
other companies which also seek to transport crude oil to the same markets. Our success will be 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 logistics, 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 – Risk oversight and enterprise risk management section.
Market Volatility
The cyclical nature of commodity prices may influence the pace at which our customers expand their operations. This can impact
the rate of output growth in our industry, the value of our services as contracts expire, and timing for the demand of
transportation services and/or new liquids infrastructure. We seek to mitigate this risk through term contracting and offering a
market competitive transportation service.
66 | TC Energy Management's discussion and analysis 2023
Power and Energy Solutions
The Power and Energy Solutions business consists of power generation, non-regulated natural gas storage assets, as well as
emerging technologies that can provide low-carbon solutions for our customers and industry.
Our Power and Energy Solutions business includes approximately 4,600 MW of generation powered by nuclear, natural gas, wind
and solar. These generation assets are generally supported by long-term contracts. Our Canadian power infrastructure assets are
located in Alberta, Ontario, Québec and New Brunswick while our U.S. power infrastructure assets are located in Texas.
Additionally, we have approximately 400 MW of PPAs in both the U.S. and Canada from wind and solar facilities. We continue to
pursue generation assets and PPA opportunities in Canada and the U.S.
We also own and operate approximately 118 Bcf of non-regulated natural gas storage capacity in Alberta.
Strategy
Our strategy is to maximize the value of our existing portfolio through maintaining safety and operational excellence while
enhancing the life cycle and reliability of our assets. Beyond our existing portfolio, we will focus our capital investment in sectors
and projects that offer commercial frameworks consistent with TC Energy's value proposition, namely long-term contracts and
rate regulation. Long term, we believe there will be a growing need for a reliable supply of resources as energy transition
unfolds. We can play a vital role in energy transition and will continue to build expertise and capabilities in emerging
technologies and markets that we believe will fit these criteria in the future and have synergies with our natural gas business.
Recent highlights
• under the Bruce Power life extension program, the Unit 6 MCR was completed and successfully placed in commercial
operations in third quarter 2023, ahead of schedule and within budget. In March 2023, Unit 3 was removed from service and
began its MCR construction starting in second quarter 2023. The final basis of estimate for the Unit 4 MCR was filed with the
IESO in fourth quarter 2023, and received approval on February 8, 2024
• acquired 100 per cent of the Class B Membership Interests in the 155 MW Fluvanna Wind Farm and 148 MW Blue Cloud Wind
Farm
• completed construction of the 81 MW Saddlebrook Solar project, with full commercial operation commencing on
January 5, 2024
• announced we will continue to advance the OPSP with our prospective partner, the Saugeen Ojibway Nation.
TC Energy Management's discussion and analysis 2023 | 67
68 | TC Energy Management's discussion and analysis 2023
Power and Energy Solutions assets currently have a combined power generation capacity, net to TC Energy, of 4,642 MW. We
operate each facility except for Bruce Power.
Generating
capacity (MW)
Type of fuel Description
Ownership
Power assets
1 Bruce Power1
3,170
nuclear
Eight operating reactors in Tiverton, Ontario. Bruce Power
leases the nuclear facilities from OPG.
48.3%
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
Fluvanna2
5 Blue Cloud2
6 Bear Creek
7 Carseland
8 Grandview
9 Saddlebrook Solar
10 Redwater
207
155
148
100
95
90
81
46
natural gas Cogeneration plant in Fort McMurray, Alberta.
wind Wind farm located near Scurry County, Texas.
wind Wind farm located near Bailey County, Texas.
natural gas Cogeneration plant in Grande Prairie, Alberta.
natural gas Cogeneration plant in Carseland, Alberta.
natural gas Cogeneration plant in Saint John, New Brunswick.
solar Hybrid solar generation facility near Aldersyde, Alberta.
natural gas Cogeneration plant in Redwater, Alberta.
Canadian non-regulated natural gas storage
11 Crossfield
12 Edson
68 Bcf
50 Bcf
Under construction
Other energy solutions
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%
100%
100%
100%
13
Lynchburg
RNG RNG production facility in Lynchburg, Tennessee.
30%
1
2
Our share of power generation capacity.
TC Energy owns 100 per cent of the Class B Membership Interests and has a tax equity investor that owns 100 per cent of the Class A Membership Interests, to
which a percentage of earnings, tax attributes and cash flows are allocated under the provisions of each tax equity agreement. Refer to the Power and Energy
Solutions – Significant events section for additional information.
TC Energy Management's discussion and analysis 2023 | 69
UNDERSTANDING OUR POWER AND ENERGY SOLUTIONS BUSINESS
Canadian Power
Canadian Power Generation & Marketing
We own and operate approximately 1,200 MW of power supply in Canada, excluding our investment in Bruce Power. In Alberta
we own five facilities: four natural gas-fired cogeneration and one solar. We 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 enable us to capture opportunities to increase earnings in periods of high
spot prices. Our two eastern Canadian natural gas-fired cogeneration assets, Bécancour and Grandview, are fully contracted.
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 6,560 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 48.3 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.
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 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 years of operational life to each of the six units.
The Unit 6 MCR, the first of the six-unit MCR life extension program, commenced in January 2020 and was placed back into
commercial operation in third quarter 2023 ahead of schedule and within budget despite challenges associated with the
COVID-19 pandemic. The Unit 3 MCR, the second unit in the MCR program, commenced in first quarter 2023 and has an expected
completion in 2026. In the fourth quarter 2023, the Unit 4 MCR final cost and schedule estimate was submitted to the IESO and
approved on February 8, 2024. We expect the Unit 4 MCR to commence in first quarter 2025 with expected completion in 2028.
Investments in the remaining three 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.
Along with the MCR life extension program, Bruce Power’s Project 2030 has a goal of achieving 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. 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, which began in early 2022, is targeting
another 200 MW.
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.
70 | TC Energy Management's discussion and analysis 2023
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. No operating cost efficiencies for the 2022 to 2024 period have been provided for
at December 31, 2023, and no operating 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 was undertaken with a
Canadian-based nuclear medicine partnership and the Saugeen Ojibway Nation, on whose traditional territory the Bruce Power
facilities are located.
Power Purchase Agreements – Canada
We have approximately 400 MW of wind and solar generation PPAs and associated environmental attributes in Alberta. These
PPAs allow us to generate incremental earnings by offering renewable power products to our customers.
U.S. Power
Power Generation & Marketing – U.S.
We own approximately 300 MW of wind generation located in Texas which operate in the Electric Reliability Council of Texas
(ERCOT) and Southwest Power Pool (SPP) markets. A portion of this power generation is sold under a long-term, fixed price
contract.
Our U.S. Power and emissions commercial trading and marketing business optimizes the value of our assets and leverages
physical and financial products in the power and environmental markets with a focus on risk management.
Power Purchase Agreements – U.S.
We have approximately 400 MW of wind generation PPAs and associated environmental attributes in the U.S. These PPAs allow
us to generate incremental earnings by offering renewable power products to our customers.
Other Energy Solutions
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 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 2023 | 71
SIGNIFICANT EVENTS
Bruce Power Life Extension
The Unit 6 MCR, which began in January 2020, was declared commercially operational on September 14, 2023, ahead of schedule
and within budget despite challenges from the COVID-19 pandemic.
On March 1, 2023, Unit 3 was removed from service and began its MCR construction in second quarter 2023 with a return to
service expected in 2026.
The final cost and schedule estimate for the Unit 4 MCR program was submitted to the IESO on December 13, 2023, and received
approval on February 8, 2024. The Unit 4 MCR is expected to commence in first quarter 2025 with an expected completion in
2028.
Renewable Energy Contracts and/or Investment Opportunities
In second quarter 2023, we finalized contracts to sell 50 MW under our 24-by-7 carbon-free power offering in Alberta. Contract
terms range from 15 to 20 years and are expected to commence in 2025.
In November 2023, a majority of the 297 MW Sharp Hills Wind Farm achieved commercial operation resulting in the
commencement of our 15-year PPA for 100 per cent of the power produced and the rights to all environmental attributes from
the facility.
Texas Wind Farm Acquisitions
On March 15, 2023, we acquired 100 per cent of the Class B Membership Interests in the 155 MW Fluvanna Wind Farm located
in Scurry County, Texas for US$99 million, before post-closing adjustments. Additionally, on June 14, 2023, we acquired
100 per cent of the Class B Membership Interests in the 148 MW Blue Cloud Wind Farm located in Bailey County, Texas for
US$125 million, before post-closing adjustments.
Each of these operating assets has a tax equity investor which owns 100 per cent of the Class A Membership Interests, to which a
percentage of earnings, tax attributes and cash flows are allocated under the provisions of each tax equity agreement and are
recorded in Net income attributable to non-controlling interests in the Consolidated statement of income.
Saddlebrook Solar
On October 25, 2023, we completed construction of Saddlebrook Solar, an 81 MW facility located near Aldersyde, Alberta and
began commissioning activities including supplying generation to the Alberta market. Full commercial operation was achieved
on January 5, 2024. The project was partially supported with funding from Emissions Reduction Alberta and Lockheed Martin.
72 | TC Energy Management's discussion and analysis 2023
FINANCIAL RESULTS
The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings
(losses)(the most directly comparable GAAP measure). Refer to page 11 for more information on non-GAAP measures we use.
The table below reflects 100 per cent of comparable EBITDA on assets we own or partially own and fully consolidate, as well as
equity income for assets we own an equity interest in and do not consolidate.
year ended December 31
(millions of $)
Bruce Power1
Canadian Power
Natural Gas Storage and other2
Comparable EBITDA
Depreciation and amortization
Comparable EBIT
Specific items:
Bruce Power unrealized fair value adjustments
Gain on sale of Ontario natural gas-fired power plants
Risk management activities
Segmented earnings (losses)
2023
680
334
6
1,020
(92)
928
7
—
69
1,004
2022
2021
552
322
33
907
(72)
835
(17)
—
15
833
397
253
19
669
(78)
591
14
17
6
628
1
2
Includes our share of equity income from Bruce Power.
Includes non-controlling interest in the Texas Wind Farms, which comprises Class A Membership Interests. Refer to the Corporate - Financial results section for
additional information.
Power and Energy Solutions segmented earnings increased by $171 million in 2023 compared to 2022 and increased by
$205 million in 2022 compared to 2021 and included the following specific items, which have been excluded from our calculation
of comparable EBITDA and comparable EBIT:
• 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
• our proportionate share of Bruce Power's unrealized gains and losses on funds invested for post-retirement benefits and risk
management activities
• unrealized gains and losses from changes in the fair value of derivatives used to reduce commodity exposures.
Comparable EBITDA for Power and Energy Solutions increased by $113 million in 2023 compared to 2022 primarily due to:
• higher contributions from Bruce Power primarily due to a higher contract price, reduced outage costs with fewer planned
outage days and lower depreciation expense, partially offset by lower generation and increased operating expenses.
Additional financial and operating information on Bruce Power is provided below
• increased Canadian Power financial results primarily from lower natural gas fuel costs and higher realized power prices
• decreased Natural Gas Storage and other results due to increased business development costs across the segment.
Comparable EBITDA for Power and Energy Solutions increased by $238 million in 2022 compared to 2021 primarily due to the net
effect of:
• positive contributions from Bruce Power primarily due to a higher contract price
• improved Canadian Power earnings primarily due to higher realized power prices
• increased Natural Gas Storage and other results from higher realized Alberta natural gas storage spreads in 2022.
Depreciation and amortization
Depreciation and amortization increased by $20 million in 2023 compared to 2022 primarily due to the acquisition of the
Texas Wind Farms in the first half of 2023. Depreciation was lower by $6 million in 2022 compared to 2021 as a result of certain
adjustments in 2022.
TC Energy Management's discussion and analysis 2023 | 73
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)
Items included in comparable EBITDA and comparable EBIT are comprised of:
Revenues1
Operating expenses
Depreciation and other
Comparable EBITDA and comparable EBIT2
Bruce Power – other information
Plant availability3,4
Planned outage days4
Unplanned outage days
Sales volumes (GWh)5
Realized power price per MWh6
2023
2022
2021
1,941
(917)
(344)
680
92%
106
62
20,447
$94
1,848
(924)
(372)
552
86%
302
34
20,610
$89
1,642
(922)
(323)
397
86%
321
22
20,542
$80
1
2
3
4
5
6
Net of amounts recorded to reflect operating cost efficiencies shared with the IESO, if applicable.
Represents our 48.3 per cent ownership interest and internal costs supporting our investment in Bruce Power. Excludes unrealized gains and losses on funds
invested for post-retirement benefits and risk management activities.
The percentage of time the plant was available to generate power, regardless of whether it was running.
Excludes MCR outage days.
Sales volumes include deemed generation.
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.
The Unit 6 MCR, which began in 2020, was declared commercially operational on September 14, 2023, ahead of schedule and
within budget. The Unit 3 MCR commenced on March 1, 2023 with a return to service expected in 2026.
A planned outage on Unit 4 was completed in second quarter 2023 and on Unit 8 in fourth quarter 2023. The final cost and
schedule estimate for the Unit 4 MCR program was submitted to the IESO on December 13, 2023, and received approval on
February 8, 2024.
Planned maintenance was completed on all units in 2022. In 2021, planned maintenance on Units 1 and 3 was completed and an
outage on Unit 7 commenced in the fourth quarter.
OUTLOOK
Comparable EBITDA
Power and Energy Solutions comparable EBITDA in 2024 is expected to be higher than 2023 primarily from increased Bruce Power
equity income due to the full year impact of Unit 6 after its return to service in September 2023 and the expected April 1, 2024
contract price increase. Lower Alberta power prices in 2024 are expected, reducing contributions from Canadian Power.
Planned maintenance at Bruce Power in 2024 is currently scheduled to begin on Unit 1 in the first quarter and on Units 5 to 8 in
the second quarter. The average 2024 plant availability percentage, excluding the Unit 3 MCR program, is expected to be in the
low-90 per cent range.
Capital expenditures
We incurred $0.9 billion in 2023 for our share of the Unit 3 and Unit 6 MCR programs for Bruce Power, construction of
Saddlebrook Solar and other maintenance capital projects across the segment. We expect to incur approximately $0.9 billion in
2024 primarily related to our share of Bruce Power's Unit 3 and Unit 4 MCR programs.
74 | TC Energy Management's discussion and analysis 2023
BUSINESS RISKS
The following are risks specific to our Power and Energy Solutions business. Refer to page 99 for information about general risks
related to TC Energy as a whole, including other operational, safety and financial risks. The Power and Energy Solutions
marketing business complies with our risk management policies which are described in the Other information – Risk oversight
and enterprise risk management section.
Fluctuating power and natural gas market prices
Much of the physical power generation and fuel used in our 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 Energy Solutions business. Unexpected outages or extended planned
outages at our power plants can increase maintenance costs as well as lower plant output, revenues 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 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.
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, as well
as 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.
TC Energy Management's discussion and analysis 2023 | 75
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 Canada and the U.S., as well as in the development of greenfield power plants.
Traditional and non-traditional participants 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.
Execution and capital costs
We make substantial capital commitments developing power generation infrastructure based on the assumption that these
assets will deliver an attractive return on investment. While we carefully consider the scope and expected costs of our capital
projects, we are exposed to execution and capital cost overrun risk which may impact our return on these projects. We mitigate
this risk by implementing comprehensive project governance and oversight processes and through the structuring of
engineering, procurement and construction contracts with reputable counterparties.
76 | TC Energy Management's discussion and analysis 2023
Corporate
SIGNIFICANT EVENTS
2016 Columbia Pipeline Acquisition Lawsuit
In June 2023, the Delaware Chancery Court (the Court) issued its decision in the class action lawsuit commenced by former
shareholders of Columbia Pipeline Group Inc. (CPG) related to the acquisition of CPG by TC Energy in 2016. The Court found that
the former CPG executives breached their fiduciary duties, that the former CPG Board breached its duty of care in overseeing the
sale process and that TC Energy aided and abetted those breaches. The Court awarded US$1 per share in damages to the
plaintiffs and total damages, which are presently estimated at US$400 million plus statutory interest. Post-trial briefing and
argument has concluded and a decision from the Court allocating liability as between TC Energy and the former CPG executives is
expected sometime in the first half of 2024. Management expects to proceed with an appeal following the Court’s
determination of total damages and TC Energy’s allocated share.
Focus Project
In late 2022, we launched the Focus Project to identify opportunities to improve safety, productivity and cost-effectiveness.
To date, we have identified a broad set of opportunities expected to further enhance safety, as well as improve operational and
financial performance over the long term.
Certain initiatives have been implemented in 2023, including launching a new simplified operational management system in
support of enhanced safety performance, efficiencies in certain processes related to capital projects and reducing corporate
costs. We expect to continue to implement additional initiatives beyond 2023, primarily in our Natural Gas Pipelines business,
with benefits in the form of enhanced productivity, lower costs, and higher revenues, with the majority of these benefits
expected to be realized by our customers. We also have additional safety initiatives as part of a three-year safety improvement
plan.
At December 31, 2023, we have incurred pre-tax costs of $124 million for the Focus Project primarily related to external
consulting and severance costs, of which $65 million was recorded in Plant operating costs and other in the Consolidated
statement of income and was removed from comparable amounts. Of the remaining costs incurred, $23 million was recorded in
Plant operating costs and other with offsetting revenues in the Consolidated statement of income related to costs recoverable
through regulatory and commercial tolling structures, the net effect of which had no impact on net income. An additional
$36 million was allocated to capital projects. No material consulting costs are expected to be incurred in 2024.
Asset Divestiture Program
On October 4, 2023, TC Energy successfully completed the sale of a 40 per cent non-controlling equity interest in Columbia Gas
and Columbia Gulf which significantly accelerated our deleveraging goal. We continue to evaluate incremental capital rotation
opportunities to further strengthen our financial position.
2023 Canada Federal Budget
On March 28, 2023, the Canadian Federal Government delivered its 2023 Budget. As part of this budget, several changes were
announced to interest deductibility rules, global minimum tax proposals and other tax measures. We do not expect a material
impact on our financial performance and cash flows in the near term, but we will continue to monitor any developments.
TC Energy Management's discussion and analysis 2023 | 77
FINANCIAL RESULTS
The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented
earnings(losses)(the most directly comparable GAAP measure). Refer to page 11 for more information on non-GAAP measures we
use.
year ended December 31
(millions of $)
Comparable EBITDA and comparable EBIT
Specific items:
Focus Project costs
Liquids Pipelines business separation costs
Foreign exchange gains – inter-affiliate loans1
Voluntary Retirement Program
Segmented earnings (losses)
2023
(14)
(65)
(37)
—
—
(116)
2022
(20)
—
—
28
—
8
2021
(24)
—
—
41
(63)
(46)
1
Reported in Income (loss) from equity investments in the Consolidated statement of income.
In 2023, Corporate segmented losses were $116 million compared to segmented earnings of $8 million in 2022. In 2022,
Corporate segmented earnings were $8 million compared to segmented losses of $46 million in 2021.
Corporate segmented earnings (losses) included the following specific items which have been excluded from our calculation of
comparable EBITDA and comparable EBIT:
• a pre-tax charge of $65 million recorded in 2023 related to Focus Project costs. Refer to the Corporate – Significant events
section for additional information
• a pre-tax charge of $37 million incurred in 2023 due to Liquids Pipelines business separation costs related to the spinoff
Transaction. Refer to the Liquids Pipelines – Significant events section for additional information
• foreign exchange gains in 2022 and 2021 on our proportionate share of peso-denominated inter-affiliate loans to the Sur de
Texas joint venture from its partners up to March 15, 2022 when the peso-denominated inter-affiliate loans were fully repaid
upon maturity. These foreign exchange gains were recorded in Income from equity investments in the Corporate segment and
were excluded from our calculation of comparable EBITDA and comparable EBIT as they were fully offset by corresponding
foreign exchange losses on the inter-affiliate loan receivable included in Foreign exchange gains (losses), net. Refer to the
Other Information – Related party transactions section for additional information
• a pre-tax charge of $63 million in 2021 for the VRP offered in 2021.
Comparable EBITDA and comparable EBIT for Corporate increased by $6 million in 2023 from a loss of $20 million in 2022 due to
lower litigation costs. Comparable EBITDA and comparable EBIT for Corporate in 2022 was generally consistent with 2021.
78 | TC Energy Management's discussion and analysis 2023
OTHER INCOME STATEMENT ITEMS
Interest expense
year ended December 31
(millions of $)
Interest expense on long-term debt and junior subordinated notes
Canadian dollar-denominated
U.S. dollar-denominated
Foreign exchange impact
Other interest and amortization expense
Capitalized interest
Interest expense included in comparable earnings
Specific items:
Keystone regulatory decisions
Keystone XL preservation and other
Interest expense
2023
2022
2021
(895)
(1,692)
(592)
(3,179)
(261)
187
(3,253)
(10)
—
(776)
(1,267)
(383)
(2,426)
(189)
27
(2,588)
—
—
(712)
(1,259)
(320)
(2,291)
(85)
22
(2,354)
—
(6)
(3,263)
(2,588)
(2,360)
Interest expense increased by $675 million in 2023 compared to 2022 and increased by $228 million in 2022 compared to 2021.
The following specific items have been removed from our calculation of interest expense included in comparable earnings:
• carrying charges of $10 million in 2023 as a result of a pre-tax charge related to the FERC Administrative Law Judge initial
decision on Keystone. This decision was issued in February 2023 in respect of a tolling-related complaint pertaining to amounts
recognized from 2018 to 2022
• a $6 million charge in 2021 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.
Interest expense included in comparable earnings in 2023 increased by $665 million compared to 2022 primarily due to the net
effect of:
• long-term debt issuances, net of maturities
• the foreign exchange impact from a stronger U.S. dollar on translation of U.S. dollar-denominated interest expense
• higher interest rates on our long-term debt that bears interest at a floating rate
• higher capitalized interest, largely due to funding related to our investment in Coastal GasLink LP. Refer to Note 8, Coastal
GasLink, of our 2023 Consolidated financial statements for additional information.
Interest expense included in comparable earnings in 2022 increased by $234 million compared to 2021 mainly due to the net
effect of:
• higher interest rates on increased levels of short-term borrowings
• long-term debt and junior subordinated note issuances, net of maturities
• the foreign exchange impact from a stronger U.S. dollar on translation of U.S. dollar-denominated interest expense.
Refer to the Financial Condition section for additional information.
TC Energy Management's discussion and analysis 2023 | 79
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
2023
2022
2021
102
350
123
575
157
161
51
369
140
101
26
267
AFUDC increased by $206 million in 2023 compared to 2022. The decrease in Canadian dollar-denominated AFUDC is primarily
related to NGTL System expansion projects placed in service. The increase in U.S. dollar-denominated AFUDC is the result of the
reactivation of AFUDC on the TGNH assets under construction following the new TSA with the CFE, as well as capital expenditures
on the Southeast Gateway pipeline project in 2023, partially offset by projects placed in service on our U.S. natural gas pipelines.
Due to the delay of an FID, effective November 1, 2023, we have suspended recording AFUDC on the assets under construction
for the Tula pipeline project.
AFUDC increased by $102 million in 2022 compared to 2021. The increase in Canadian dollar-denominated AFUDC is primarily
related to increased capital expenditures on the NGTL System. The increase in U.S. dollar-denominated AFUDC is due to the
reactivation of AFUDC on the TGNH assets under construction following the new TSA with the CFE, as well as capital expenditures
on the Southeast Gateway pipeline project, partially offset by the impact of decreased capital expenditures and projects placed
in service on our U.S. natural gas pipeline projects.
Foreign exchange gains (losses), net
year ended December 31
(millions of $)
Foreign exchange gains (losses), net included in comparable earnings
Specific items:
Foreign exchange gains (losses), net – intercompany loan
Foreign exchange losses – inter-affiliate loan
Risk management activities
Foreign exchange gains (losses), net
2023
118
(44)
—
246
320
2022
(8)
—
(28)
(149)
(185)
2021
254
—
(41)
(203)
10
Foreign exchange gains were $320 million in 2023 compared to foreign exchange losses of $185 million in 2022 and foreign
exchange gains of $10 million in 2021. The following specific items have been removed from our calculation of Foreign exchange
gains (losses), net included in comparable earnings:
• unrealized foreign exchange gains and losses on the peso-denominated intercompany loan between TCPL and TGNH
beginning in second quarter 2023. Refer to the Non-GAAP measures section for additional information
• unrealized gains and losses from changes in the fair value of derivatives used to manage our foreign exchange risk
• foreign exchange losses on the peso-denominated inter-affiliate loan receivable from the Sur de Texas joint venture until
March 15, 2022, when it was fully repaid upon maturity. The interest income and interest expense on the peso-denominated
inter-affiliate loan was included in comparable earnings with all amounts offsetting and resulting in no impact on
consolidated net income.
Refer to the Other Information – Financial risks, financial instruments and related party transactions sections for additional
information.
80 | TC Energy Management's discussion and analysis 2023
Foreign exchange gains included in comparable earnings were $118 million in 2023 compared to foreign exchange losses of
$8 million in 2022. The change was primarily due to the net effect of:
• higher realized gains on derivatives used to manage our foreign exchange exposure to net liabilities in Mexico
• higher net realized losses on derivatives used to manage our net exposure to foreign exchange rate fluctuations on
U.S. dollar‑denominated income
• higher foreign exchange losses on the revaluation of our peso-denominated net monetary liabilities to U.S. dollars.
Foreign exchange losses included in comparable earnings were $8 million in 2022 compared to foreign exchange gains of
$254 million in 2021. The change was primarily due to the net effect of:
• net realized losses in 2022 compared to realized gains in 2021 on derivatives used to manage our net exposure to foreign
exchange rate fluctuations on U.S. dollar-denominated income
• foreign exchange losses in 2022 compared to gains in 2021 on the revaluation of our peso-denominated net monetary
liabilities to U.S. dollars
• higher realized gains on derivatives used to manage our foreign exchange exposure to net liabilities in Mexico.
Interest income and other
year ended December 31
(millions of $)
Interest income and other included in comparable earnings
Specific item:
Milepost 14 insurance expense
Interest income and other
2023
278
(36)
242
2022
146
—
146
2021
190
—
190
Interest income and other increased by $96 million in 2023 compared to 2022 and decreased by $44 million in 2022 compared to
2021. Interest income and other in 2023 included a $36 million accrued insurance expense related to the Milepost 14 incident,
which is an estimate of the insurance proceeds for environmental remediation that we expect to receive from our wholly-owned
captive insurance subsidiary. This expense has been removed from our calculation of Interest income and other included in
comparable earnings. Refer to the Non-GAAP measures section for additional information.
Interest income and other included in comparable earnings increased by $132 million in 2023 compared to 2022 due to higher
interest earned on short-term investments and the change in fair value of other restricted investments, partially offset by lower
interest income in 2023 due to the repayment of the inter-affiliate loan receivable from Sur de Texas joint venture in July 2022.
Interest income and other included in comparable earnings decreased by $44 million in 2022 compared to 2021, due to the
March 2022 refinancing of the inter-affiliate loan receivable from Sur de Texas joint venture and subsequent repayment of the
loan on July 29, 2022.
TC Energy Management's discussion and analysis 2023 | 81
Income tax (expense) recovery
year ended December 31
(millions of $)
Income tax expense included in comparable earnings
Specific items:
Coastal GasLink impairment charge
Keystone regulatory decisions
Focus Project costs
Liquids Pipelines business separation costs
Keystone XL preservation and other
Expected credit loss provision on net investment in leases
and certain contract assets in Mexico
Keystone XL asset impairment charge and other
Great Lakes goodwill impairment charge
Settlement of Mexico prior years' income tax assessments
Voluntary Retirement Program
Sale of Northern Courier
Sale of Ontario natural gas-fired power plants
Bruce Power unrealized fair value adjustments
Risk management activities
Income tax (expense) recovery
2023
(1,037)
157
15
17
6
4
(25)
14
—
—
—
—
—
(2)
(91)
(942)
2022
(813)
405
7
—
—
6
49
(123)
40
(196)
—
—
—
4
32
(589)
2021
(830)
—
—
—
—
12
—
641
—
—
15
6
(10)
(3)
49
(120)
Income tax expense in 2023 increased by $353 million compared to 2022 and increased by $469 million in 2022 compared to
2021.
In addition to the income tax impacts on other specific items referenced elsewhere in this MD&A, Income tax expense also
includes the following specific items, which have been removed from our calculation of Income tax expense included in
comparable earnings:
2023
• a $157 million income tax recovery related to the impairment of our equity investment in Coastal GasLink LP
• a $14 million U.S. minimum tax recovery on the 2021 Keystone XL asset impairment charge and other related to the
termination of the Keystone XL pipeline project.
2022
• a $405 million income tax recovery related to the impairment of our equity investment in Coastal GasLink LP, net of certain
unrealized tax losses not recognized
• $196 million expense related to the settlement of prior years' income tax assessments related to our operations in Mexico
• a $123 million income tax expense as part of the Keystone XL asset impairment charge and other that includes a $96 million
U.S. minimum tax related to the termination of the Keystone XL pipeline project.
2021
• income tax impact of the Keystone XL pipeline project asset impairment charge and other.
Income tax expense included in comparable earnings in 2023 increased by $224 million compared to 2022 primarily due to higher
earnings subject to income tax, Mexico foreign exchange exposure and lower foreign income tax rate differentials, partially
offset by lower flow-through income taxes and lower Mexico inflation adjustments. Refer to the Foreign exchange section for
additional information.
Income tax expense included in comparable earnings in 2022 decreased by $17 million compared to 2021 primarily due to lower
flow-through income taxes and higher foreign tax rate differentials, partially offset by higher earnings subject to tax and other
various valuation allowances.
82 | TC Energy Management's discussion and analysis 2023
Net (income) loss attributable to non-controlling interests
year ended December 31
(millions of Canadian $)
Columbia Gas and Columbia Gulf1
Portland Natural Gas Transmission System
Texas Wind Farms
TC PipeLines, LP
Redeemable non-controlling interest
Non-Controlling
Interests
Ownership at
December 31, 2023
40.0%
38.3%
100% 2
nil
3
nil
2023
(143)
(41)
38
—
—
2022
2021
—
(37)
—
—
—
—
(30)
—
(60)
(1)
(91)
Net (income) loss attributable to non-controlling interests
(146)
(37)
1
2
3
On October 4, 2023, we completed the sale of a 40 per cent non-controlling equity interest in Columbia Gas and Columbia Gulf to GIP.
The Texas Wind Farms have tax equity investors that own 100 per cent of the Class A Membership Interests, to which a percentage of earnings, tax attributes
and cash flows are allocated.
Prior to the March 3, 2021 acquisition, the non-controlling interest in TC PipeLines, LP was 74.5 per cent.
Net income attributable to non-controlling interests increased by $109 million in 2023 compared to 2022 due to the net effect
of the sale of a 40 per cent non-controlling equity interest in Columbia Gas and Columbia Gulf and the acquisition of the
Texas Wind Farms. Refer to the U.S. Natural Gas Pipelines – Significant events and Power and Energy Solutions – Significant
events sections for additional information.
Net income attributable to non-controlling interests decreased by $54 million in 2022 compared to 2021 primarily as a result of
the March 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.
Preferred share dividends
year ended December 31
(millions of $)
Preferred share dividends
2023
(93)
2022
(107)
2021
(140)
Preferred share dividends decreased by $14 million in 2023 compared to 2022 and $33 million in 2022 compared to 2021 primarily
due to the redemption of preferred shares in 2022 and 2021, partially offset by higher floating dividend rates on certain series of
preferred shares.
TC Energy Management's discussion and analysis 2023 | 83
Foreign exchange
Foreign exchange related to U.S. dollar dominated operations
Certain of our businesses generate all or most of their earnings in U.S. dollars and, since we report our financial results in
Canadian dollars, changes in the value of the U.S. dollar against the Canadian dollar directly affect our comparable EBITDA and
may also impact comparable earnings. As our U.S. dollar-denominated operations continue to grow, this exposure increases. A
portion of the U.S. dollar-denominated comparable EBITDA exposure is naturally offset by U.S. dollar-denominated amounts
below comparable EBITDA within Depreciation and amortization, Interest expense and other income statement line items. The
balance of the exposure is actively managed on a rolling forward basis up to three years using foreign exchange derivatives;
however, the natural exposure beyond that period remains. The net impact of the U.S. dollar movements on comparable
earnings during the year ended December 31, 2023, after considering natural offsets and economic hedges, was not significant.
The components of our financial results denominated in U.S. dollars are set out in the table below, including our U.S. Natural Gas
Pipelines and Mexico Natural Gas Pipelines operations along with the majority of our Liquids Pipelines business. Comparable
EBITDA is a non-GAAP measure.
Pre-tax U.S. dollar-denominated income and expense items
year ended December 31
(millions of US$)
Comparable EBITDA
U.S. Natural Gas Pipelines
Mexico Natural Gas Pipelines1
Liquids Pipelines
Depreciation and amortization
Interest on long-term debt and junior subordinated notes
Allowance for funds used during construction
Non-controlling interests and other
Average exchange rate – U.S. to Canadian dollars
2023
2022
2021
3,248
596
796
4,640
(954)
(1,692)
350
(156)
2,188
1.35
3,142
602
754
4,498
(952)
(1,267)
161
(101)
2,339
1.30
3,075
602
884
4,561
(911)
(1,259)
101
(66)
2,426
1.25
1
Excludes interest expense on our inter-affiliate loans with the Sur de Texas joint venture which was fully offset in Interest income and other. These inter-affiliate
loans were fully repaid in 2022.
Foreign exchange related to Mexico Natural Gas Pipelines
Changes in the value of the Mexican peso against the U.S. dollar can affect our comparable earnings as a portion of our Mexico
Natural Gas Pipelines monetary assets and liabilities are peso-denominated, while our financial results are denominated in
U.S. dollars for our Mexico operations. These peso-denominated balances are revalued to U.S. dollars, creating foreign exchange
gains and losses that are included in Income (loss) from equity investments and Foreign exchange (gains) losses, net in the
Consolidated statement of income.
In addition, foreign exchange gains or losses calculated for Mexico income tax purposes on the revaluation of
U.S. dollar‑denominated monetary assets and liabilities result in a peso‑denominated income tax exposure for these entities,
leading to fluctuations in Income from equity investments and Income tax expense. This exposure increases as our
U.S. dollar‑denominated net monetary liabilities grow. On January 17, 2023, a wholly-owned Mexican subsidiary entered into a
US$1.8 billion senior unsecured term loan and a US$500 million senior unsecured revolving credit facility with a third party, which
resulted in an additional peso‑denominated income tax expense compared to 2022.
The above exposures are managed using foreign exchange derivatives, although some unhedged exposure remains. The impacts
of the foreign exchange derivatives are recorded in Foreign exchange (gains) losses, net in the Consolidated statement of
income. Refer to the Financial risks and financial instruments section for additional information.
84 | TC Energy Management's discussion and analysis 2023
The period end exchange rates for one U.S. dollar to Mexican pesos were as follows:
December 31, 2023
December 31, 2022
December 31, 2021
16.91
19.50
20.48
A summary of the impacts of transactional foreign exchange gains and losses from changes in the value of the Mexican peso
against the U.S. dollar and associated derivatives is set out in the table below:
year ended December 31
(millions of $)
Comparable EBITDA – Mexico Natural Gas Pipelines1
Foreign exchange gains (losses), net included in comparable earnings
Income tax (expense) recovery included in comparable earnings
2023
(83)
224
(133)
8
2022
2021
(32)
54
(11)
11
1
15
4
20
1
Includes the foreign exchange impacts from the Sur de Texas joint venture recorded in Income (loss) from equity investments in the Consolidated statement of
income.
TC Energy Management's discussion and analysis 2023 | 85
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 activities to meet our financing needs and to manage our capital structure and 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.sedarplus.ca).
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 activities, 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.
Financial Plan
Our capital program is comprised of approximately $31 billion of secured projects, as well as our projects under development,
which are subject to key corporate and regulatory approvals. As discussed throughout this Financial Condition section, our
capital 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 divestitures
• project financing
• potential involvement of strategic or financial partners.
In addition, we may access additional funding options, as deemed appropriate, including common shares issued from treasury
under our DRP and discrete common equity issuances.
Balance sheet analysis
At December 31, 2023, our current assets totaled $11.4 billion and current liabilities amounted to $11.8 billion, leaving us with a
working capital deficit of $0.4 billion compared to $9.6 billion at December 31, 2022. The change in working capital is primarily
due to proceeds received from the sale of a 40 per cent non-controlling equity interest in Columbia Gas and Columbia Gulf,
which also resulted in the reduction of short-term borrowings. 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 $9.6 billion of committed revolving credit facilities available for short-term borrowing capacity, of which no amounts
have been drawn. We also have arrangements in place for a further $2.0 billion of demand credit facilities on which $1.0 billion
remains available as of December 31, 2023
• additional $1.5 billion committed revolving credit facilities at certain of our subsidiaries and affiliates, on which no amounts
have been drawn
• our access to capital markets, including through securities issuances, incremental credit facilities, our asset divestiture
program and DRP, if deemed appropriate.
Our total assets at December 31, 2023 were $125.0 billion compared to $114.3 billion at December 31, 2022 with the increase
primarily reflecting our capital spending program, working capital, increased equity investments, partially offset by depreciation
and a weaker U.S. dollar at December 31, 2023 compared to December 31, 2022 on translation of our U.S. dollar-denominated
assets.
At December 31, 2023 our total liabilities were $86.0 billion, compared to $80.2 billion at December 31, 2022 due to the net
effect of movements in debt, working capital and a weaker U.S. dollar at December 31, 2023 compared to December 31, 2022 on
translation of our U.S. dollar-denominated liabilities.
Our equity at December 31, 2023 was $39.0 billion compared to $34.1 billion at December 31, 2022. The increase is primarily due
to the sale of a 40 per cent non-controlling equity interest in Columbia Gulf and Columbia Gas, partially offset by net income,
net of common and preferred dividends paid, and lower other comprehensive income.
86 | TC Energy Management's discussion and analysis 2023
Consolidated capital structure
The following table summarizes the components of our capital structure.
at December 31
(millions of $, unless otherwise noted)
Notes payable
Long-term debt, including current portion
Cash and cash equivalents
Junior subordinated notes
Preferred shares
Common shareholders' equity
Non-controlling interests
2023
—
52,914
(3,678)
49,236
10,287
2,499
27,054
9,455
98,531
Per cent
of total
—
54
(4)
50
10
3
27
10
100
2022
6,262
41,543
(620)
47,185
10,495
2,499
31,491
126
91,796
Per cent
of total
7
45
(1)
51
11
3
35
—
100
Provisions of various trust indentures and credit arrangements with certain of our subsidiaries can restrict those subsidiaries'
ability 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, 2023.
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) provided by investing activities
Net cash (used in) provided by financing activities
Effect of foreign exchange rate changes on cash and cash equivalents
Increase (decrease) in cash and cash equivalents
2023
7,268
(12,287)
8,093
3,074
(16)
3,058
2022
6,375
(7,009)
487
(147)
94
(53)
2021
6,890
(7,712)
(88)
(910)
53
(857)
TC Energy Management's discussion and analysis 2023 | 87
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 disposition of equity interest1
Focus Project costs, net of current income tax
Keystone regulatory decisions, net of current income tax
Liquids Pipelines business separation costs
Milepost 14 insurance expense
Settlement of Mexico prior years' income tax assessments
Keystone XL preservation and other, net of current income tax
Current income tax expense on Keystone XL asset impairment charge and other
Voluntary Retirement Program, net of current income tax
Comparable funds generated from operations
2023
7,268
(207)
7,061
736
54
53
40
36
—
14
(14)
—
7,980
2022
6,375
639
7,014
—
—
27
—
—
196
20
96
—
7,353
2021
6,890
287
7,177
—
—
—
—
—
—
40
140
49
7,406
1
Current income tax expense related to applying an approximate 24 per cent tax rate to the tax gain on sale of a 40 per cent non-controlling equity interest in
Columbia Gas and Columbia Gulf. This is offset by a corresponding deferred tax recovery resulting in no net impact to tax expense.
Net cash provided by operations
Net cash provided by operations increased by $893 million in 2023 compared to 2022 primarily due to the amount and timing of
working capital changes and higher funds generated from operations.
Net cash provided by operations decreased by $515 million in 2022 compared to 2021 primarily due to the amount and timing of
working capital changes and lower funds generated from operations.
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 $627 million in 2023 compared to 2022 primarily due to higher
comparable EBITDA, increased distributions from our equity investments, higher interest earned on short-term investments and
net realized gains on derivatives used to manage our foreign exchange exposures, partially offset by higher interest expense.
Comparable funds generated from operations decreased by $53 million in 2022 compared to 2021 primarily due to higher
interest expense and net realized losses on derivatives used to manage our foreign exchange exposures, partially offset by higher
comparable EBITDA.
88 | TC Energy Management's discussion and analysis 2023
Cash (used in) provided by investing activities
year ended December 31
(millions of $)
Capital spending
Capital expenditures
Capital projects in development
Contributions to equity investments
Acquisitions, net of cash acquired
Loans to affiliate (issued) repaid, net
Keystone XL contractual recoveries
Proceeds from sales of assets, net of transaction costs
Other distributions from equity investments
Deferred amounts and other
2023
2022
2021
(8,007)
(142)
(4,149)
(12,298)
(307)
250
10
33
23
2
(6,678)
(49)
(2,234)
(8,961)
—
(11)
571
—
1,433
(41)
(7,009)
(5,924)
—
(1,210)
(7,134)
—
(239)
—
35
73
(447)
(7,712)
Net cash (used in) provided by investing activities
(12,287)
Net cash used in investing activities increased from $7.0 billion in 2022 to $12.3 billion in 2023 as a result of higher contributions
to equity investments primarily related to Coastal GasLink LP, as well as increased capital spending in 2023.
Net cash used in investing activities decreased from $7.7 billion in 2021 to $7.0 billion in 2022 largely as a result of higher other
distributions from our equity investments primarily related to our proportionate share of the Sur de Texas debt repayment,
contractual recoveries received in 2022 with respect to the Keystone XL pipeline project termination in 2021, as well as a loan
issued to one of our affiliates in 2021, partially offset by higher capital spending in 2022.
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 Energy Solutions
Corporate
2023
6,184
2,660
2,292
49
1,080
33
2022
4,719
2,137
1,027
143
894
41
2021
2,737
2,820
129
571
842
35
12,298
8,961
7,134
1
Capital spending reflects cash flows associated with our Capital expenditures, Capital projects in development and Contributions to equity investments. Refer to
Note 5, Segmented information, of our 2023 Consolidated financial statements for the financial statement line items that comprise total capital spending.
TC Energy Management's discussion and analysis 2023 | 89
Capital expenditures
Capital expenditures in 2023 were incurred primarily for the advancement of the Southeast Gateway pipeline, the NGTL System
expansion and NGTL System/Foothills West Path Delivery programs, Columbia Gas and ANR projects, as well as maintenance
capital expenditures. Higher capital expenditures in 2023 compared to 2022 reflect spending for the advancement of the
Southeast Gateway pipeline, Gillis Access and Columbia Gas projects, partially offset by reduced spending on expansion of the
NGTL System.
Capital projects in development
Costs incurred during 2023 on Capital projects in development were attributable to spending on projects in the Power and
Energy Solutions segment.
Contributions to equity investments
Contributions to equity investments increased in 2023 compared to 2022 mainly due to the draws of $2,520 million on the
subordinated loan by Coastal GasLink LP in 2023 which are accounted for as in-substance equity contributions.
Contributions to equity investments increased in 2022 compared to 2021 mainly due to the partner equity contribution of
approximately $1.3 billion made in 2022 to Coastal GasLink LP in accordance with revised agreements impacting Coastal
GasLink LP. Refer to the Canadian Natural Gas Pipelines – Significant events section for additional information. This was partially
offset by lower contributions made to Iroquois in 2021.
As part of refinancing activities with the Sur de Texas joint venture, on March 15, 2022, our peso-denominated inter-affiliate loan
was fully repaid upon maturity in the amount of $1.2 billion and was subsequently replaced with a new U.S. dollar-denominated
inter-affiliate loan of an equivalent $1.2 billion. The Contributions to equity investments and Other distributions from equity
investments with respect to these refinancing activities are presented above on a net basis, although they are reported on a
gross basis in our Consolidated statement of cash flows. Refer to the Other Information – Related party transactions section for
additional information.
Acquisitions
On March 15, 2023, we acquired 100 per cent of the Class B Membership Interests in the Fluvanna Wind Farm located in Scurry
County, Texas for US$99 million, before post-closing adjustments. On June 14, 2023, we acquired 100 per cent of the Class B
Membership Interests in the Blue Cloud Wind Farm located in Bailey County, Texas for US$125 million, before post-closing
adjustments. Refer to the Significant Events – Power and Energy Solutions section for additional information.
Loans to affiliate
Loans to affiliate (issued) repaid, net represent issuances and repayments on the subordinated demand revolving credit facility
and the subordinated loan agreement that we entered with Coastal GasLink LP to provide additional liquidity and funding to the
Coastal GasLink project. Refer to the Other Information – Related party transactions section for additional information.
Keystone XL contractual recoveries
In 2023, we received $10 million (2022 – $571 million) of contractual recoveries with respect to the Keystone XL pipeline project
termination in 2021.
Proceeds from sales of assets
In 2023, we completed the sale of a 20.1 per cent equity interest in Port Neches Link LLC to its joint venture partner, Motiva
Enterprises, for gross proceeds of $33 million (US$25 million).
In 2021, we completed the sale of our remaining 15 per cent equity interest in Northern Courier for gross proceeds of $35 million.
Other distributions from equity investments
Other distributions from equity investments primarily relate to our proportionate share of the Sur de Texas debt repayments in
2022 and 2021, as well as the return of capital from our equity investment in Iroquois in 2023 and 2022.
Subsequent to the refinancing activities with the Sur de Texas joint venture discussed above, on July 29, 2022, the joint venture
entered into an unsecured term loan agreement with third parties, the proceeds of which were used to fully repay the
U.S. dollar-denominated inter-affiliate loan with TC Energy.
90 | TC Energy Management's discussion and analysis 2023
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
Disposition of equity interest, net of transaction costs
Junior subordinated notes issued, net of issue costs
Redeemable non-controlling interest repurchased
Dividends and distributions paid
Common shares issued, net of issue costs
Preferred shares redeemed
Gains (losses) on settlement of financial instruments
Acquisition of TC PipeLines, LP transaction costs
Net cash (used in) provided by financing activities
2023
(6,299)
15,884
(3,772)
5,328
—
—
(3,052)
4
—
—
—
8,093
2022
766
2,508
(1,338)
—
1,008
—
(3,385)
1,905
(1,000)
23
—
487
2021
1,003
10,730
(7,758)
—
495
(633)
(3,548)
148
(500)
(10)
(15)
(88)
Net cash provided by financing activities increased by $7.6 billion in 2023 compared to 2022 primarily due to higher net
issuances of long-term debt and repayments of notes payable, as well as the receipt of the $5.3 billion (US$3.9 billion) proceeds
upon sale of a 40 per cent non-controlling equity interest in Columbia Gas and Columbia Gulf. Refer to the U.S. Natural Gas
Pipelines – Significant events section for additional information.
Net cash provided by financing activities increased by $0.6 billion in 2022 compared to 2021 primarily due to higher proceeds
from common shares and junior subordinated notes issued in 2022, as well as the 2021 subsequent repurchase of the redeemable
non-controlling interest from contributions received in 2020 in support of Keystone XL construction, partially offset by lower net
issuances of long-term debt and notes payable along with higher preferred shares redemption.
The principal transactions reflected in our financing activities are discussed in further detail below.
TC Energy Management's discussion and analysis 2023 | 91
Long-term debt issued
The following table outlines significant long-term debt issuances in 2023.
(millions of Canadian $, unless otherwise noted)
Company
Issue date
Type
Maturity date
Amount
Interest rate
TRANSCANADA PIPELINES LIMITED
6.20%
Floating
5.28%
5.42%
Floating
6.04%
6.54%
5.93%
6.50%
6.71%
6.04%
6.06%
May 2026
US 1,024
Floating
May 2023
Senior Unsecured Term
Loan1
March 2023
Senior Unsecured Notes
March 2023
Senior Unsecured Notes
March 20262
March 20262
March 2023
Medium Term Notes
July 2030
March 2023
Medium Term Notes
March 2023
Medium Term Notes
March 20262
March 20262
US 850
US 400
1,250
600
400
COLUMBIA PIPELINES OPERATING COMPANY LLC3
August 2023
Senior Unsecured Notes
November 2033
US 1,500
August 2023
Senior Unsecured Notes
November 2053
US 1,250
August 2023
Senior Unsecured Notes
August 2030
August 2023
Senior Unsecured Notes
August 2043
August 2023
Senior Unsecured Notes
August 2063
COLUMBIA PIPELINES HOLDING COMPANY LLC3
August 2023
Senior Unsecured Notes
August 2028
August 2023
Senior Unsecured Notes
August 2026
US 750
US 600
US 500
US 700
US 300
GAS TRANSMISSION NORTHWEST LLC
June 2023
Senior Unsecured Notes
June 2030
US 50
4.92%
TC ENERGÍA MEXICANA, S. DE R.L. DE C.V.
January 2023
Senior Unsecured Term Loan
January 2028
January 2023
Senior Unsecured Revolving
Credit Facility
January 2028
US 1,800
US 500
Floating
Floating
1
2
3
This loan was fully repaid and retired in September 2023. Related unamortized debt issue costs of $3 million were included in Interest expense in the
Consolidated statement of income.
Callable at par in March 2024 or at any time thereafter.
On October 4, 2023, TC Energy completed the sale of a 40 per cent non-controlling equity interest in Columbia Gas and Columbia Gulf. Refer to
Note 24, Non-controlling interests, of our 2023 Consolidated financial statements for additional information.
On January 9, 2024, Columbia Pipelines Holding Company LLC issued US$500 million senior unsecured notes due January 2034,
bearing interest at a fixed rate of 5.68 per cent.
92 | TC Energy Management's discussion and analysis 2023
Long-term debt repaid/retired
The following table outlines significant long-term debt repaid/retired in 2023.
(millions of Canadian $, unless otherwise noted)
Company
TRANSCANADA PIPELINES LIMITED
Retirement
date
Type
October 2023
Senior Unsecured Notes
September 2023
Senior Unsecured Term Loan1
July 2023
Medium Term Notes
Amount
Interest rate
US 625
US 1,024
750
3.75%
Floating
3.69%
TUSCARORA GAS TRANSMISSION COMPANY
November 2023
Unsecured Term Loan
US 32
Floating
NOVA GAS TRANSMISSION LTD.
TC ENERGÍA MEXICANA, S. DE R.L. DE C.V.
April 2023
Debentures
US 200
7.88%
Various
Senior Unsecured Revolving Credit Facility
US 315
Floating
1
In May 2023, we entered into a US$1,024 million senior unsecured term loan and the full amount was drawn. The loan was fully repaid and retired in September
2023. Related unamortized debt issue costs of $3 million were included in Interest expense in the Consolidated statement of income.
For more information about long-term debt and junior subordinated notes issued and long-term debt repaid in 2023, 2022 and
2021, refer to the notes to our 2023 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 ($633 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.
TC Energy Management's discussion and analysis 2023 | 93
Dividend reinvestment plan
Under the DRP, eligible holders of common and preferred shares of TC Energy can reinvest their dividends and make optional
cash payments to obtain additional TC Energy common shares. From August 31, 2022 to July 31, 2023, common shares were
issued from treasury at a discount of two per cent to market prices over a specified period. The participation rate by common
shareholders in the DRP in 2023 was approximately 39 per cent (2022 – 33 per cent), resulting in $737 million
(2022 – $607 million) reinvested in common equity under the program.
Commencing with the dividends declared on July 27, 2023, common shares purchased under TC Energy's DRP are acquired on
the open market at 100 per cent of the weighted average purchase price.
Share information
at February 9, 2024
Common Shares
Preferred Shares
Series 1
Series 2
Series 3
Series 4
Series 5
Series 6
Series 7
Series 9
Series 11
Options to buy common shares
issued and outstanding
1.0 billion
issued and outstanding
14.6 million
7.4 million
10 million
4 million
12.1 million
1.9 million
24 million
18 million
10 million
outstanding
7 million
convertible to
Series 2 preferred shares
Series 1 preferred shares
Series 4 preferred shares
Series 3 preferred shares
Series 6 preferred shares
Series 5 preferred shares
Series 8 preferred shares
Series 10 preferred shares
Series 12 preferred shares
exercisable
4 million
For more information on preferred shares refer to the notes to our 2023 Consolidated financial statements.
94 | TC Energy Management's discussion and analysis 2023
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
2023
2022
2021
$3.72
$0.86975
$1.62659
$0.4235
$1.46703
$0.48725
$1.55993
$0.97575
$0.9405
$0.83775
—
—
$3.60
$0.86975
$0.82611
$0.4235
$0.66655
$0.48725
$0.80668
$0.97575
$0.9405
$0.83775
—
$0.30625
$3.48
$0.86975
$0.50997
$0.4235
$0.34997
$0.48725
$0.41622
$0.97575
$0.9405
$0.83775
$0.34375
$1.225
On February 13, 2024, we increased the quarterly dividend on our outstanding common shares by 3.2 per cent to $0.96 per
common share for the quarter ending March 31, 2024 to shareholders of record at the close of business on March 28, 2024,
which equates to an annual dividend of $3.84 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, 2024, we had a total of $11.8 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
TCPL / TCPL USA
TCPL / TCPL USA
Supports commercial paper program and for general
corporate purposes
Supports commercial paper programs and for general
corporate purposes of the borrowers, guaranteed by TCPL
Supports commercial paper programs and for general
corporate purposes of the borrowers, guaranteed by TCPL
December 2028
3.0
2.8
December 2024
US 2.5
US 2.3
December 2026
US 2.5
US 2.5
Demand senior unsecured revolving credit facilities:
TCPL / TCPL USA
Supports the issuance of letters of credit and provides
additional liquidity; TCPL USA facility guaranteed by TCPL
Demand
2.0 2
1.0 2
1
2
Unused capacity is net of commercial paper outstanding and facility draws.
Or the U.S. dollar equivalent.
At February 9, 2024, our operated affiliates had an additional $1.5 billion of undrawn capacity on third-party demand and
committed credit facilities.
TC Energy Management's discussion and analysis 2023 | 95
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, 2023
(millions of $)
Long-term debt and junior subordinated notes1
Operating leases2
Purchase obligations and other
Total
< 1 year
1 - 3 years
4 - 5 years
> 5 years
63,503
548
4,988
69,039
2,938
72
2,649
5,659
8,066
9,328
43,171
134
813
117
517
225
1,009
9,013
9,962
44,405
1
2
Excludes issuance costs and fair value adjustments.
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 at December 31, 2023 was nil (2022 – $6.3 billion).
Long-term debt and junior subordinated notes
At December 31, 2023, we had $52.9 billion (2022 – $41.5 billion) of long-term debt and $10.3 billion (2022 – $10.5 billion) of
junior subordinated notes.
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 18 years.
Interest payments
At December 31, 2023, scheduled interest payments related to our long-term debt and junior subordinated notes were
as follows:
at December 31, 2023
(millions of $)
Long-term debt
Junior subordinated notes
Total
< 1 year
1 - 3 years
4 - 5 years
> 5 years
25,439
50,734
76,173
2,373
611
2,984
4,323
1,318
5,641
3,612
1,678
5,290
15,131
47,127
62,258
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.
We have entered into PPAs with solar and wind-power generating facilities ranging from 2024 to 2038, that require the purchase
of generated energy and associated environmental attributes. At December 31, 2023, the total planned capacity secured under
the PPAs is approximately 800 MW with the generation subject to operating availability and capacity factors. These PPAs do not
meet the definition of a lease or derivative. Future payments and their timing cannot be reasonably estimated as they are
dependent on when certain underlying facilities are placed in service and the amount of energy generated. Certain of these
purchase commitments have offsetting sale PPAs for all or a portion of the related output from the facility.
96 | TC Energy Management's discussion and analysis 2023
Purchase obligations and other
At December 31, 2023, payments for purchase obligations and other were as follows:
at December 31, 2023
(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
Transportation by others1
Capital spending2
Other
Power and Energy Solutions
Capital spending2
Other3
Corporate
Other
Capital spending2
Total
< 1 year
1 - 3 years
4 - 5 years
> 5 years
1,685
226
546
340
177
197
142
314
1,312
1,312
43
6
3
231
187
395
14
26
6
3
200
22
236
14
4,988
2,649
363
20
216
26
—
17
—
—
31
28
112
—
813
341
7
94
—
—
—
—
—
—
28
47
—
517
804
2
94
—
—
—
—
—
—
109
—
—
1,009
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.
TC Energy Management's discussion and analysis 2023 | 97
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 guarantee has terms that can be renewed in June 2024, with the annual option to extend for one year periods
ending in 2053.
At December 31, 2023, our share of potential exposure under the Sur de Texas pipeline guarantees was estimated to be
$97 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 that can be
renewed in December 2025 and is extendable for any number of successive two-year periods, with a final renewal period of
three years ending in 2065.
At December 31, 2023, 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, 2023 to be approximately $80 million
with a carrying amount of $3 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 2023, we made funding contributions of $28 million to our defined benefit pension plans, $9 million for other post-retirement
benefit plans and $64 million for the savings plan and defined contribution plans. Total letters of credit provided for the funding
of solvency requirements to the Canadian defined benefit plan at December 31, 2023 was $244 million (2022 – $322 million;
2021 – $322 million).
In 2024, we expect to make no contributions for the defined benefits pension plans, funding contributions of approximately
$6 million for other post-retirement benefit plans and approximately $70 million for the savings plans and defined contribution
pension plans. We do not expect to issue additional letters of credit to the Canadian DB Plan for the funding of solvency
requirements.
The net benefit cost for our defined benefit and other post-retirement plans decreased to $20 million in 2023 from $57 million in
2022 primarily due to the impact of increased interest rates.
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.
98 | TC Energy Management's discussion and analysis 2023
Other information
RISK OVERSIGHT AND ENTERPRISE RISK MANAGEMENT
Risk management is embedded in all activities at TC Energy and 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 tolerances. We manage
risk through a centralized Enterprise Risk Management (ERM) program that systematically identifies enterprise risks, including
sustainability-related risks, which could materially impact the achievement of our strategic objectives.
The purpose of the ERM program is to address risks to, or yielding from, the execution of our business strategies, as well as
enabling practices that allow us to identify and monitor emerging risks. Specifically, the ERM program and framework provides
an end-to-end process for risk identification, analysis, evaluation and mitigation, and the ongoing monitoring and reporting to
the Board, CEO and Executive Vice-Presidents, including the Chief Risk Officer.
Our Board retains general oversight of all enterprise risks, as identified below, and specifically has direct oversight of reputation
and relationships, political and regulatory uncertainty, capital allocation strategy, project 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. It also participates in detailed presentations on each
enterprise risk 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 sustainability-related risks, 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, major project execution, health, safety, sustainability and environmental risks,
including climate-related risks
• the Audit Committee oversees management's role in managing financial risk, including market risk, counterparty credit risk
and cybersecurity.
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.
Further, our management of climate-related governance, strategy, risks and opportunities, metrics and targets are outlined in
our comprehensive TCFD alignment section of our Report on Sustainability. A summary of enterprise-wide risks with potential to
impact our strategic objectives can be found below. These risks are being continuously monitored through our robust ERM
program, which includes a network of emerging risk liaisons in key positions across the organization who are responsible for
identifying potential enterprise-level risks that are reported quarterly to the Board of Directors.
As part of our commitment to continuous improvement of the ERM program, we identified and are working towards adopting
Key Risk Indicators (KRIs) for risk events that may impact our ability to achieve our strategic objectives. These metrics will
establish a set of appropriate indicators that will provide quantifiable metrics and objective rationale, as well as meaningful
trending, for each enterprise risk. Going forward, KRIs will be used to inform our annual in-depth review of our enterprise risks
conducted by the Board.
TC Energy Management's discussion and analysis 2023 | 99
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,
contracts or 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.
Our management system, TOMS, provides structured
requirements and processes for our day-to-day work to
protect us, our co-workers, our workplace and assets, the
communities we work in and the environment. TOMS
establishes operational risk management practices to
minimize risk exposure and operational failures and is
continually improved based on new knowledge from
performance monitoring of our assets, learnings from
external incidents and collaborative work with industry and
regulators. 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.
Although we have a comprehensive insurance program to
mitigate a certain portion of our risk, insurance does not
cover all events in all circumstances.
Cybersecurity
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 cybersecurity risks and
could be subject to cybersecurity events
directed against our information
technology or physical assets. This risk
has been elevated with the increased
pace of technology adoption, as well as
evolving geopolitical conflicts. 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, bringing novel or
unexpected vulnerabilities. This has
resulted in stricter cybersecurity
regulations in the jurisdictions in which
we operate.
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, government agencies and
environmental non-governmental
organizations.
A cyberattack could expose our business
to a wide range of losses, including
misuse or interruption of critical
information and functions. It could also
affect our operations by damaging our
assets, resulting in potential safety and/or
environmental incidents. A significant
attack could also cause reputational harm,
competitive disadvantage, regulatory
enforcement actions and potential
litigation, which could have a material
adverse effect on our operations and/or
financial position.
We maintain a comprehensive cybersecurity strategy and
program which aligns with regulatory and industry
standards. Our strategy is regularly reviewed and updated,
and the status of our cybersecurity program is reported to
the Audit Committee on a quarterly basis. The program
includes governance covered by policies and standards, risk
assessments, continuous monitoring of networks and other
information sources for threats to the organization,
comprehensive incident response plans/processes and a
robust cybersecurity awareness program for employees and
contractors. We have insurance which may cover losses
from physical damage to our facilities as a result of a
cybersecurity event; however, insurance does not cover all
events in all circumstances.
Inadequately managing stakeholder
expectations and concerns, including
those related to climate and sustainability,
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.
Our core values – safety, innovation, responsibility,
collaboration and integrity – 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. Further, our
management of climate-related governance, strategy, risks
and opportunities, metrics and targets are outlined in our
annual Report on Sustainability.
100 | TC Energy Management's discussion and analysis 2023
Risk and description
Impact
Monitoring and mitigation
Political and regulatory uncertainty
Our ability to construct and operate
energy infrastructure requires regulatory
approvals and is dependent on evolving
policies and regulations by federal,
state, provincial and local government
agencies. This includes changes in
regulation that may impact our projects
and operations into the future, which
could affect the financial performance
of our assets.
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 and changes in investor
and lender sentiment could affect our
ability to access capital at a competitive
cost. Geopolitical instability, higher
interest rates, and persistent inflation
could put further pressures on the cost
of capital into the future.
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. We continue to adapt our
strategy to protect and enhance the
incumbency of our businesses.
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.
Regulations could also increase the cost of
our operations, due to complying with
new or more stringent regulations,
resulting in the inability to earn a
reasonable return on our invested capital.
A higher cost of capital could negatively
impact our ability to deliver an attractive
return on our investments or inhibit both
short and long-term growth. Significant
increases to interest rates could result in a
higher cost of borrowing and therefore
negatively impact our earnings.
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.
Project execution and capital costs
Investing in large infrastructure projects
involves substantial capital commitments
and associated execution risks, including
skilled labour shortages and weather-
related delays, which can impact project
costs and schedules, based on the
assumption that these assets will deliver
an attractive return on investment in the
future.
While we carefully determine the
expected cost of our capital projects,
under some commercial arrangements,
we bear capital cost overrun and schedule
risk which may decrease our return on
these projects.
We 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 stakeholders in the
development and operation of our assets.
We identify emerging risks including customer, regulatory
and government decisions, as well as innovative technology
development and report to 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
asset divestitures as a 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 sustainability-related
updates. Sustainability remains a key consideration in
determining strategy, capital allocation and engagement
with capital markets. We conduct research annually around
the evolving sustainability 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 effectively rotate capital while adhering to
our risk preferences and focus on per share metrics. We
conduct analyses to confirm the longer-term resilience of
the supply and demand markets we serve 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 to respond to changing market conditions.
Our Project Governance program supports project
execution and operational excellence. The program aligns
with TOMS which provides the framework and standards to
optimize project execution, 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.
TC Energy Management's discussion and analysis 2023 | 101
Risk and description
Impact
Monitoring and mitigation
Talent attraction, retention, and succession planning
Critical skills are required to execute our
strategy which include a deep
understanding of the energy industry,
geopolitical environment and various
regulatory regimes in the areas we
operate. The talent landscape is
undergoing high degrees of change
necessitating adaptation, flexibility and
constant monitoring of enterprise-wide
talent strategies.
Talent challenges could significantly
impact the organization through increased
costs, decreased productivity, and the
ability to effectively compete in the
marketplace. It could also result in a
failure to achieve our strategic objectives.
We assess our talent risk using a framework based on
people data and trends, which we examine for level of
criticality. We use the outcome of this assessment to
determine which talent programs will yield the best results
to attract, retain and develop talent. Plans to enhance our
workforce planning initiatives are underway.
Climate change
Physical and transition risks associated with climate change have the potential to intensify the enterprise risks outlined above.
Our business, operations, financial condition and performance may be impacted by climate change policies and its associated
impacts. We report and monitor material climate policy and related developments through our ERM program to ensure
Management and our Board of Directors have visibility to the broader perspective, and that mitigation plans are applied in a
holistic and consistent manner.
Physical Risks
Physical risks to assets could include, but are not limited to severe weather events, wildfires, and longer-term shifts in climate
patterns, temperature and precipitation; however, it is difficult to predict the timing, frequency, or severity of such events.
Physical risks from climate change could carry financial implications, such as costs resulting from direct damage to our assets,
loss of revenues due to business interruption or indirect effects such as value chain disruption. We may experience increased
insurance premiums and deductibles, or a decrease in available coverage, for our assets in areas subject to severe weather.
Our engineering standards are regularly reviewed to ensure assets continue to be designed and operated to withstand the
potential impacts of climate change. Our emergency response plans are focused on quickly and effectively responding to
emergencies and mitigating impacts in a timely manner. We also maintain insurance as a mitigative measure to reduce the
financial impact associated with damage to our assets due to extreme weather events.
Transition Risks
Transition risks arise as a result of the global shift to a more sustainable, lower GHG emissions economy. Transition risks include
policy, legal, technological, market and reputational risks. These risks include but are not limited to: changes in energy supply
and demand trajectories, the pace and reliability of technological advancements, changes in decarbonization policies and
regulations, and stakeholder perceptions of our role in the transition to a lower GHG emissions intensive economy. Financial
implications from transition risks could include asset impairment due to new or amended climate-related regulations, increased
climate change reporting requirements, increased commodity price volatility, reduced demand for fossil fuels, challenges in
permitting projects and limited access to and or increased cost of capital. Our financial performance could also be impacted by
shifting consumer demands and the development and deployment of new technology.
Our exposure to climate change related transition risk and resulting policy changes is managed through our business model,
which is based on a long-term, low-risk strategy whereby much of our earnings are underpinned by regulated cost-of-service
arrangements and/or long-term contracts. We factor transition risks into our capital planning, financial risk management and
operational activities and are working towards reducing the GHG emissions intensity of our existing operations.
We also evaluate the financial resilience of our asset portfolio against a range of future outcomes as part of our strategic
planning process. We are exploring technologies, implementing strategies, and incorporating our GHG emissions reduction
targets in our capital allocation framework and decision-making process.
Information on how we manage climate-related risks and opportunities can be found in our annual Report on Sustainability.
102 | TC Energy Management's discussion and analysis 2023
Health, safety, sustainability and environment
The Board's HSSE Committee oversees operational risk, major project execution risk, occupational and process safety,
sustainability, security of personnel, environmental and climate change related risks, as well as monitoring 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, standards and procedures.
TC Energy's Operational Management System, TOMS, leverages industry best practices and standards and incorporates
applicable regulatory requirements. TOMS governs health, safety, environment, and operational integrity matters at TC Energy.
It is applicable across Canada, U.S. and Mexico throughout the lifecycle of our assets and employs a continuous improvement
cycle. Periodic audits of TOMS, as they apply to our Canadian assets, are conducted by the CER and lessons learned from these
audits are shared and applied across our system where applicable.
The HSSE Committee reviews performance and operational risk management. It receives updates and reports on:
• overall HSSE corporate governance
• operational performance
• asset integrity
• significant occupational safety and process safety incidents
• occupational and process safety performance metrics
• occupational health, safety and industrial hygiene, which includes physical and mental health, as well as psychological safety
• emergency preparedness, incident response and evaluation
• environment, including 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, which 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 and the Reconciliation Action Plan.
To enhance our overall governance structure, we have evolved our corporate HSSE committee into two separate committees
that report to the Board HSSE Committee:
• a Sustainability Management Committee that provides strategic leadership and direction on sustainability issues
• an Operating Committee that is responsible for making enterprise decisions in support of management system governance,
strategic system enhancements and operational risk management related to safety and environmental considerations.
Focus on sustainability
Starting in 2022, we embedded sustainability goals into our corporate scorecard to progress and advance key strategic priorities
including growth and energy transition. Our 2023 corporate scorecard includes goals on safety, diversity of women and visible
minorities in leadership and management of our GHG emissions. Our approach to sustainability is guided by our nine
commitments that align to the United Nations (UN) Sustainable Development Goals, with tangible targets to measure and drive
performance in areas including emissions reductions, women in leadership, biodiversity and safety. We are committed to
ensuring balanced and transparent disclosure of our progress against these targets annually in our Report on Sustainability.
Another way in which we demonstrate our commitment to sustainability is through our pursuit of voluntary initiatives. In
May 2023, we joined Catalyst, a global non-profit organization supporting companies with solutions and strategies to accelerate
progress for women through workplace inclusion. In June 2023, we completed a pilot of the Taskforce for Nature-based Financial
Disclosures framework to support the development of an approach to disclosure of nature-related dependencies, impacts, risks
and opportunities. In July 2023, we signed the UN Women’s Empowerment Principles (WEPs), furthering our commitment to
foster an inclusive, safe and productive workplace for all our staff. By signing the WEPs, we are committing to align with the
seven core principles and take steps to advance gender equality in our workplace and community.
TC Energy Management's discussion and analysis 2023 | 103
Our Reconciliation Action Plan, including the 2022 update, outlines six measurable goals of action to help advance
reconciliation, both internally and in the communities where we operate. Throughout 2023, our Indigenous Advisory Council,
established with members representing Indigenous perspectives across Canada, has advised on strategies, approaches, and
tactics in support of pillar areas of focus including: talent and employment, hiring and contracting, and relationships and
partnerships.
Health, safety and asset integrity
The safety of our employees, contractors and the public, the integrity of our pipelines and our power and energy solutions
infrastructure, are a top priority. All assets are designed, constructed, commissioned, operated and maintained with full
consideration given to safety and integrity, and are placed in service only after all necessary requirements, both regulatory and
internal, have been satisfied.
In 2023, we spent $2.1 billion (2022 – $1.6 billion) for pipeline integrity on the natural gas and liquids pipelines we operate,
which includes expenditures related to our modernization program within our U.S. Natural Gas Pipelines business. Pipeline
integrity spending will fluctuate based on the results of on-going 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 integrity 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 Risk oversight and enterprise risk management section 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 of TOMS, 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. Occupational health, safety and industrial hygiene 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 wellbeing, health education, leader support and improved working
conditions to sustain a productive workforce
• increase mental wellbeing awareness, provide various health and wellness supports and training to employees and leaders,
measure the success of programs and improve psychological safety
• foster a positive safety culture by building human and organizational performance to strengthen our cultural defenses and
develop error-tolerant systems to better protect our people.
104 | TC Energy Management's discussion and analysis 2023
Environmental risk, compliance and liabilities
Through the implementation of TOMS, TC Energy proactively and systematically manages environmental hazards and risks
throughout the lifecycle of our assets. 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. We consider the information collected during environmental
assessments, and where sensitive habitats or areas of high biodiversity value are identified, we apply the biodiversity protection
hierarchy and avoid those areas, as practicable. Where those areas cannot be avoided, we minimize our disturbance, restore and
reclaim the disturbed area and provide offsets where required. To conserve and protect the environment during construction,
information gathered for an environmental impact assessment is used to develop project-specific environmental protection
plans. Whenever the potential exists for a proposed facility or pipeline to interact with water resources, we conduct evaluations
to understand the full nature and extent of the interactions. When we temporarily use water to test the integrity of our
pipelines, we adhere to strict regulatory requirements and ensure water meets applicable water quality standards before it is
discharged or disposed of, and when our construction activities involve crossing waterbodies, we implement protection
measures to avoid or minimize potential adverse effects. Project plans are communicated with stakeholders and Indigenous
communities, as applicable, and engagement with these groups informs the environmental assessments and protection plans.
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, which 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, which 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.
TOMS includes requirements for TC Energy to 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.
TC Energy Management's discussion and analysis 2023 | 105
At December 31, 2023, accruals related to these obligations, with the exception of the accrual related to the Milepost 14
incident, totaled $19 million (2022 – $20 million) representing the estimated amount we will need to manage our currently
known material environmental liabilities. Refer to the Liquids Pipelines – Significant events section for additional information.
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 2023, we incurred $109 million (2022 – $118 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 levels aimed at reducing GHG emissions. We actively monitor and submit comments to
regulators as these new and evolving initiatives are undertaken and policies are implemented. We support transparent climate
change policies that promote sustainable and economically responsible natural resource development. Our assets in specific
geographies are currently subject to GHG regulations and we expect that the number of our assets subject to GHG regulations
will continue to increase over time and across our footprint. Changes in regulations may result in higher operating costs, other
expenses or capital expenditures to comply with new or changing regulations. The following existing jurisdictional policies and
anticipated policies sections describe some of the more relevant existing and anticipated policies applicable to our business.
106 | TC Energy Management's discussion and analysis 2023
Existing jurisdictional policies
Canadian jurisdictions
• Federal: 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, repairs to identified leaking equipment
components following prescribed timelines and measurements to quantify emission reductions. Power facilities are not
affected by this regulation at the current time
• Federal: The Government of Canada has developed the Clean Fuel Regulations (CFR) to achieve reductions in GHG emissions
with a narrowed scope including only liquid fuels, which will not directly impact TC Energy. CFR does allow for credit
generation opportunities for gaseous fuel stream to incentivize GHG emission reduction opportunities. The CFR was finalized
in June 2022 and came into effect in July 2023. Regulated parties and credit generators expressed concerns over uncertainties
about credit availability and recognition for the 2023 and 2024 periods, stemming from ongoing updates like the incomplete
Land Use and Biodiversity Guidance and the anticipated ECCC Life Cycle Assessment model update in July 2024. Amidst these
updates, there are concerns about the timely processing of Carbon Intensity applications, the limited number of
CFR-accredited verification bodies, and the overall clarity regarding key elements for the successful implementation of the
CFR. We continue to closely monitor this file and engage with Canadian policymakers, assessing impacts as further information
is available
• Federal: 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 province of Manitoba. As a result of
the Federal program, our assets across Canada are all subject to some type of carbon pricing and the costs under these
programs are recovered in tolls. The current level of carbon pricing is $65/tonne, increasing by $15/tonne every year to
$170/tonne in 2030
• Federal: 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: 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. The CleanBC Industry Fund 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
• Alberta: 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 Energy Solutions
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 Energy Solutions assets are recovered through market pricing and hedging
activities
• Québec: 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 as are the Canadian Mainline and TQM natural gas
pipeline facilities. The provincial 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. For TQM and the Canadian Mainline assets in
Québec, compliance instruments have been or will be purchased in order to comply with the requirements of this initiative
with these compliance costs being recovered through tolls
TC Energy Management's discussion and analysis 2023 | 107
• Ontario: The Ontario and Federal governments reached an agreement whereby the Federal OBPS in Ontario was replaced on
January 1, 2022 by the Ontario Emissions Performance Standards (OEPS) program. The OEPS program applies to our Canadian
Mainline operations in the province and costs under this program are recovered in tolls
• Saskatchewan: In September 2022, the Saskatchewan and Federal governments reached an agreement whereby the Federal
OBPS in Saskatchewan was replaced on January 1, 2023 by the Saskatchewan Emissions Performance Standards (SEPS) program
for pipeline transmission sector assets. The SEPS apply to our Canadian Mainline and Foothills operations in the province and
costs under this program are recovered in tolls.
U.S. jurisdictions
• Federal: On December 2, 2023, the United States Environmental Protection Agency (USEPA) released a final rule that amends
and supplements the New Source Performance Standards – Subpart OOOO series of volatile organic compound and methane
emissions regulations for the oil and natural gas industry. The rule, collectively referred to as the “Methane Rule,” sets
performance standards for new, modified, or reconstructed sources after December 6, 2022 (OOOOb) and establishes
emission guidelines (EGs) for existing sources prior to December 6, 2022 (OOOOc). Under OOOOc, the states will submit their
plans to meet the EGs for existing sources to the USEPA within 24 months after publication of the final rule, and existing
compressor stations would be required to comply with a state’s new EGs no later than 36 months after the state plan is
submitted to USEPA. The Methane Rule includes fugitive component LDAR requirements, a zero-emission process (pneumatic)
controller standard, emission limitations for reciprocating and centrifugal compressors, and a third-party reporting program
facilitated by USEPA for identifying large gas release events (Super Emitter program). The OOOOb standards will apply to a
relatively limited number of facilities and the costs of compliance are anticipated to be incorporated into new and modified
facilities moving forward. The OOOOc standards would apply to a larger number of existing facilities, but impacts of the rule
are still subject to further evaluation and assessment, and actual compliance deadlines for existing sources will vary based on
state and/or location
• Federal: Final “Good Neighbor Plan” for Ozone National Ambient Air Quality Standards. The USEPA released a final version of
the Good Neighbor Rule on March 15, 2023, effective August 4, 2023, that specifies new limits for emissions of nitrogen oxides
(NOx) from reciprocating internal combustion engines by May 1, 2026. Based on assessments completed thus far, the final rule
could require installation of catalytic controls or retrofit of engines with low emission combustion controls at a cost exceeding
US$500 million. However, seven Federal Circuit courts have granted stays of the Rule within their jurisdictions until decisions
1
and an emergency stay request remains pending before the U.S. Supreme Court
are made on the merits in those proceedings
• 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
• Pennsylvania: In April 2022, the Pennsylvania Department of Environmental Protection (PADEP) published its final Reasonable
Available Control Technologies (RACT) requirements and emission limitations for major stationary sources of NOx and volatile
organic compounds (VOCs) statewide. Columbia Gas Transmission has four facilities impacted by the rule, and initial
notifications and case by case evaluations were submitted to PADEP for these facilities by December 31, 2022. The purpose of
the case-by-case evaluations was to determine whether sources could be re-permitted to the lower emission rate or if
installation of controls would be necessary to comply. Columbia Gas Transmission facilities were able to re-permit to the lower
emission rate based on historic stack test data such that no control installations were needed to comply
• Ohio: Effective March 2022, the Ohio Environmental Protection Agency (OEPA) finalized RACT requirements and limitations for
emissions of NOx from stationary sources in the Cleveland non-attainment area. Columbia Gas Transmission has four facilities
in the Cleveland non-attainment area, with two facilities impacted by the rule. A RACT Study was submitted for one of the
stations subject to the rule, outlining the steps and cost necessary to install controls by March 2025 to comply with the rule.
The other facility subject to the rule is required to perform annual tune-ups to achieve compliance
1
The seven circuit courts that have granted judicial stays for the entirety of litigation are as follows: 4th Circuit (West Virginia), 5th Circuit (Texas, Louisiana,
Mississippi), 6th Circuit (Kentucky), 8th Circuit (Arkansas, Missouri, Minnesota), 9th Circuit (Nevada), 10th Circuit (Oklahoma, Utah) and the 11th Circuit (Alabama).
108 | TC Energy Management's discussion and analysis 2023
• Oregon: The Governor of Oregon issued an executive order to reduce and regulate GHG emissions by establishing annual
reduction goals, developing a new carbon cap and reduce program and enhancing clean fuel standards on January 1, 2022.
The state Department of Environmental Quality recommended a final draft of the rule to the state Environmental Quality
Commission (EQC) and the EQC approved the program which still exempts our facilities and their emissions
• 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
• Washington: In late 2022, the Washington Department of Ecology adopted the Cap-and-Invest Program (CIP), which became
effective in January 2023 and established a comprehensive, market-based program to reduce carbon pollution and achieve the
GHG emissions reduction goals established by the State legislature. The CIP sets a declining limit, or cap, on overall carbon
emissions in the state and requires businesses to obtain allowances equal to their covered GHG emissions. Under the CIP,
companies are incented to reduce emissions to avoid higher compliance costs, as the cost to obtain allowances will increase as
the supply of allowances decreases over time. GTN has three impacted compressor station facilities, and cost exposure under
the CIP is mainly driven by throughput and fuel forecast data, as well as price volatility in the newly established CIP allowance
market. As an active participant in the CIP allowance market, GTN met its base compliance obligation for 2023
• Washington: The Washington Commercial Building Code passed a ban to limit the use of natural gas-powered furnaces and
water heaters in all new commercial and residential properties with four stories or more, starting in July 2023
• New York: On February 2, 2022, the New York Department of Environmental Conservation (NY DEC) adopted 6 NYCRR
Part 203, “Oil and Natural Gas Sector” with an effective date of March 3, 2022, and an initial compliance period commencing
January 1, 2023. Part 203 regulates VOCs and methane emissions from the oil and gas sector. Compliance obligations include
leak detection and repair at operated storage wells, compressor stations, and city gate meter and regulator sites; blowdown
notifications; and reporting of pigging activities, as well as a baseline inventory for all assets in New York.
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 Emissions 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
• 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 GHG emission reductions from prevention and control activities. This regulation
requires the PPCIEM, through which operational and technological practices are adopted, to determine a GHG emissions
intensity 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
• 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 functions as a three-year pilot from 2020 to 2022
allowing 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
• Federal: ECCC committed to expand on the current methane reduction regulations and released draft amendments in
December 2023 to reduce Canada's oil and gas sector methane emissions by at least 75 per cent below 2012 levels by 2030.
The draft amendments introduce a risk-based approach for the detection and repair of fugitive emissions, prohibit all venting
with specific exceptions and offer an alternative performance-based approach using continuous monitoring. TC Energy has
identified several areas for improvement and clarification. We will seek clarifications and adjustments and, in collaboration
with industry associations, will participate in the public consultation process. The updated regulations are expected to come
into force January 1, 2027, with phased requirements through 2030. We will continue to refine our internal emissions
management strategies and update our compliance plans to align with the anticipated regulatory changes
TC Energy Management's discussion and analysis 2023 | 109
• Federal: In December 2023, ECCC released a Regulatory Framework for an Oil and Gas Sector Greenhouse Gas Emissions Cap
that builds on a July 2022 discussion paper to contribute to 2030 climate goals and achieve net-zero by 2050. The framework
proposes to implement a national cap-and-trade system to cap upstream and LNG sub-sector emissions between 35 per cent
to 38 per cent below 2019 levels, with some compliance flexibility up to 20 per cent to 23 per cent below the same baseline
year. Although transmission pipelines are excluded from the proposed regulatory framework, there is a possibility of cascading
effects and unintended consequences. The draft regulations are expected to be released in mid-2024, with final publication in
2025. The regulations are expected to be phased in between 2026 and 2030. We will continue to monitor, assess, and provide
feedback to ECCC on the proposed emissions cap, as appropriate
• Federal: On August 19, 2023, ECCC published the draft Clean Electricity Regulations (CERs), targeting a net-zero electricity
system by 2035. The CERs, effective from January 1, 2025, mandate a GHG emissions intensity standard of 30 tonnes CO2/GWh
for fossil fuel power generation units with a capacity of 25 MW or more, though there are exemptions and limited compliance
flexibilities. The draft regulations, enacted under the Canadian Environmental Protection Act, could potentially affect energy
affordability and reliability and have a significant operational and financial impact to our business; as drafted, our current
cogeneration fleet would be required to meet this new standard by 2035. Throughout the consultation process, we are
actively engaging with the ECCC, providing feedback and collaborating with other industry stakeholders. We will continue
monitoring and providing feedback to ECCC as this file progresses
• British Columbia: Currently, British Columbia is formulating a new carbon pricing model, the British Columbia OBPS. This system
mirrors the federal OBPS system and is forecasted to reduce the carbon tax payments in the near future. However, the British
Columbia OBPS proposes a considerably more stringent threshold compared to the federal OBPS or other analogous
jurisdictions like the Alberta Technology Innovation and Emissions Reduction Regulations. The specifics of the British Columbia
OBPS are still under deliberation and any costs associated with are expected to be recoverable through tolls. We are
proactively observing the developments and offering our feedback. Concurrently, British Columbia is laying the groundwork
for an oil and gas emission cap within the province. We are actively involved in these discussions, providing feedback pertinent
to our operations in British Columbia, with a focus on concerns related to energy affordability and reliability.
U.S. jurisdictions
• Federal: The U.S. Senate passed the PHMSA reauthorization bill, the PIPES Act of 2020, which required PHSMA to promulgate
gas pipeline leak detection and repair regulations. On May 4, 2023, PHMSA released a Notice of Proposed Rulemaking (NPRM)
to regulate methane emissions from new and existing gas transmission, distribution, and gas gathering pipelines, and
underground storage and LNG facilities. PHMSA’s NPRM provides limited exemption for compressor stations recognizing
USEPA’s current and proposed methane standards. The cost of compliance due to the proposed PHMSA regulations is expected
to increase significantly due to new monitoring and repair requirements on the entire natural gas transmission system
• Federal: In May 2023, USEPA released amendments to the previously released June 2022 proposal regarding the GHG Reporting
program that would go into effect on January 1, 2025 and be included in Reporting Year 2024 for GHG reporting due to the
USEPA by March 31, 2025. This proposal includes reporting of a new reporting category (Subpart B – Energy Consumption) and
revisions to global warming potentials. USEPA released another supplemental proposal in August 2023. This proposal includes
reporting of additional emission sources such as reciprocating engine exhaust methane and centrifugal compressor dry seal
venting; revisions to current emission factors for fugitive equipment leaks and pneumatic devices; and options to use facility
specific measurements in place of emission factors for certain emission sources. These proposed revisions would be
implemented with reports prepared for Reporting Year 2025 for GHG reporting due to the USEPA by March 31, 2026. TC Energy
reports to the USEPA as required by the GHG Reporting rule (40 CFR 98)
• Federal: The Inflation Reduction Act (IRA) was passed and signed into law on August 16, 2022. The IRA instructs USEPA to
implement a waste methane fee program by 2024 based on GHG emissions reported to USEPA as required by 40 CFR 98
Subpart W. TC Energy reports to Subpart W for the natural gas transmission compression, underground natural gas storage and
onshore natural gas transmission pipeline industry segments. For these industry segments, the IRA imposes and collects a fee
on methane emissions that exceeds 0.11 per cent of the natural gas sent for sale from the facility. The proposed fee is
US$900/tonne for 2024, US$1,200/tonne for 2025 and US$1,500/tonne for 2026 reporting and forward. In an initial
assessment, there would have been no fee impact to TC Energy based on 2021 or 2022 emissions. The IRA also instructs USEPA
to revise Subpart W by August 2024 to ensure GHG reporting is based on empirical data
110 | TC Energy Management's discussion and analysis 2023
• 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
• California: California Air Resource Board is planning potential changes to their California Oil and Gas Methane Regulation that
include requirements for monitoring plans, repairing leaks after being identified by satellites and changes that would align
with USEPA’s proposed emissions guidelines for existing sources. The California Air Resources Board posted a notice of public
availability on November 2, 2023 for proposed amendments to Sub article 13: Greenhouse Gas Emission Standards for Crude Oil
and Natural Gas Facilities. The amendments consolidated the Delay of Repair (DOR) provisions into a dedicated section and
elaborated on the justification requirements for DOR requests. The proposed amendments if adopted would require
development of an implementation plan for three affected facilities and training for operations personnel
• Michigan: The Michigan Department of Environment, Great Lakes and Energy is currently evaluating potential ozone control
strategies for the southeast Michigan ozone non-attainment area and the interaction of methane and ozone, which may lead
to the development of laws and regulations that affect TC Energy through impacted ANR and Great Lakes facilities in the state
• New York: On July 18, 2019, the Climate Leadership and Community Protection Act (Climate Act) was signed into law, requiring
New York to reduce economy-wide GHG emissions by 40 per cent by 2030 and no less than 85 per cent by 2050 from 1990
levels. The New York State Department of Environmental Conservation (DEC) and New York State Energy Research and
Development Authority (NYSERDA) are developing New York’s Cap-and-Invest Program (NYCI), proposed in 2023, to meet the
Climate Act’s GHG reduction and equity requirements. The NYCI will set an annual cap on the amount of GHG emissions that
are permitted to be emitted in the state. The program is currently in the stakeholder engagement phase, with compliance
aimed to commence in 2025. NYCI will potentially impact TC Energy owned/operated assets in New York, but impacts will be
further evaluated once a draft rule is published, which is expected in 2024.
Changes to environmental remediation regulations – U.S. Jurisdictions
• Federal: The USEPA proposed a rule entitled, Alternate Polychlorinated Biphenyl (PCB) Extraction Methods and Amendments to
PCB Cleanup and Disposal Regulations in 2021. The rule addresses a myriad of issues related to laboratory methodologies,
performance-based disposal options for PCB remediation waste and emergency situations, among other proposed changes.
We are currently reviewing the proposed rule to determine its impact.
In addition to the above, there are new mandatory climate-related disclosure requirements being issued in jurisdictions in which
we operate. These disclosure requirements may impact how we report our climate-related risks and opportunities, strategy, risk
management and GHG emission metrics and targets. We continue to monitor these developments and progress activities in
anticipation of these new requirements.
Other sustainability related regulations
There are also mandatory cybersecurity and human rights-related disclosure requirements being issued in jurisdictions in which
we operate. While these disclosure requirements do not necessarily apply to us, they may impact how we report on non-climate
related sustainability risks, opportunities, strategies, governance and incidents. We continue to monitor these developments and
progress activities related to these new and anticipated requirements.
TC Energy Management's discussion and analysis 2023 | 111
Financial risks
We are exposed to various financial risks 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. Our risks 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 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 manage 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 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 demand for these commodities could negatively impact opportunities to
expand our asset base and/or re-contract with our shippers and customers as contractual agreements expire.
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.
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 directly affect our comparable EBITDA and
may also impact comparable earnings.
112 | TC Energy Management's discussion and analysis 2023
A portion of our Mexico Natural Gas Pipelines monetary assets and liabilities are peso-denominated, while our Mexico operations'
financial results are denominated in U.S. dollars. Therefore, changes in the value of the Mexican peso against the U.S. dollar can
affect our comparable earnings. In addition, foreign exchange gains or losses calculated for Mexico income tax purposes on the
revaluation of U.S. dollar-denominated monetary assets and liabilities result in a peso-denominated income tax exposure for
these entities, leading to fluctuations in Income from equity investments and Income tax expense.
We actively manage a portion of our foreign exchange risk using foreign exchange derivatives. Refer to the Foreign exchange
section for additional information.
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 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
• net investment in leases and certain contract assets in Mexico.
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 reasonable and supportable forecasts to determine any
impairment, which is recognized in Plant operating costs and other. At December 31, 2023 and 2022, we had no significant
credit risk concentrations and no significant amounts past due or impaired. We recorded an $80 million recovery for the year
ended December 31, 2023 on the expected credit loss provision before tax recognized on the TGNH net investment in leases and
certain contract assets in Mexico (2022 – $163 million loss). Other than the expected credit loss provision noted above, we had
no significant credit losses at December 31, 2023 and 2022. Refer to Note 29, Risk management and financial instruments, of our
2023 Consolidated financial statements for additional information.
We have significant credit and performance exposure to financial institutions that 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. Our portfolio of financial sector exposure consists primarily of highly-rated
investment grade, systemically important financial institutions.
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 additional
information.
TC Energy Management's discussion and analysis 2023 | 113
Legal proceedings
TC Energy and its subsidiaries are subject to various legal proceedings, arbitrations and actions arising in the normal course of
business. We assess all legal matters on an ongoing basis, including those of our equity investments. With the potential
exception of the matters discussed in Note 32, Commitments, contingencies and guarantees, of our 2023 Consolidated financial
statements, for which the claims are material and there is a reasonable possibility of loss, but have not been assessed as probable
and a reasonable estimate of loss cannot be made, it is the opinion of management that the ultimate resolution of such
proceedings and actions will not have a material impact on our consolidated financial position or results of operations.
114 | TC Energy Management's discussion and analysis 2023
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, 2023, 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, 2023, 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, 2023, the internal control
over financial reporting was effective.
Our internal control over financial reporting as of December 31, 2023 has been audited by KPMG LLP, an independent registered
public accounting firm, as stated in their attestation report which is included in our 2023 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 2023 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 2023 | 115
CRITICAL ACCOUNTING ESTIMATES
In preparing our Consolidated financial statements, we are 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. We use the most current information available and exercise 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. Refer to Note 2, Accounting
policies, of our 2023 Consolidated financial statements for additional information.
Impairment of equity investment in Coastal GasLink LP
On February 1, 2023, TC Energy announced that the revised capital cost of the Coastal GasLink pipeline project was expected
to be approximately $14.5 billion. The revised estimate of total project costs and our corresponding future funding requirements
were indicators that a decrease in the value of our equity investment had occurred. A valuation assessment was completed at
December 31, 2022 and at each reporting period through September 30, 2023 and we concluded that the fair value of
TC Energy’s investment was below its carrying value at each period an assessment was performed. We determined that
there was an other-than-temporary impairment of our equity investment in Coastal GasLink LP, which resulted in a pre-tax
impairment charge of $2,100 million ($1,943 million after tax) for the year ended December 31, 2023, in Impairment of equity
investment in the Consolidated statement of income in the Canadian Natural Gas Pipelines segment. The impairment charge
reflected the net impact of changes in the subordinated loan for the nine months ended September 30, 2023, along with
TC Energy’s proportionate share of unrealized gains and losses on interest rate derivatives in Coastal GasLink LP and other
changes to the equity investment. The cumulative pre-tax impairment charge recognized to date at December 31, 2023 is
$5,148 million ($4,586 million after tax). The impairment of the subordinated loan resulted in unrealized non-taxable capital
losses that are not recognized. Refer to Note 8, Coastal GasLink, of our 2023 Consolidated financial statements for additional
information.
The fair value of TC Energy’s investment in Coastal GasLink LP at September 30, 2023 was estimated using a 40-year discounted
cash flow model and incorporated assumptions related to the capital cost estimates, discount rates and long-term financing
plans.
At December 31, 2023, there were no events or changes in circumstances from September 30, 2023 indicating a significant
adverse impact on the estimated fair value of our investment in Coastal GasLink LP, therefore there was no other-than-
temporary impairment that existed at December 31, 2023. Refer to our 2023 Consolidated financial statements for additional
information.
Impairment of 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.
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.
116 | TC Energy Management's discussion and analysis 2023
Qualitative goodwill impairment indicators
As part of the annual goodwill impairment assessment at December 31, 2023, we evaluated qualitative factors impacting the fair
value of the underlying reporting units for all reporting units other than for the Tuscarora and North Baja reporting units, which
are described below. It was determined that it was more likely than not that the fair value of these reporting units exceeded
their carrying amounts, including goodwill.
Sale of a 40 per cent non-controlling equity interest in Columbia Gas and Columbia Gulf
In conjunction with the process leading up to the sale of a 40 per cent non-controlling equity interest in Columbia Gas and
Columbia Gulf, we performed a quantitative goodwill impairment test for the Columbia Pipeline Group, Inc. (Columbia)
reporting unit at June 30, 2023. Refer to the U.S. Natural Gas Pipelines – Significant events section for additional information on
this sale transaction.
In the determination of the fair value utilized in the quantitative goodwill impairment test for the Columbia reporting unit, we
performed a discounted cash flow analysis using projections of future cash flows and applied a risk-adjusted discount rate and
terminal value multiple which involved significant estimates and judgments. It was determined that the fair value of the
Columbia reporting unit exceeded its carrying value, including goodwill. Although goodwill was not impaired, the estimated fair
value in excess of the carrying value was less than 10 per cent. There is a risk that reductions in future cash flow forecasts and
adverse changes in other key assumptions could result in a future impairment of a portion of the goodwill balance relating to
Columbia.
North Baja and Tuscarora
We elected to proceed directly to a quantitative annual impairment test at December 31, 2023 for the $63 million of goodwill
related to the North Baja reporting unit due to the passage of time from the previous quantitative test at December 31, 2018. We
also elected to proceed directly to a quantitative annual impairment test for the $30 million of goodwill related to the Tuscarora
reporting unit due to the passage of time from the previous quantitative test at December 31, 2018, and subsequent to the
Tuscarora Section 4 rate case settlement in 2023. It was determined that the fair values of North Baja and Tuscarora exceeded
their carrying values, including goodwill, at December 31, 2023.
TC Energy Management's discussion and analysis 2023 | 117
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 refunded or recovered through the tolls
charged by us. As a result, these gains and losses are deferred as regulatory liabilities or regulatory assets 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
2023
1,285
155
(1,143)
(106)
191
2022
614
91
(871)
(151)
(317)
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, 2023
(millions of $)
Derivative instruments held for trading
Derivative instruments in hedging relationships
Total fair
value
181
10
191
< 1 year
1 - 3 years
4 - 5 years
> 5 years
142
—
142
75
(2)
73
24
5
29
(60)
7
(53)
118 | TC Energy Management's discussion and analysis 2023
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
Unrealized gains (losses) in the year
Commodities
Foreign exchange
Realized gains (losses) in the year
Commodities
Foreign exchange
Derivative Instruments in Hedging Relationships2
Realized gains (losses) in the year
Commodities
Interest rate
2023
2022
2021
96
246
811
155
(2)
(43)
14
(149)
759
(2)
(73)
(3)
9
(203)
287
240
(44)
(32)
1
2
Realized and unrealized gains (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 (losses) on foreign exchange held-for-trading derivative instruments are included on a net basis in Foreign exchange
(gains) losses, net in the Consolidated statement of income.
In 2023, there were no gains or losses included in Net income (loss) relating to discontinued cash flow hedges where it was probable that the anticipated
transaction would not occur (2022 – nil; 2021 – realized loss of $10 million).
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 29, Risk
management and financial instruments, of our 2023 Consolidated financial statements.
TC Energy Management's discussion and analysis 2023 | 119
RELATED PARTY TRANSACTIONS
Related party transactions are conducted in the normal course of business and are measured at the exchange amount, which is
the amount of consideration established and agreed to by the related parties.
Coastal GasLink LP
We hold a 35 per cent equity interest in Coastal GasLink LP, and have been contracted to develop, construct and operate the
Coastal GasLink pipeline.
TC Energy Subordinated Loan Agreement
TC Energy has a subordinated loan agreement with Coastal GasLink LP under which draws by Coastal GasLink LP will fund the
remaining $0.9 billion (December 31, 2022 – $3.3 billion) equity requirement related to the estimated capital cost to complete
the Coastal GasLink pipeline. At December 31, 2023, the total capacity committed by TC Energy under this subordinated loan
agreement was $3.4 billion.
Any amounts outstanding on this loan will be repaid by Coastal GasLink LP to TC Energy, once final project costs are known,
which will be determined after the pipeline is placed in service. Coastal GasLink LP partners, including TC Energy, will contribute
equity to Coastal GasLink LP to ultimately fund Coastal GasLink LP’s repayment of this subordinated loan to TC Energy. We expect
that, in accordance with contractual terms, these additional equity contributions will be predominantly funded by TC Energy but
will not result in a change to our 35 per cent ownership. The total amount drawn on this loan at December 31, 2023 was
$2,520 million (December 31, 2022 – $250 million). Due to impairment charges recognized during the year, the carrying value of
this loan was $500 million at December 31, 2023 (2022 – nil).
Subordinated Demand Revolving Credit Facility
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 $100 million
with an outstanding balance of nil at December 31, 2023 (December 31, 2022 – nil). This revolver was not impacted by the
impairment charge recognized to date.
Sur de Texas
We hold a 60 per cent equity interest in a joint venture with IEnova to own the Sur de Texas pipeline, for which we are the
operator. In 2017, we entered into a MXN$21.3 billion unsecured revolving credit facility with the joint venture, which bore
interest at a floating rate. On March 15, 2022, as part of refinancing activities with the Sur de Texas joint venture, the
peso-denominated inter-affiliate loan was replaced with a new U.S. dollar-denominated inter-affiliate loan from us for an
equivalent $1.2 billion (US$938 million) with a floating interest rate. On July 29, 2022, the Sur de Texas joint venture entered into
an unsecured term loan agreement with third parties, the proceeds of which were used to fully repay the U.S. dollar-
denominated inter-affiliate loan with TC Energy.
Our Consolidated statement of income reflects the related interest income and foreign exchange impact on this loan receivable
until its repayment on March 15, 2022, which were fully offset upon consolidation with corresponding amounts included in our
proportionate share of Sur de Texas equity earnings as follows:
year ended December 31
(millions of $)
Interest income1
Interest expense2
Foreign exchange losses1
Foreign exchange gains1
2023
2022
2021
Affected line item in the
Consolidated statement of income
—
—
—
—
19
(19)
(28)
28
87
(87)
(41)
41
Interest income and other
Income from equity investments
Foreign exchange (gains) losses, net
Income from equity investments
1
2
Included in our Corporate segment.
Included in our Mexico Natural Gas Pipelines segment.
On March 15, 2022, as part of refinancing activities with the Sur de Texas joint venture, the peso-denominated inter-affiliate loan
discussed above was replaced with a new U.S. dollar-denominated inter-affiliate loan from us of an equivalent $1.2 billion
(US$938 million) with a floating interest rate. On July 29, 2022, the Sur de Texas joint venture entered into an unsecured term
loan agreement with third parties, the proceeds of which were used to fully repay the U.S. dollar-denominated inter-affiliate
loan with TC Energy.
120 | TC Energy Management's discussion and analysis 2023
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 2023 Consolidated financial
statements.
TC Energy Management's discussion and analysis 2023 | 121
QUARTERLY RESULTS
Selected quarterly consolidated financial data
2023
(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
2022
(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
Fourth
4,236
1,463
1,403
$1.41
$1.35
$0.93
Fourth
4,041
(1,447)
1,129
($1.42)
$1.11
$0.90
Third
3,940
(197)
1,035
($0.19)
$1.00
$0.93
Third
3,799
841
1,068
$0.84
$1.07
$0.90
Second
3,830
250
981
$0.24
$0.96
$0.93
Second
3,637
889
979
$0.90
$1.00
$0.90
First
3,928
1,313
1,233
$1.29
$1.21
$0.93
First
3,500
358
1,103
$0.36
$1.12
$0.90
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 addition to the
factors below, our revenues and segmented earnings (losses) are impacted by fluctuations in foreign exchange rates, mainly
related to our U.S. dollar-denominated operations and our peso-denominated exposure.
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
(losses) generally remain relatively stable during any fiscal year. Over the long term, however, they fluctuate because of:
• regulatory decisions
• negotiated settlements with customers
• newly constructed assets being placed in service
• acquisitions and divestitures
• natural gas marketing activities and commodity prices
• developments outside of the normal course of operations
• certain fair value adjustments
• provisions for expected credit losses on net investment in leases and certain contract assets in Mexico.
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.
122 | TC Energy Management's discussion and analysis 2023
In Power and Energy Solutions, 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
• power marketing and trading activities
• 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 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.
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. We also exclude from comparable measures our proportionate share of the
unrealized gains and losses from changes in the fair value of Bruce Power's funds invested for post-retirement benefits and
derivatives related to its risk management activities. These 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.
In fourth quarter 2023, comparable earnings also excluded:
• a $74 million income tax recovery related to a revised assessment of the valuation allowance and non-taxable capital losses on
our equity investment in Coastal GasLink LP
• an $18 million after-tax recovery related to the net impact of a U.S. minimum tax recovery on the 2021 Keystone XL asset
impairment charge and other and a gain on the sale of Keystone XL project assets, offset partially by adjustments to the
estimate for contractual and legal obligations related to termination activities
• an after-tax unrealized foreign exchange loss of $55 million on the peso-denominated intercompany loan between TCPL and
TGNH
• a $25 million after-tax loss on the expected credit loss provision related to the TGNH net investment in leases and certain
contract assets in Mexico
• an after-tax charge of $23 million due to Liquids Pipelines business separation costs related to the spinoff Transaction
• a $9 million after-tax expense related to Focus Project costs
• carrying charges of $4 million after tax as a result of a charge related to the FERC Administrative Law Judge initial decision on
Keystone issued in February 2023 in respect of a tolling-related complaint pertaining to amounts recognized from 2018 to
2022
• preservation and other costs for Keystone XL pipeline project assets of $4 million after tax, which could not be accrued as part
of the Keystone XL asset impairment charge.
In third quarter 2023, comparable earnings also excluded:
• an after-tax impairment charge of $1,179 million related to our equity investment in Coastal GasLink LP
• a $14 million after-tax expense related to Focus Project costs
• an after-tax charge of $11 million due to Liquids Pipelines business separation costs related to the spinoff Transaction
• preservation and other costs for Keystone XL pipeline project assets of $2 million after tax, which could not be accrued as part
of the Keystone XL asset impairment charge
• an after-tax net unrealized foreign exchange gain of $20 million on the peso-denominated intercompany loan between TCPL
and TGNH.
TC Energy Management's discussion and analysis 2023 | 123
In second quarter 2023, comparable earnings also excluded:
• an after-tax impairment charge of $809 million related to our equity investment in Coastal GasLink LP
• a $36 million after-tax accrued insurance expense related to the Milepost 14 incident
• a $25 million after-tax expense related to Focus Project costs
• an after-tax net unrealized foreign exchange loss of $9 million on the peso-denominated intercompany loan between TCPL
and TGNH
• preservation and other costs for Keystone XL pipeline project assets of $4 million after tax, which could not be accrued as part
of the Keystone XL asset impairment charge
• an $8 million after-tax recovery on the expected credit loss provision related to the TGNH net investment in leases and certain
contract assets in Mexico.
In first quarter 2023, comparable earnings also excluded:
• a $72 million after-tax recovery on the expected credit loss provision related to the TGNH net investment in leases and certain
contract assets in Mexico
• $48 million after-tax charge as a result of the FERC Administrative Law Judge initial decision on Keystone issued in February
2023 in respect of a tolling-related complaint pertaining to amounts recognized from 2018 to 2022 which consists of a
one-time pre-tax charge of $57 million and accrued pre-tax carrying charges of $5 million
• an after-tax impairment charge of $29 million related to our equity investment in Coastal GasLink LP
• preservation and other costs for Keystone XL pipeline project assets of $4 million after tax, which could not be accrued as part
of the Keystone XL asset impairment charge.
In fourth quarter 2022, comparable earnings also excluded:
• an after-tax impairment charge of $2.6 billion related to our equity investment in Coastal GasLink LP
• a $64 million after-tax expected credit loss provision related to the TGNH net investment in leases and certain contract assets
in Mexico
• $20 million after-tax charge due to the CER decision on Keystone issued in December 2022 in respect of a tolling-related
complaint pertaining to amounts reflected in 2021 and 2020
• preservation and other costs for Keystone XL pipeline project assets of $8 million after tax, which could not be accrued as part
of the Keystone XL asset impairment charge
• a $5 million after-tax net expense related to the 2021 Keystone XL asset impairment charge and other due to a U.S. minimum
tax, partially offset by the gain on the sale of Keystone XL project assets and reduction to the estimate for contractual and
legal obligations related to termination activities
• a $1 million income tax expense for the settlement related to prior years' income tax assessments in Mexico.
In third quarter 2022, comparable earnings also excluded:
• preservation and other costs for Keystone XL pipeline project assets of $3 million after tax, which could not be accrued as part
of the Keystone XL asset impairment charge.
In second quarter 2022, comparable earnings also excluded:
• preservation and other costs for Keystone XL pipeline project assets of $3 million after tax, which could not be accrued as part
of the Keystone XL asset impairment charge
• a $2 million income tax expense for the settlement related to prior years' income tax assessments in Mexico.
In first quarter 2022, comparable earnings also excluded:
• an after-tax goodwill impairment charge of $531 million related to Great Lakes
• a $193 million income tax expense for the settlement-in-principle of matters related to prior years' income tax assessments in
Mexico
• preservation and other costs for Keystone XL pipeline project assets of $5 million after tax, which could not be accrued as part
of the Keystone XL asset impairment charge.
124 | TC Energy Management's discussion and analysis 2023
FOURTH QUARTER 2023 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 Energy Solutions
Corporate
Total segmented earnings (losses)
Interest expense
Allowance for funds used during construction
Foreign exchange gains (losses), net
Interest income and other
Income (loss) before income taxes
Income tax (expense) recovery
Net income (loss)
Net (income) loss attributable to non-controlling interests
Net income (loss) attributable to controlling interests
Preferred share dividends
Net income (loss) attributable to common shares
Net income (loss) per common share – basic
2023
692
955
150
309
263
(42)
2,327
(845)
132
89
121
1,824
(209)
1,615
(128)
1,487
(24)
1,463
$1.41
2022
(2,592)
882
96
322
298
(4)
(998)
(722)
115
132
53
(1,420)
4
(1,416)
(9)
(1,425)
(22)
(1,447)
($1.42)
Net income (loss) attributable to common shares increased by $2.9 billion or $2.83 per common share for the three months
ended December 31, 2023 compared to the same period in 2022. The significant increase for the three months ended
December 31, 2023 is primarily due to the net effect of the specific items mentioned below. Net income per common share in
both periods also reflect the impact of common shares issued in 2023 and 2022.
Fourth quarter 2023 results included:
• a $74 million income tax recovery related to a revised assessment of the valuation allowance and non-taxable capital losses on
our equity investment in Coastal GasLink LP
• an $18 million after-tax recovery related to the net impact of a U.S. minimum tax recovery on the 2021 Keystone XL asset
impairment charge and other and a gain on the sale of Keystone XL project assets, offset partially by adjustments to the
estimate for contractual and legal obligations related to termination activities
• an after-tax unrealized foreign exchange loss of $55 million on the peso-denominated intercompany loan between TCPL and
TGNH
• a $25 million after-tax loss on the expected credit loss provision related to the TGNH net investment in leases and certain
contract assets in Mexico
• an after-tax charge of $23 million due to Liquids Pipelines business separation costs related to the spinoff Transaction
• a $9 million after-tax expense related to Focus Project costs
• carrying charges of $4 million after tax as a result of a charge related to the FERC Administrative Law Judge initial decision on
Keystone issued in February 2023 in respect of a tolling-related complaint pertaining to amounts recognized from 2018 to
2022
• preservation and other costs for Keystone XL pipeline project assets of $4 million after tax, which could not be accrued as part
of the Keystone XL asset impairment charge.
TC Energy Management's discussion and analysis 2023 | 125
Fourth quarter 2022 results included:
• an after-tax impairment charge of $2.6 billion related to our equity investment in Coastal GasLink LP
• a $64 million after-tax expected credit loss provision related to the TGNH net investment in leases and certain contract assets
in Mexico
• $20 million after-tax charge due to the CER decision on Keystone issued in December 2022 in respect of a tolling-related
complaint pertaining to amounts reflected in 2021 and 2020
• preservation and other costs for Keystone XL pipeline project assets of $8 million after tax, which could not be accrued as part
of the Keystone XL asset impairment charge
• a $5 million after-tax net expense related to the 2021 Keystone XL asset impairment charge and other due to U.S. minimum
tax, partially offset by the gain on the sale of Keystone XL project assets and adjustments to the estimate for contractual and
legal obligations related to termination activities
• a $1 million income tax expense for the settlement related to prior years' income tax assessments in Mexico.
Net income in each period included unrealized gains and losses on our proportionate share of Bruce Power's fair value
adjustment on funds invested for post-retirement benefits and derivatives related to its risk management activities, as well as
unrealized gains and losses from changes in our risk management activities, all of which we exclude along with the above noted
items, to arrive at comparable earnings. A reconciliation of Net income (loss) attributable to common shares to comparable
earnings is shown in the following table.
126 | TC Energy Management's discussion and analysis 2023
Reconciliation of net income (loss) attributable to common shares to comparable earnings
three months ended December 31
(millions of $, except per share amounts)
Net income (loss) attributable to common shares
Specific items (net of tax):
Coastal GasLink impairment charge
Keystone XL asset impairment charge and other
Foreign exchange (gains) losses, net – intercompany loan
Expected credit loss provision on net investment in leases
and certain contract assets in Mexico
Liquids Pipelines business separation costs
Focus Project costs
Keystone regulatory decisions
Keystone XL preservation and other
Milepost 14 insurance expense
Settlement of Mexico prior years' income tax assessments
Bruce Power unrealized fair value adjustments
Risk management activities1
Comparable earnings
Net income (loss) per common share
Specific items (net of tax):
Coastal GasLink impairment charge
Keystone XL asset impairment charge and other
Foreign exchange (gains) losses, net – intercompany loan
Expected credit loss provision on net investment in leases
and certain contract assets in Mexico
Liquids Pipelines business separation costs
Focus Project costs
Keystone regulatory decisions
Keystone XL preservation and other
Milepost 14 insurance expense
Settlement of Mexico prior years' income tax assessments
Bruce Power unrealized fair value adjustments
Risk management activities
Comparable earnings per common share
1 three months ended December 31
(millions of $)
U.S. Natural Gas Pipelines
Liquids Pipelines
Canadian Power
U.S. Power
Natural Gas Storage
Foreign exchange
Income tax attributable to risk management activities
Total unrealized gains (losses) from risk
management activities
2023
1,463
(74)
(18)
55
25
23
9
4
4
—
—
(5)
(83)
1,403
$1.41
(0.07)
(0.02)
0.05
0.03
0.02
0.01
—
—
—
—
—
(0.08)
$1.35
2022
(1,447)
2,643
5
—
64
—
—
20
8
—
1
(9)
(156)
1,129
($1.42)
2.60
—
—
0.06
—
—
0.02
0.01
—
—
(0.01)
(0.15)
$1.11
2023
2022
(29)
20
(6)
4
18
104
(28)
(28)
(38)
30
5
67
172
(52)
83
156
TC Energy Management's discussion and analysis 2023 | 127
Comparable EBITDA to comparable earnings
Comparable EBITDA represents segmented earnings (losses) adjusted for the specific items described above and excludes
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 Energy Solutions
Corporate
Comparable EBITDA
Depreciation and amortization
Interest expense included in comparable earnings
Allowance for funds used during construction
Foreign exchange gains (losses), net included in comparable earnings
Interest income and other included in comparable earnings
Income tax (expense) recovery included in comparable earnings
Net (income) loss attributable to non-controlling interests
Preferred share dividends
Comparable earnings
Comparable earnings per common share
2023
2022
1,034
1,225
208
379
266
(5)
3,107
(717)
(840)
132
40
121
(288)
(128)
(24)
1,403
$1.35
768
1,141
211
364
203
(4)
2,683
(670)
(722)
115
(40)
53
(259)
(9)
(22)
1,129
$1.11
Comparable EBITDA – 2023 versus 2022
Comparable EBITDA increased by $424 million for the three months ended December 31, 2023 compared to the same period in
2022 primarily due to the net effect of the following:
• increased EBITDA in Canadian Natural Gas Pipelines mainly as a result of higher contributions from Coastal GasLink related to
the recognition of a $200 million incentive payment upon meeting certain milestones and higher flow-through costs and
increased rate-base earnings on the NGTL System
• increased Power and Energy Solutions EBITDA attributable to higher realized Alberta natural gas storage spreads, higher
contributions from Bruce Power and increased Canadian Power financial results due to higher contributions from marketing
activities
• increased U.S. dollar-denominated EBITDA from U.S. Natural Gas Pipelines as a result of incremental earnings from growth and
modernization projects placed in service and higher net earnings from additional contract sales, along with certain fourth
quarter 2022 adjustments, partially offset by higher operational costs reflective of increased utilization and lower commodity
prices related to our mineral rights business
• increased EBITDA from Liquids Pipelines primarily due to higher volumes on the Keystone Pipeline System, partially offset by
the negative impact of the CER decision issued in December 2022 in respect of a tolling-related complaint pertaining to
amounts invoiced in 2022
• decreased U.S. dollar-denominated EBITDA from Mexico Natural Gas Pipelines attributable to lower earnings from Guadalajara
due to lower fixed revenue and higher operating costs due to a weather event, partially offset by earnings from the lateral
section of the Villa de Reyes pipeline which was placed in commercial service in third quarter 2023.
Due to the flow-through treatment of certain costs including income taxes, financial charges and depreciation in our Canadian
rate-regulated pipelines, changes in these costs impact our comparable EBITDA despite having no significant effect on net
income.
128 | TC Energy Management's discussion and analysis 2023
Comparable earnings – 2023 versus 2022
Comparable earnings increased by $274 million or $0.24 per common share for the three months ended December 31, 2023
compared to the same period in 2022 and was primarily the net effect of:
• changes in comparable EBITDA described above
• higher interest expense primarily due to long-term debt issuances, net of maturities, the foreign exchange impact on
translation of increased U.S. dollar-denominated interest expense, partially offset by higher capitalized interest and reduced
levels of short-term borrowings
• higher depreciation and amortization on the NGTL System from expansion facilities that were placed in service
• higher AFUDC primarily due to capital expenditures on the Southeast Gateway pipeline project, partially offset by the impact
of NGTL System expansion projects that were placed in service and the suspension of AFUDC on the Tula pipeline project,
effective November 1, 2023, due to the delay of an FID
• increased income tax expense due to the impact of higher comparable earnings subject to income tax and Mexico foreign
exchange exposure, partially offset by lower flow-through income taxes, higher foreign income tax rate differentials and lower
Mexico inflation adjustments
• impact of derivatives used to manage our net exposure to foreign exchange rate fluctuation on U.S. dollar-denominated
income and our foreign exchange exposure to net liabilities in Mexico
• higher interest income and other due to higher interest earned on short-term investments and the change in fair value of
other restricted investments
• higher net income attributable to non-controlling interests primarily due to the net effect of the sale of a 40 per cent
non-controlling equity interest in Columbia Gas and Columbia Gulf and the acquisition of the Texas Wind Farms.
Comparable earnings per common share for the three months ended December 31, 2023 reflect the dilutive effect of common
shares issued in 2023 and 2022.
TC Energy Management's discussion and analysis 2023 | 129
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. The net impact of the U.S. dollar movements on comparable
earnings during the three months ended December 31, 2023, 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. Natural Gas
Pipelines 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
three months ended December 31
(millions of US$)
Comparable EBITDA
U.S. Natural Gas Pipelines
Mexico Natural Gas Pipelines
Liquids Pipelines
Depreciation and amortization
Interest expense on long-term debt and junior subordinated notes
Allowance for funds used during construction
Non-controlling interests and other
Average exchange rate - U.S. to Canadian dollars
2023
2022
900
153
204
842
156
204
1,257
1,202
(241)
(473)
81
(92)
532
1.36
(237)
(323)
55
(44)
653
1.36
Foreign exchange related to Mexico Natural Gas Pipelines
Changes in the value of the Mexican peso against the U.S. dollar can affect our comparable earnings as a portion of our Mexico
Natural Gas Pipelines monetary assets and liabilities are peso-denominated, while our financial results are denominated in
U.S. dollars for our Mexico operations. These peso-denominated balances are revalued to U.S. dollars, creating foreign exchange
gains and losses that are included in Income (loss) from equity investments and Foreign exchange (gains) losses, net in the
Consolidated statement of income.
In addition, foreign exchange gains or losses calculated for Mexico income tax purposes on the revaluation of
U.S. dollar‑denominated monetary assets and liabilities result in a peso-denominated income tax exposure for these entities,
leading to fluctuations in Income from equity investments and Income tax expense. This exposure increases as our
U.S. dollar‑denominated net monetary liabilities grow. On January 17, 2023, a wholly-owned Mexican subsidiary entered into a
US$1.8 billion senior unsecured term loan and a US$500 million senior unsecured revolving credit facility with a third party, which
resulted in an additional peso-denominated income tax expense compared to 2022.
The above exposures are managed using foreign exchange derivatives, although some unhedged exposure remains. The impacts
of the foreign exchange derivatives are recorded in Foreign exchange (gains) losses, net in the Consolidated statement of
income. Refer to the Financial risks and financial instruments section for additional information.
130 | TC Energy Management's discussion and analysis 2023
The period end exchange rates for one U.S. dollar to Mexican pesos were as follows:
December 31, 2023
December 31, 2022
December 31, 2021
16.91
19.50
20.48
A summary of the impacts of transactional foreign exchange gains and losses from changes in the value of the Mexican peso
against the U.S. dollar and associated derivatives is set out in the table below:
three months ended December 31
(millions of $)
Comparable EBITDA - Mexico Natural Gas Pipelines1
Foreign exchange gains (losses), net included in comparable earnings
Income tax (expense) recovery included in comparable earnings
2023
2022
(16)
64
(38)
10
(15)
34
(9)
10
1
Includes the foreign exchange impacts from the Sur de Texas joint venture recorded in Income (loss) from equity investments in the Consolidated statement of
income.
Highlights by business segment
Canadian Natural Gas Pipelines
For the three months ended December 31, 2023, Canadian Natural Gas Pipelines segmented earnings were $0.7 billion compared
to segmented losses of $2.6 billion for the same period in 2022. Segmented losses included a pre-tax impairment charge of
$3.0 billion, for the three months ended December 31, 2022, related to our equity investment in Coastal GasLink LP, which has
been excluded from our calculation of comparable EBITDA and comparable EBIT. Refer to Note 8, Coastal GasLink, of our 2023
Consolidated financial statements for additional information.
Net income for the NGTL System increased by $13 million for the three months ended December 31, 2023 compared to the same
period in 2022 mainly due to a higher average investment base resulting from continued system expansions. The NGTL System is
operating under the 2020-2024 Revenue Requirement Settlement, which includes an approved 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 for the three months ended December 31, 2023 was consistent with the same period in
2022. 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.
Comparable EBITDA for Canadian Natural Gas Pipelines increased by $266 million for the three months ended December 31, 2023
compared to the same period in 2022 due to the net effect of:
• earnings from Coastal GasLink related to the recognition of a $200 million incentive payment upon meeting certain
milestones. Refer to the Canadian Natural Gas Pipelines – Significant events section for additional information
• higher flow-through financial charges, depreciation and income taxes, as well as higher rate-base earnings on the NGTL
System.
Depreciation and amortization increased by $30 million for the three months ended December 31, 2023 compared to the same
period in 2022 reflecting incremental depreciation on the NGTL System from expansion facilities that were placed in service and
on the Canadian Mainline due to assets placed in service on a section with higher depreciation rates per the terms of the
2021-2026 Mainline Settlement.
TC Energy Management's discussion and analysis 2023 | 131
U.S. Natural Gas Pipelines
U.S. Natural Gas Pipelines segmented earnings increased by $73 million for the three months ended December 31, 2023
compared to the same period in 2022 and included unrealized gains and losses from changes in the fair value of derivatives
related to our U.S. natural gas marketing business, which has been excluded from our calculation of comparable EBITDA and
comparable EBIT.
Higher U.S. dollar-denominated segmented earnings for the three months ended December 31, 2023 had a positive impact on
the Canadian dollar equivalent segmented earnings from our U.S. operations compared to the same period in 2022.
Comparable EBITDA for U.S. Natural Gas Pipelines increased by US$58 million for the three months ended December 31, 2023
compared to the same period in 2022 and was primarily due to the net effect of:
• incremental earnings from growth and modernization projects placed in service
• a net increase in earnings from additional contract sales on Columbia Gas, ANR and Great Lakes along with certain fourth
quarter 2022 adjustments related to ANR regulatory deferrals
• increased equity earnings from Iroquois
• reduced earnings from our mineral rights business due to lower commodity prices
• decreased earnings due to higher operational costs, reflective of increased system utilization across our footprint, as well as
higher property taxes related to projects in service.
Depreciation and amortization increased by US$5 million for the three months ended December 31, 2023 compared to the same
period in 2022 due to new projects placed in service.
Mexico Natural Gas Pipelines
Mexico Natural Gas Pipelines segmented earnings increased by $54 million for the three months ended December 31, 2023
compared to the same period in 2022 and included a loss of $36 million (2022 – loss of $92 million) on the expected credit loss
provision related to the TGNH net investment in leases and certain contract assets in Mexico, which has been excluded from our
calculation of comparable EBITDA and comparable EBIT. Refer to Note 29, Risk management and financial instruments, of our
2023 Consolidated financial statements for additional information.
Comparable EBITDA for Mexico Natural Gas Pipelines decreased by US$3 million for the three months ended December 31, 2023
compared to the same period in 2022 due to the net effect of:
• lower earnings from Guadalajara primarily due to lower fixed revenue in accordance with the current transportation contract
and higher operating costs associated with a disruption of service due to a weather event
• higher earnings in TGNH primarily related to the lateral section of the Villa de Reyes pipeline which was placed in commercial
service in third quarter 2023.
Depreciation and amortization was consistent for the three months ended December 31, 2023 compared to the same period in
2022.
Liquids Pipelines
Liquids Pipelines segmented earnings decreased by $13 million for the three months ended December 31, 2023 compared to the
same period in 2022 and included the following specific items, which have been excluded from our calculation of comparable
EBITDA and comparable EBIT:
• pre-tax preservation and other costs for Keystone XL pipeline project assets of $5 million for the three months ended
December 31, 2023 (2022 – $10 million), which could not be accrued as part of the Keystone XL asset impairment charge
• a pre-tax charge of $3 million incurred in fourth quarter 2023 due to Liquids Pipelines business separation costs related to the
spinoff Transaction
• a $4 million pre-tax adjustment for the three months ended December 31, 2023 (2022 – $118 million) to the 2021 Keystone XL
asset impairment charge and other resulting from the net effect of the gain on sale of Keystone XL project assets and
adjustments to the estimate for contractual and legal obligations related to termination activities
• a $27 million pre-tax charge due to the CER decision issued in December 2022 in respect of a tolling-related complaint
pertaining to amounts reflected in 2021 and 2022
• unrealized gains and losses from changes in the fair value of derivatives related to our liquids marketing business.
132 | TC Energy Management's discussion and analysis 2023
Comparable EBITDA for Liquids Pipelines increased by $15 million for the three months ended December 31, 2023 compared to
the same period in 2022 primarily due to the net effect of:
• higher contracted volumes on the U.S. Gulf Coast section of the Keystone Pipeline System
• higher uncontracted volumes on the Keystone Pipeline System
• the negative impact of the CER decision issued in December 2022 in respect of a tolling-related complaint pertaining to
amounts invoiced in 2022.
Depreciation and amortization was consistent for the three months ended December 31, 2023 compared with the same period in
2022.
Power and Energy Solutions
Power and Energy Solutions segmented earnings decreased by $35 million for the three months ended December 31, 2023
compared to the same period in 2022 and included the following specific items, which have been excluded from our calculations
of comparable EBITDA and comparable EBIT:
• our proportionate share of Bruce Power's unrealized gains and losses on funds invested for post-retirement benefits and risk
management activities
• unrealized gains and losses from changes in the fair value of derivatives used to reduce commodity exposures.
Comparable EBITDA for Power and Energy Solutions increased by $63 million for the three months ended December 31, 2023
compared to the same period in 2022 primarily due to the net effect of:
• increased Natural Gas Storage and other results from higher realized Alberta natural gas storage spreads
• higher contributions from Bruce Power primarily due to realized gains on funds invested for post-retirement benefits, an
increased contract price and lower operating expenses, partially offset by lower generation
• increased Canadian Power financial results due to higher net contributions from marketing activities, partially offset by lower
realized power prices.
Depreciation and amortization increased by $7 million for the three months ended December 31, 2023 compared to the same
period in 2022 primarily due to the acquisition of the Texas Wind Farms in the first half of 2023.
Corporate
Corporate segmented losses increased by $38 million for the three months ended December 31, 2023 compared to the same
period in 2022 and included the following specific items, which have been excluded from our calculation of comparable EBITDA
and comparable EBIT:
• a pre-tax charge of $22 million incurred in fourth quarter 2023 due to Liquids Pipelines business separation costs related to the
spinoff Transaction
• a pre-tax charge of $15 million for the three months ended December 31, 2023 related to Focus Project costs.
Comparable EBITDA and EBIT for Corporate remained consistent for the three months ended December 31, 2023 compared to the
same period in 2022.
TC Energy Management's discussion and analysis 2023 | 133
Accounting terms
AFUDC
U.S.GAAP / GAAP
RRA
ROE
Allowance for funds used during
construction
U.S. generally accepted accounting
principles
Rate-regulated accounting
Return on common equity
Government and regulatory bodies terms
AER
CER
CFE
CRE
ECCC
FERC
IESO
NYSE
OBPS
OPG
PHMSA
SEC
TCFD
TSX
Alberta Energy Regulator
Canada Energy Regulator
Comisión Federal de Electricidad
(Mexico)
Comisión Reguladora de Energía, 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
Ontario Power Generation
Pipeline and Hazardous Materials Safety
Administration
U.S. Securities and Exchange
Commission
Task Force on Climate-Related Financial
Disclosures
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
bitumen
CEO
CFO
cogeneration facilities
diluent
DRP
Empress
FID
force majeure
GHG
HCAs
HSSE
investment base
LDC
LNG
OM&A
PPA
rate base
RNG
TSA
TOMS
WCSB
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
A major delivery/receipt point for natural
gas near the Alberta/Saskatchewan
border
Final investment decision
Unforeseeable circumstances that
prevent a party to a contract from
fulfilling it
Greenhouse gas
High-consequence areas
Health, safety, sustainability and
environment
Includes rate base, as well as assets
under construction
Local distribution company
Liquefied natural gas
Operating, maintenance and
administration
Power purchase arrangement
Average assets in service, working
capital and deferred amounts used in
setting of regulated rates
Renewable natural gas
Transportation Service Agreement
TC Energy's Operational Management
System
Western Canadian Sedimentary basin
134 | TC Energy Management's discussion and analysis 2023
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 2023 to that in 2022, and highlights significant changes between 2022 and 2021. 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, 2023, 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 consolidated 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 four 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 15, 2024
Joel E. Hunter
Executive Vice-President and
Chief Financial Officer
TC Energy Consolidated Financial Statements 2023 | 135
Report of Independent Registered Public Accounting Firm
To the Shareholders and Board of Directors
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, 2023 and 2022, 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, 2023, 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, 2023 and 2022, and the results of its operations and its cash flows for each of the
years in the three‑year period ended December 31, 2023, 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, 2023, 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 15, 2024 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 judgments. 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.
Valuation of the equity investment in Coastal GasLink LP
As discussed in Notes 2 and 8 to the consolidated financial statements, the Company reviews equity method investments for
impairment when an event or change in circumstances has a significant adverse effect on the investment’s fair value. Where the
Company concludes an investment’s fair value is below its carrying value, the Company then determines whether the
impairment is other-than-temporary, and if so, an impairment loss is recognized for the excess of the carrying value over the
estimated fair value of the investment, not exceeding the carrying value of the investment.
136 | TC Energy Consolidated Financial Statements 2023
With the expectation that additional equity contributions under the subordinated loan agreement between the Company and
Coastal GasLink LP will be predominantly funded by TC Energy as a limited partner of Coastal GasLink LP, the Company completed
valuation assessments during the first three quarters of 2023 and concluded that the fair value of its investment in Coastal
GasLink LP was below its carrying value and that these were other-than-temporary impairments. As a result, a pre-tax
impairment charge of $2,100 million was recognized during the nine months ended September 30, 2023. Fair value was
estimated using a 40-year discounted cash flow model and incorporated assumptions related to capital cost estimates, discount
rates, and long-term financing plans (collectively, the “key assumptions”).
We identified the valuation of the equity investment in Coastal GasLink LP at September 30, 2023 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 investment. In addition, the audit effort
associated with this estimate 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 critical audit matter. This included controls related to the
Company’s determination of the fair value of the investment and its evaluation of the key assumptions. We recalculated the
capital cost estimates by comparing the project budget to the actual costs incurred to September 30, 2023. We also compared
the amounts in the project budget to project status and milestone reporting provided to the partners of Coastal GasLink LP. We
compared assumptions used in the long-term financing plans to publicly available data for comparable financing transactions
and financing reports provided to the partners of Coastal GasLink LP. In addition, we involved a valuation professional with
specialized skills and knowledge, who assisted in:
• evaluating the methodology used by management in the valuation by comparing it to methodologies used to value other
development stage entities; and
• evaluating the discount rates used by management in the valuation by comparing them to discount rate ranges that were
independently developed using publicly available market data for comparable entities.
Valuation of goodwill for the Columbia reporting unit
As discussed in Notes 2 and 15 to the consolidated financial statements, the goodwill balance as of December 31, 2023 for the
Columbia reporting unit was $9,708 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.
In respect of the Columbia reporting unit, the Company performed a quantitative goodwill impairment test on June 30, 2023
(the “June 30, 2023 impairment test”) in conjunction with the process leading up to the sale of a 40 per cent equity interest in
Columbia Gas Transmission, LLC (Columbia Gas) and Columbia Gulf Transmission, LLC (Columbia Gulf) (the “Transaction”). 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 (collectively, the “key assumptions”). It was determined that the fair value of the Columbia reporting unit, inclusive of the
Columbia Gas and Columbia Gulf business units, exceeded its carrying value, including goodwill, as of June 30, 2023. Although
goodwill was not impaired, the estimated fair value in excess of the carrying value was less than 10 per cent.
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.
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 its evaluation of the key assumptions. We
compared the Company’s historical revenue and capital expenditure projections used in the prior quantitative goodwill
impairment test to 2023 actual results to assess the Company’s ability to accurately forecast. We evaluated the Company’s
revenue and capital expenditure projections in the June 30, 2023 impairment test by comparing them to 2023 actual results and
to assumptions used in industry publications related to North American and global energy consumption and production
forecasts. We also inspected the executed agreements associated with the Transaction to assess whether the closing terms and
TC Energy Consolidated Financial Statements 2023 | 137
economic value of the Transaction were consistent with the key assumptions and the fair value determined from the discounted
cash flow model. 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.
Qualitative goodwill impairment indicators for the Columbia and ANR reporting units
As discussed in Notes 2 and 15 to the consolidated financial statements, the goodwill balance as of December 31, 2023 for the
Columbia Pipeline Group, Inc. (Columbia) and the American Natural Resources (ANR) reporting units was $9,708 million and
$2,570 million, respectively. 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 performed qualitative assessments to determine whether events or changes in circumstances indicate that the
Columbia and ANR reporting units’ goodwill might be impaired. These qualitative assessments were performed as of
December 31, 2023.
We identified the evaluation of qualitative goodwill impairment indicators, or qualitative factors, for the Columbia and ANR
reporting units 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 the 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 the quantitative goodwill
impairment tests performed in a previous period. In addition, we involved a valuation professional with specialized skills and
knowledge, who assisted in:
• evaluating the Company’s determination of the 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.
Chartered Professional Accountants
We have served as the Company's auditor since 1956.
Calgary, Canada
February 15, 2024
138 | TC Energy Consolidated Financial Statements 2023
Report of Independent Registered Public Accounting Firm
To the Shareholders and Board of Directors
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, 2023,
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, 2023, 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, 2023 and 2022, 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, 2023, and the related notes (collectively, the consolidated financial statements), and our report dated
February 15, 2024 expressed an unqualified opinion on those consolidated financial statements.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report
on Internal Control over Financial Reporting 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 15, 2024
TC Energy Consolidated Financial Statements 2023 | 139
Consolidated statement of income
year ended December 31
(millions of Canadian $, except per share amounts)
2023
2022
2021
Revenues (Note 6)
Canadian Natural Gas Pipelines
U.S. Natural Gas Pipelines
Mexico Natural Gas Pipelines
Liquids Pipelines
Power and Energy Solutions
Income (Loss) from Equity Investments (Note 12)
Impairment of Equity Investment (Notes 8 and 12)
Operating and Other Expenses
Plant operating costs and other
Commodity purchases resold
Property taxes
Depreciation and amortization
Goodwill and asset impairment charges and other (Notes 7 and 15)
Net Gain (Loss) on Sale of Assets
Financial Charges
Interest expense (Note 21)
Allowance for funds used during construction
Foreign exchange (gains) losses, net (Note 23)
Interest income and other
Income (Loss) before Income Taxes
Income Tax Expense (Recovery) (Note 20)
Current
Deferred
Net Income (Loss)
Net income (loss) attributable to non-controlling interests (Note 24)
Net Income (Loss) Attributable to Controlling Interests
Preferred share dividends
Net Income (Loss) Attributable to Common Shares
Net Income (Loss) per Common Share (Note 25)
Basic
Diluted
5,173
6,229
846
2,667
1,019
15,934
1,377
(2,100)
4,887
517
897
2,778
(4)
9,075
—
3,263
(575)
(320)
(242)
2,126
4,010
931
11
942
3,068
146
2,922
93
2,829
$2.75
$2.75
4,764
5,933
688
2,668
924
14,977
1,054
(3,048)
4,932
534
848
2,584
453
9,351
—
2,588
(369)
185
(146)
2,258
1,374
415
174
589
785
37
748
107
641
$0.64
$0.64
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)
(10)
(190)
1,893
2,166
305
(185)
120
2,046
91
1,955
140
1,815
$1.87
$1.86
Dividends Declared per Common Share
$3.72
$3.60
$3.48
Weighted Average Number of Common Shares (millions) (Note 25)
Basic
Diluted
1,030
1,030
995
996
973
974
The accompanying Notes to the consolidated financial statements are an integral part of these statements.
140 | TC Energy Consolidated Financial Statements 2023
Consolidated statement of comprehensive income
year ended December 31
(millions of Canadian $)
Net Income (Loss)
2023
3,068
2022
785
Other Comprehensive Income (Loss), Net of Income Taxes
Foreign currency translation gains and losses on net investment in foreign operations
(1,141)
1,494
Change in fair value of net investment hedges
Change in fair value of cash flow hedges
Reclassification to net income of (gains) losses on cash flow hedges
Unrealized actuarial gains (losses) on pension and other post-retirement benefit
plans
Reclassification to net income of actuarial (gains) losses on pension and
other post-retirement benefit plans
Other comprehensive income (loss) on equity investments
Other comprehensive income (loss) (Note 27)
Comprehensive Income (Loss)
Comprehensive income (loss) attributable to non-controlling interests
Comprehensive Income (Loss) Attributable to Controlling Interests
Preferred share dividends
Comprehensive Income (Loss) Attributable to Common Shares
17
—
74
(11)
—
(211)
(1,272)
1,796
(220)
2,016
93
1,923
(36)
(39)
42
63
6
867
2,397
3,182
45
3,137
107
3,030
The accompanying Notes to the consolidated financial statements are an integral part of these statements.
2021
2,046
(108)
(2)
(10)
55
158
14
535
642
2,688
81
2,607
140
2,467
TC Energy Consolidated Financial Statements 2023 | 141
Consolidated statement of cash flows
year ended December 31
(millions of Canadian $)
Cash Generated from Operations
Net income (loss)
Depreciation and amortization
Goodwill and asset impairment charges and other (Notes 7 and 15)
Deferred income taxes (Note 20)
(Income) loss from equity investments (Note 12)
Impairment of equity investment (Notes 8 and 12)
Distributions received from operating activities of equity investments (Note 12)
Employee post-retirement benefits funding, net of expense (Note 28)
Net (gain) loss on sale of assets
Equity allowance for funds used during construction
Unrealized (gains) losses on financial instruments (Note 29)
Expected credit loss provision (Note 29)
Foreign exchange losses on loan receivable from affiliate (Note 13)
Other
(Increase) decrease in operating working capital (Note 30)
Net cash provided by operations
Investing Activities
Capital expenditures (Note 5)
Capital projects in development (Note 5)
Contributions to equity investments (Notes 5, 8 and 12)
Acquisitions, net of cash acquired (Note 31)
Loans to affiliate (issued) repaid, net (Notes 8 and 13)
Keystone XL contractual recoveries (Note 7)
Proceeds from sales of assets, net of transaction costs
Other distributions from equity investments (Note 12)
Deferred amounts and other
Net cash (used in) provided by investing activities
Financing Activities
Notes payable issued (repaid), net
Long-term debt issued, net of issue costs
Long-term debt repaid
Disposition of equity interest, net of transaction costs (Notes 24 and 31)
Junior subordinated notes issued, net of issue costs
Redeemable non-controlling interest repurchased (Note 7)
Dividends on common shares
Dividends on preferred shares
Distributions to non-controlling interests
Distributions on Class C Interests (Note 7)
Common shares issued, net of issue costs
Preferred shares redeemed (Note 26)
Gains (losses) on settlement of financial instruments
Acquisition of TC PipeLines, LP transaction costs (Note 24)
Net cash (used in) provided by financing activities
Effect of Foreign Exchange Rate Changes on Cash and Cash Equivalents
Increase (Decrease) in Cash and Cash Equivalents
Cash and Cash Equivalents
Beginning of year
Cash and Cash Equivalents
End of year
2023
2022
2021
3,068
2,778
(4)
11
(1,377)
2,100
1,254
(17)
—
(367)
(342)
(83)
—
40
207
7,268
(8,007)
(142)
(4,149)
(307)
250
10
33
23
2
(12,287)
(6,299)
15,884
(3,772)
5,328
—
—
(2,787)
(92)
(124)
(49)
4
—
—
—
8,093
(16)
3,058
620
3,678
785
2,584
453
174
(1,054)
3,048
1,025
(29)
—
(248)
135
163
28
(50)
(639)
6,375
(6,678)
(49)
(3,433)
—
(11)
571
—
2,632
(41)
(7,009)
766
2,508
(1,338)
—
1,008
—
(3,192)
(106)
(44)
(43)
1,905
(1,000)
23
—
487
94
(53)
673
620
2,046
2,522
2,775
(185)
(898)
—
975
(5)
(30)
(191)
194
—
41
(67)
(287)
6,890
(5,924)
—
(1,210)
—
(239)
—
35
73
(447)
(7,712)
1,003
10,730
(7,758)
—
495
(633)
(3,317)
(141)
(74)
(16)
148
(500)
(10)
(15)
(88)
53
(857)
1,530
673
The accompanying Notes to the consolidated financial statements are an integral part of these statements.
142 | TC Energy Consolidated Financial Statements 2023
Consolidated balance sheet
at December 31
(millions of Canadian $)
ASSETS
Current Assets
Cash and cash equivalents
Accounts receivable
Inventories
Other current assets (Note 9)
Plant, Property and Equipment (Note 10)
Net Investment in Leases (Note 11)
Equity Investments (Note 12)
Restricted Investments
Regulatory Assets (Note 14)
Goodwill (Note 15)
Other Long-Term Assets (Note 16)
LIABILITIES
Current Liabilities
Notes payable (Note 17)
Accounts payable and other (Note 18)
Dividends payable
Accrued interest
Current portion of long-term debt (Note 21)
Regulatory Liabilities (Note 14)
Other Long-Term Liabilities (Note 19)
Deferred Income Tax Liabilities (Note 20)
Long-Term Debt (Note 21)
Junior Subordinated Notes (Note 22)
EQUITY
Common shares, no par value (Note 25)
Issued and outstanding:
December 31, 2023 – 1,037 million shares
December 31, 2022 – 1,018 million shares
Preferred shares (Note 26)
Additional paid-in capital
Retained earnings (Accumulated deficit)
Accumulated other comprehensive income (loss) (Note 27)
Controlling Interests
Non-controlling interests (Note 24)
2023
2022
3,678
4,209
982
2,503
11,372
80,569
2,263
10,314
2,636
2,330
12,532
3,018
125,034
—
6,987
979
913
2,938
11,817
4,806
1,015
8,125
49,976
10,287
86,026
620
3,624
936
2,152
7,332
75,940
1,895
9,535
2,108
1,910
12,843
2,785
114,348
6,262
7,149
930
668
1,898
16,907
4,520
1,017
7,648
39,645
10,495
80,232
30,002
28,995
2,499
—
(2,997)
49
29,553
9,455
39,008
125,034
2,499
722
819
955
33,990
126
34,116
114,348
Commitments, Contingencies and Guarantees (Note 32)
Variable Interest Entities (Note 33)
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 2023 | 143
Consolidated statement of equity
year ended December 31
(millions of Canadian $)
Common Shares (Note 25)
Balance at beginning of year
Shares issued:
Dividend reinvestment and share purchase plan
Exercise of stock options
Under public offering, net of issue costs
Acquisition of TC PipeLines, LP, net of transaction costs (Note 24)
Balance at end of year
Preferred Shares (Note 26)
Balance at beginning of year
Redemption of shares
Balance at end of year
Additional Paid-In Capital
Balance at beginning of year
Issuance of stock options, net of exercises
Disposition of equity interest, net of transaction costs (Note 24)
Reclassification of additional paid-in capital deficit to retained earnings (accumulated deficit)
Keystone XL project-level credit facility retirement and issuance of Class C Interests (Note 7)
Acquisition of TC PipeLines, LP (Note 24)
Repurchase of redeemable non-controlling interest (Note 7)
Balance at end of year
Retained Earnings (Accumulated Deficit)
Balance at beginning of year
Net income (loss) attributable to controlling interests
Common share dividends
Preferred share dividends
Reclassification of additional paid-in capital deficit to retained earnings (accumulated deficit)
Redemption of preferred shares
Balance at end of year
Accumulated Other Comprehensive Income (Loss) (Note 27)
Balance at beginning of year
Other comprehensive income (loss) attributable to controlling interests
Impact of non-controlling interest (Note 24)
Acquisition of TC PipeLines, LP (Note 24)
Balance at end of year
Equity Attributable to Controlling Interests
Equity Attributable to Non-Controlling Interests
Balance at beginning of year
Disposition of equity interest (Note 24)
Non-controlling interests on acquisition of Texas Wind Farms (Note 24)
Net income (loss) attributable to non-controlling interests
Other comprehensive income (loss) attributable to non-controlling interests
Distributions declared to non-controlling interests
Acquisition of TC PipeLines, LP (Note 24)
Balance at end of year
Total Equity
2023
2022
2021
28,995
26,716
24,488
1,003
4
—
—
30,002
2,499
—
2,499
722
9
(3,537)
2,806
—
—
—
—
819
2,922
(3,839)
(93)
(2,806)
—
(2,997)
955
(379)
(527)
—
49
342
183
1,754
—
28,995
3,487
(988)
2,499
729
(7)
—
—
—
—
—
722
3,773
748
(3,595)
(95)
—
(12)
819
(1,434)
2,389
—
—
955
29,553
33,990
126
9,451
222
146
(366)
(124)
—
9,455
39,008
125
—
—
37
8
(44)
—
126
34,116
—
165
—
2,063
26,716
3,980
(493)
3,487
2
(6)
—
—
737
(398)
394
729
5,367
1,955
(3,409)
(133)
—
(7)
3,773
(2,439)
652
—
353
(1,434)
33,271
1,682
—
—
90
(10)
(74)
(1,563)
125
33,396
The accompanying Notes to the consolidated financial statements are an integral part of these statements.
144 | TC Energy Consolidated Financial Statements 2023
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 Energy Solutions. 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 40,596 km (25,226 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 50,088 km (31,123 miles) of regulated
natural gas pipelines, 532 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 2,895 km (1,798 miles) of
regulated natural gas pipelines currently in operation.
Liquids Pipelines
The Liquids Pipelines segment primarily consists of the Company's investments in 4,865 km (3,024 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 Energy Solutions
The Power and Energy Solutions segment primarily consists of the Company's investments in approximately 4,600 MW of power
generation facilities and 118 Bcf of non-regulated natural gas storage facilities. These assets are located in Alberta, Ontario,
Québec, New Brunswick and Texas. In addition, TC Energy has physical and virtual power purchase agreements (PPAs) in Canada
and the U.S. to buy and/or sell power from wind and solar facilities. These PPAs have the potential to be leases, derivatives or
revenue arrangements depending on the contractual terms of the agreement.
TC Energy Consolidated Financial Statements 2023 | 145
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. 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 TC Energy’s equity investment in Coastal GasLink LP (Note 8)
• assessment of goodwill impairment indicators and fair value of reporting units that contain goodwill (Note 15)
• estimates and judgments used in measuring the fair value of Columbia Gas Transmission, LLC (Columbia Gas) and Columbia
Gulf Transmission, LLC (Columbia Gulf) (Note 15).
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 and Class C Interests (Note 7)
• recoverability and depreciation rates of plant, property and equipment (Note 10)
• allocation of consideration to lease and non-lease components in a contract that contains a lease (Note 11)
• assumptions used to measure the carrying amount of and expected credit losses on net investment in leases and certain
contract assets (Notes 11 and 29)
• fair value of equity investments not otherwise noted above (Note 12)
• carrying value of regulatory assets and liabilities (Note 14)
• assumptions used to measure the environmental remediation liability from the Keystone pipeline rupture (Note 18)
• recognition of asset retirement obligations (Note 19)
• provisions for income taxes, including valuation allowances and releases as well as tax positions that may be reviewed as part
of an audit by tax authorities (Note 20)
• assumptions used to measure retirement and other post-retirement benefit obligations (Note 28)
• fair value of financial instruments (Note 29)
• fair value of Fluvanna Wind Farm and Blue Cloud Wind Farm (Texas Wind Farms) assets (Note 31)
• commitments and provisions for contingencies and guarantees (Note 32).
TC Energy continues to assess the impact of climate change on the consolidated financial statements. There are ongoing
developments in the ESG frameworks and regulatory initiatives that could further impact accounting estimates and judgments
including, but not limited to, assessment of asset useful lives, goodwill valuation, impairment of plant, property and equipment,
accrued environmental costs and asset retirement obligations. The impact of these changes is 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.
146 | TC Energy Consolidated Financial Statements 2023
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), the Alberta Energy Regulator or the B.C. Oil and Gas Commission. In the U.S., regulated
interstate natural gas pipelines and liquids pipelines as well as 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
• 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.
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.
Revenues from non-lease components associated with a lease arrangement are recognized systematically over the term of the
contract.
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.
TC Energy Consolidated Financial Statements 2023 | 147
Other
The Company is contracted to provide pipeline construction services to a partially-owned entity for a development fee. The
development fee is considered variable consideration due to refund provisions in the contract. The Company recognizes its
estimate of the most likely amount of the variable consideration to which it will be entitled. The development fee is recognized
over time as the services are provided based on the input method using an estimate of activity level.
U.S. Natural Gas Pipelines
Capacity Arrangements and Transportation
Revenues from the Company's U.S. natural gas pipelines are generated from contractual arrangements for committed capacity
and from the transportation of natural gas. Revenues earned from firm contracted capacity arrangements are generally
recognized ratably over the term of the contract regardless of the amount of natural gas that is transported. Transportation
revenues for interruptible or volumetric-based services are recognized when the service is performed.
The Company's U.S. natural gas pipelines are subject to FERC regulations and, as a result, a portion of revenues collected may be
subject to refund if invoiced during an interim period when a rate proceeding is ongoing. Allowances for these potential refunds
are recognized using management's best estimate based on the facts and circumstances of the proceeding. Any allowances that
are recognized during the proceeding process are refunded or retained at the time a regulatory decision becomes final.
U.S. natural gas pipelines' revenues are invoiced and received on a monthly basis. The Company does not take ownership of the
natural gas that it transports for customers.
Natural Gas Storage and Other
Revenues from the Company's regulated U.S. natural gas storage services are generated mainly from firm committed capacity
storage contracts. The performance obligation in these contracts is the reservation of a specified amount of capacity for storage
including specifications with 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.
Mexico Natural Gas Pipelines
Capacity Arrangements and Transportation
Revenues from certain of 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 generates revenues from operating and maintenance services provided on certain leased pipelines. Revenues
earned from these services are recognized ratably over the term of the contract.
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.
148 | TC Energy Consolidated Financial Statements 2023
Power and Energy Solutions
Power
Revenues from the Company's Power and Energy Solutions business are primarily derived from long-term contractual
commitments to provide power capacity to meet the demands of the market and from the sale of electricity to both centralized
markets and to customers. Power generation revenues also include revenues from the sale of steam to customers. Revenues and
capacity payments are recognized as the services are provided and as electricity and steam is delivered. Power generation
revenues are invoiced and received on a monthly basis.
Natural Gas Storage and Other
Non-regulated natural gas storage contracts include park, loan and term storage arrangements. Revenues are recognized as the
services are provided. Term storage revenues are invoiced and received on a monthly basis. Revenues 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, proprietary
natural gas inventory in storage and emissions allowances and credits not held for compliance. The Company purchases certain
emissions allowances and credits as part of bundled arrangements that also include the purchase of electricity for a fixed price.
The cost allocated to emissions allowances and credits under such arrangements is based on observable market prices.
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
0.75 per cent to 6.67 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.
TC Energy Consolidated Financial Statements 2023 | 149
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.
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 Energy Solutions
Plant, property and equipment for Power and Energy Solutions 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 construction stage is probable or costs are otherwise
likely to be recoverable. The Company 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
The Company determines if a contract contains a lease at inception of a contract by using judgment in assessing the following
aspects: 1) the contract specifies an identified asset which is physically distinct or, if not physically distinct, represents
substantially all of the capacity of the asset; 2) the contract provides the customer with the right to obtain substantially all of
the economic benefits from the use of the asset and 3) the customer has the right to direct how and for what purpose the
identified asset is used throughout the period of the contract.
If the contract is determined to contain a lease, further judgment is required to identify separate lease components of the
arrangement by assessing whether the lessee can benefit from the right of use either on its own or together with other resources
that are readily available to the lessee, as well as if the right of use is neither highly dependent on, nor highly interrelated, with
the other rights to use the underlying assets in the contract.
The Company considers non-lease components as distinct elements of a contract that are not related to the use of the leased
asset. A good or service that is provided to a customer is distinct if: 1) the customer can benefit from the good or service either
on its own or together with other resources that are readily available to the customer and 2) the entity’s promise to transfer the
good or service to the customer is separately identifiable from other promises in the contract. The Company applies the practical
expedient to not separate lease and non-lease components for all lessee contracts and facilities and liquids tank terminals for
which the Company is the lessor in an operating lease.
150 | TC Energy Consolidated Financial Statements 2023
Lessee Accounting Policy
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 expedient to not recognize ROU assets or lease liabilities for leases that qualify for the
short-term lease recognition exemption.
Lessor Accounting Policy
The Company provides transportation and other services on certain assets to customers according to long-term service
agreements through sales-type and operating leases.
In a sales-type lease, the Company measures the total consideration within the contract at lease commencement. When a lease
arrangement contains more than one lease and/or non-lease component, a portion of the contract consideration is allocated to
each component based on the stand-alone selling price for each distinct service. The Company applies judgment to determine
reasonable estimates of the expected future cost of satisfying the performance obligations of each service. The payments
associated with lease components are apportioned between a reduction in the lease receivable and sales-type lease income.
At lease commencement, the Company recognizes a net investment in lease represented by the present value of both the future
lease payments and the estimated residual value of the leased asset. The plant, property and equipment of the leased asset is
derecognized, with related gains/losses, if any, recognized in the Consolidated statement of income. Sales-type lease income is
determined using the rate implicit in the lease and is recorded in Revenues.
The Company is the lessor within certain other contracts, including PPAs, that are accounted for as operating leases. In an
operating lease, the leased asset remains capitalized in Plant, property and equipment on the Consolidated balance sheet and is
depreciated over its useful life, while lease payments are recognized as revenue over the term of the lease on a straight-line
basis. Variable lease payments are recognized as income in the period in which they occur.
Impairment of Long-Lived Assets
The Company reviews long-lived assets such as plant, property and equipment 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.
Impairment of Equity Method Investments
The Company reviews equity method investments for impairment when an event or change in circumstances has a significant
adverse effect on the investment's fair value. Where the Company concludes an investment's fair value is below its carrying
value, the Company then determines whether the impairment is other-than-temporary, and if so, an impairment loss is
recognized for the excess of the carrying value over the estimated fair value of the investment, not exceeding the carrying value
of the investment.
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.
TC Energy Consolidated Financial Statements 2023 | 151
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. The Company has elected to allocate goodwill impairment charges first to goodwill that
is non-deductible for income tax purposes, with any remaining charge allocated to tax-deductible goodwill.
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.
Non-Controlling Interests
Non-controlling interests (NCI) represent third-party ownership interests in certain consolidated subsidiaries of the Company.
Partial dispositions which result in a change in the Company's ownership interest, but do not result in a change in control, of a
subsidiary that constitutes a business are accounted for as equity transactions. No gain or loss is recognized in earnings. At the
time of partial disposition, NCI is recorded as the third-party's ownership interest in the Company's carrying value of the net
assets of the subsidiary. Any difference between the amount by which the NCI is adjusted and the fair value of the consideration
paid or received is recognized in additional-paid-in capital and/or retained earnings (accumulated deficit).
Loans and Receivables
Loans receivable from affiliates and accounts receivable are measured at amortized cost.
Impairment of Financial Assets
The Company reviews financial assets, inclusive of net investment in leases and certain contract 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. An expected credit loss (ECL) is calculated using a model and methodology based on assumptions and judgment
considering historical data, current counterparty information as well as reasonable and supportable forecasts of future economic
conditions.
The ECL is recognized in Plant operating costs and other in the Consolidated statement of income, and is presented on the
Consolidated balance sheet as a reduction to the carrying value of the related financial asset.
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.
152 | TC Energy Consolidated Financial Statements 2023
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.
Any interest and/or penalty incurred related to tax is reflected in income tax expense.
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 and Emission Allowances and Credits
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. TC Energy evaluates recoveries from insurers and other third parties separately from
the liability and, when recovery is probable, it records an asset separately from the associated liability. These recoveries are
presented, along with environmental remediation costs, on a net basis in Plant operating costs and other in the Consolidated
statement of income. Variations in one or more of the categories described above could result in additional costs such as fines,
penalties and/or expenditures associated with litigation and settlement of claims with respect to environmental liabilities.
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 within the Power and Energy Solutions segment in the Consolidated statement of income. The Company
records allowances and credits held for compliance in Other current assets and Other long-term assets on the Consolidated
balance sheet. Allowances and credits not held for compliance are classified as Inventories on the Consolidated balance sheet.
TC Energy Consolidated Financial Statements 2023 | 153
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 (OPEB 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 OPEB Plans 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.
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 rate of exchange in effect at the balance sheet date while revenues, expenses, gains
and losses are translated at the exchange rate prevailing at the date 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.
154 | TC Energy Consolidated Financial Statements 2023
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 as well as 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 in the Consolidated statement
of cash flows.
In hedging the foreign currency exposure of a net investment in a foreign operation, the foreign exchange gains and losses on
the hedging instruments are recognized in OCI. The amounts recognized previously in AOCI are reclassified to net income in the
event the Company reduces its net investment in a foreign operation.
In some cases, derivatives do not meet the specific criteria for hedge accounting treatment. In these instances, the changes in
fair value are recorded in net income in the period of change.
Gains and losses arising from changes in the fair value of derivatives accounted for as part of RRA, including those that qualify for
hedge accounting treatment, are refunded or recovered through the tolls charged by the Company. As a result, these gains and
losses are deferred as regulatory assets or liabilities and are refunded to or collected from ratepayers in subsequent periods when
the derivative settles.
Derivatives embedded in other financial instruments or contracts (host instrument) are recorded as separate derivatives.
Embedded derivatives are measured at fair value if their economic characteristics are not clearly and closely related to those of
the host instrument, their terms are the same as those of a stand-alone derivative and the total contract is not held for trading or
accounted for at fair value. When changes in the fair value of embedded derivatives are measured separately, they are included
in net income.
Long-Term Debt Transaction Costs and Issuance Costs
The Company records long-term debt transaction costs and issuance costs as a deduction from the carrying amount of the
related debt liability and amortizes these costs using the effective interest method except those related to the Canadian natural
gas regulated pipelines, which continue to be amortized on a straight-line basis in accordance with the provisions of regulatory
tolling mechanisms.
Guarantees
Upon issuance, the Company records the fair value of certain guarantees entered into by the Company on behalf of a
partially-owned entity or by partially-owned entities for which contingent payments may be made. The fair value of these
guarantees is estimated by discounting the cash flows that would be incurred by the Company if letters of credit were used in
place of the guarantees as appropriate in the circumstances. Guarantees are recorded as an increase to Equity investments or
Plant, property and equipment and a corresponding liability is recorded in Other long-term liabilities. The release from the
obligation is recognized either over the term of the guarantee or upon expiration or settlement of the guarantee.
TC Energy Consolidated Financial Statements 2023 | 155
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. The assessment of whether an
entity is a VIE and, if so, whether the Company is the primary beneficiary, is completed at the inception of the entity or at a
reconsideration event.
Consolidated VIEs
The Company's consolidated VIEs consist of legal entities where the Company has a variable interest and for which it is
considered 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.
Non-Consolidated VIEs
The Company’s non-consolidated VIEs consist of legal entities where the Company has a variable interest but is not the primary
beneficiary as it does not have the power (either explicit or implicit), through voting or similar rights, 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. Non-consolidated VIEs are accounted for as equity investments.
The Company’s maximum exposure to loss is the maximum loss that could potentially be recorded through net income in future
periods as a result of the Company’s variable interest in a VIE.
156 | TC Energy Consolidated Financial Statements 2023
3. ACCOUNTING CHANGES
Future Accounting Changes
Income Taxes
In December 2023, the FASB issued new guidance to enhance the transparency and decision usefulness of income tax disclosures
through improvements to the rate reconciliation and income taxes paid information. The guidance also includes certain other
amendments to improve the effectiveness of income tax disclosures. This new guidance is effective for the annual period
beginning January 1, 2025. The guidance is applied prospectively with retrospective application permitted. Early adoption is
permitted for annual financial statements not yet issued. The Company does not expect this guidance to have a material impact
on the Company's consolidated financial statements.
Segment Reporting
In November 2023, the FASB issued new guidance to improve disclosures about a public entity's reportable segments and
address requests from investors for additional, more detailed information about a reportable segment's expenses. The guidance
is effective for annual periods beginning January 1, 2024 and interim periods beginning January 1, 2025. Early adoption is
permitted and the guidance is applied retrospectively. The Company is currently assessing the impact of the standard on the
Company's consolidated financial statements.
Leases
In March 2023, the FASB issued new guidance that clarified the accounting for leasehold improvements associated with common
control leases. The guidance requires all lessees to amortize leasehold improvements associated with common control leases
over their useful life to the common control group and account for them as a transfer of assets between entities under common
control at the end of the lease. Additional disclosures are required when the useful life of leasehold improvements to the
common control group exceeds the related lease term. This new guidance is effective January 1, 2024 and can be applied either
prospectively or retrospectively, with early application permitted. The Company will adopt the guidance on a prospective basis
starting January 1, 2024, and it is not expected to have a material impact on the Company's consolidated financial statements.
4. SPINOFF OF LIQUIDS PIPELINES BUSINESS
On July 27, 2023, TC Energy announced plans to separate into two independent, investment-grade, publicly listed companies
through the proposed spinoff of its Liquids Pipelines business (the spinoff Transaction) and on November 8, 2023 the Company
communicated that the name of the new Liquids Pipelines business would be South Bow Corporation (South Bow). In addition to
TC Energy shareholder and court approvals, the spinoff Transaction is subject to receipt of favourable tax rulings from Canadian
and U.S. tax authorities, receipt of necessary regulatory approvals, and satisfaction of other customary closing conditions.
TC Energy expects that the spinoff Transaction will be completed in the second half of 2024.
Under the spinoff Transaction, TC Energy shareholders will retain their current ownership in TC Energy’s common shares and
receive a pro-rata allocation of common shares in South Bow. The determination of the number of common shares in South Bow
to be distributed to TC Energy shareholders will be determined prior to the closing of the spinoff Transaction. The spinoff
Transaction is expected to be tax free to TC Energy’s Canadian and U.S. shareholders.
For the year ended December 31, 2023, the Company incurred pre-tax Liquids Pipelines business separation costs of $40 million
($34 million after tax) with respect to the spinoff Transaction, which included internal costs related to separation activities,
legal, tax, audit and other consulting fees recorded in Plant operating costs and other in the Consolidated statement of income.
TC Energy Consolidated Financial Statements 2023 | 157
Canadian
Natural
Gas
Pipelines
U.S.
Natural
Gas
Pipelines
Mexico
Natural
Gas
Pipelines
Liquids
Pipelines
Power
and
Energy
Solutions
Corporate
1
Total
5. SEGMENTED INFORMATION
year ended December 31, 2023
(millions of Canadian $)
Revenues
Intersegment revenues
Income (loss) from equity investments
Impairment of equity investment
5,173
6,229
—
101
5,173
6,330
220
(2,100)
324
—
846
—
846
78
—
Plant operating costs and other
(1,756)
(1,660)
(39)
Commodity purchases resold
Property taxes
Depreciation and amortization
Goodwill and asset impairment charges and other
—
(302)
(1,325)
—
(56)
(473)
(934)
—
Segmented Earnings (Losses)
(90)
3,531
—
—
(89)
—
796
Interest expense
Allowance for funds used during construction
Foreign exchange gains (losses), net
Interest income and other
Income (Loss) before Income Taxes
Income tax (expense) recovery
Net Income (Loss)
Net (income) loss attributable to non-controlling interests
Net Income (Loss) Attributable to Controlling Interests
Preferred share dividends
Net Income (Loss) Attributable to Common Shares
Capital Spending3
Capital expenditures
Capital projects in development
Contributions to equity investments
2,953
2,536
2,292
—
3,231
6,184
—
124
—
—
2,660
2,292
49
—
—
49
2,667
1,019
—
22
—
(123) 2
15,934
—
2,667
1,041
(123)
15,934
67
—
(836)
(437)
(116)
(338)
4
688
—
(603)
(24)
(6)
(92)
—
—
1,377
—
7 2
(2,100)
(4,887)
—
—
—
—
(517)
(897)
(2,778)
4
1,011
1,004
(116)
6,136
(3,263)
575
320
242
4,010
(942)
3,068
(146)
2,922
(93)
2,829
8,007
142
4,149
144
142
794
33
—
—
1,080
33
12,298
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.
Included in Investing activities in the Consolidated statement of cash flows.
158 | TC Energy Consolidated Financial Statements 2023
year ended December 31, 2022
(millions of Canadian $)
Revenues
Intersegment revenues
Income (loss) from equity investments
Impairment of Equity Investment
Canadian
Natural
Gas
Pipelines
U.S.
Natural
Gas
Pipelines
Mexico
Natural
Gas
Pipelines
Liquids
Pipelines
Power
and
Energy
Solutions
Corporate
1
Total
4,764
5,933
—
132
4,764
6,065
18
(3,048)
292
—
688
—
688
122
—
2,668
—
2,668
55
—
(756)
(512)
(121)
(329)
118
1,123
924
12
936
539
—
(544)
(22)
(4)
(72)
—
833
—
(144) 2
14,977
—
(144)
14,977
28 3
1,054
—
124 2
(3,048)
(4,932)
—
—
—
—
8
Plant operating costs and other
(1,679)
(1,856)
(221)
Commodity purchases resold
Property taxes
Depreciation and amortization
Goodwill and asset impairment charges and other
—
(297)
(1,198)
—
—
(426)
(887)
(571)
Segmented Earnings (Losses)
(1,440)
2,617
—
—
(98)
—
491
Interest expense
Allowance for funds used during construction
Foreign exchange gains (losses), net3
Interest income and other
Income (Loss) before Income Taxes
Income tax (expense) recovery
Net Income (Loss)
Net (income) loss attributable to non-controlling interests
Net Income (Loss) Attributable to Controlling Interests
Preferred share dividends
Net Income (Loss) Attributable to Common Shares
Capital Spending4
Capital expenditures
Capital projects in development
Contributions to equity investments5
3,274
2,137
1,027
—
1,445
4,719
—
—
—
—
2,137
1,027
106
—
37
143
93
49
752
894
41
—
—
41
(534)
(848)
(2,584)
(453)
3,632
(2,588)
369
(185)
146
1,374
(589)
785
(37)
748
(107)
641
6,678
49
2,234
8,961
1
2
3
4
5
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 Foreign exchange gains (losses), net by the corresponding foreign exchange losses and gains on the affiliate
receivable balance until March 15, 2022, when it was fully repaid upon maturity. Refer to Note 13, Loans receivable from affiliates, for additional information.
Included in Investing activities in the Consolidated statement of cash flows.
Contributions to equity investments in the Corporate segment of $1.2 billion are offset by the equivalent amount in Other distributions from equity
investments, although they are reported on a gross basis in the Company’s Consolidated statement of cash flows. Refer to Note 13, Loans receivable from
affiliates, for additional information.
TC Energy Consolidated Financial Statements 2023 | 159
year ended December 31, 2021
(millions of Canadian $)
Revenues
Intersegment revenues
Income (loss) from equity investments
Plant operating costs and other
Commodity purchases resold
Property taxes
Depreciation and amortization
Goodwill and asset impairment charges and other
Net gain (loss) on sale of assets
Canadian
Natural
Gas
Pipelines
U.S.
Natural
Gas
Pipelines
Mexico
Natural
Gas
Pipelines
Liquids
Pipelines
Power
and
Energy
Solutions
Corporate
1
Total
4,519
5,233
—
145
4,519
5,378
12
244
(1,567)
(1,393)
—
(289)
(1,226)
—
—
—
(367)
(791)
—
—
605
—
605
119
(55)
(3)
—
(109)
—
—
2,306
—
2,306
71
(700)
(84)
(113)
(318)
(2,775)
13
724
14
738
411
(455)
—
(5)
(78)
—
17
—
(159) 2
13,387
—
(159)
13,387
41 3
72 2
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
Foreign exchange gains (losses), net3
Interest income and other
Income (Loss) before Income Taxes
Income tax (expense) recovery
Net Income (Loss)
Net (income) loss attributable to non-controlling interests
Net Income (Loss) Attributable to Controlling Interests
Preferred share dividends
Net Income (Loss) Attributable to Common Shares
Capital Spending4
Capital expenditures
Contributions to equity investments
2,629
2,611
108
209
2,737
2,820
129
—
129
488
83
571
32
810
842
35
—
35
(2,360)
267
10
190
2,166
(120)
2,046
(91)
1,955
(140)
1,815
5,924
1,210
7,134
1
2
3
4
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 Foreign exchange gains (losses), net by the corresponding foreign exchange losses and gains on the affiliate
receivable balance. Refer to Note 13, Loans receivable from affiliates, for additional information.
Included in Investing activities in the Consolidated statement of cash flows.
160 | TC Energy Consolidated Financial Statements 2023
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 Energy Solutions
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
2023
2022
29,782
50,499
12,003
15,490
9,525
7,735
27,456
50,038
9,231
15,587
8,272
3,764
125,034
114,348
2023
2022
2021
5,360
1,403
8,325
846
4,942
1,322
8,025
688
4,603
1,226
6,953
605
15,934
14,977
13,387
2023
2022
28,583
44,609
7,377
80,569
27,232
43,505
5,203
75,940
TC Energy Consolidated Financial Statements 2023 | 161
6. REVENUES
Disaggregation of Revenues
year ended December 31, 2023
(millions of Canadian $)
Revenues from contracts with customers
Canadian
Natural
Gas
Pipelines
U.S.
Natural
Gas
Pipelines
Mexico
Natural
Gas
Pipelines
Power
and
Energy
Solutions
Liquids
Pipelines
Total
Capacity arrangements and transportation
5,141
5,107
Power generation
Natural gas storage and other1,2
Sales-type lease income3
Other revenues4
—
32
—
874
5,173
5,981
—
—
—
248
5,173
6,229
442
—
125
567
279
—
846
2,115
—
12,805
—
3
2,118
—
549
427
363
790
—
229
427
1,397
14,629
279
1,026
2,667
1,019
15,934
1
2
3
4
Includes $31 million of fee revenues from an affiliate related to the development and construction of the Coastal GasLink pipeline project which is 35 per cent
owned by TC Energy.
Includes $97 million of revenues generated from non-lease components for the provision of operating and maintenance services with respect to sales-type
leases on the in-service TGNH pipelines. Refer to Note 11, Leases, for additional information.
Represents the sales-type lease income on the in-service TGNH pipelines. Refer to Note 11, Leases, for additional information.
Other revenues include income from the Company's operating lease arrangements, marketing activities and financial instruments. Refer to Note 11, Leases, and
Note 29, Risk management and financial instruments, for additional information.
year ended December 31, 2022
(millions of Canadian $)
Revenues from contracts with customers
Canadian
Natural
Gas
Pipelines
U.S.
Natural
Gas
Pipelines
Mexico
Natural
Gas
Pipelines
Power
and
Energy
Solutions
Liquids
Pipelines
Total
Capacity arrangements and transportation
4,696
4,621
507
1,983
—
11,807
Power generation
Natural gas storage and other1,2
Sales-type lease income3
Other revenues4,5
—
68
4,764
—
—
—
1,298
5,919
—
14
4,764
5,933
—
54
561
127
—
688
—
4
1,987
—
681
490
391
881
—
43
490
1,815
14,112
127
738
2,668
924
14,977
1
2
3
4
5
Includes $68 million of fee revenues from an affiliate related to the development and construction of the Coastal GasLink pipeline project which is 35 per cent
owned by TC Energy.
Includes $37 million of revenues generated from non-lease components for the provision of operating and maintenance services with respect to sales-type
leases on the in-service TGNH pipelines. Refer to Note 11, Leases, for additional information.
Represents the sales-type lease income on the in-service TGNH pipelines. Refer to Note 11, Leases, for additional information.
Other revenues include income from the Company's operating lease arrangements, marketing activities and financial instruments. Refer to Note 11, Leases, and
Note 29, Risk management and financial instruments, for additional information.
Other revenues from U.S. Natural Gas Pipelines include the amortization of the net regulatory liabilities resulting from H.R.1, the Tax Cuts and Jobs Act
(U.S. Tax Reform). Refer to Note 14, Rate-regulated businesses, for additional information.
162 | TC Energy Consolidated Financial Statements 2023
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
Energy
Solutions
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 the development and construction of the Coastal GasLink pipeline project which is 35 per cent
owned by TC Energy.
Other revenues include income from the Company's operating lease arrangements, marketing activities and financial instruments. Refer to Note 11, Leases, and
Note 29, Risk management and financial instruments, for additional information.
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 14, Rate-regulated businesses, for additional information.
Contract Balances
at December 31
(millions of Canadian $)
Receivables from contracts with customers
Contract assets (Note 9)
Long-term contract assets (Note 16)
Contract liabilities1 (Note 18)
Long-term contract liabilities1 (Note 19)
2023
1,832
151
457
69
12
2022
Affected line item on the
Consolidated balance sheet
1,907
Accounts receivable
155
355
62
32
Other current assets
Other long-term assets
Accounts payable and other
Other long-term liabilities
1
During the year ended December 31, 2023, $64 million (2022 – $51 million) of revenues were recognized that were included in contract liabilities and
long-term 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 represent unearned revenue for contracted services. Under the terms of the consolidated Transportation Service
Agreement (TSA), the contract liability relating to current and future in-service TGNH pipelines is netted against certain contract
asset balances. The resulting net contract liability is settled against net investment in leases on the Consolidated balance sheet
when the pipeline enters into service.
TC Energy Consolidated Financial Statements 2023 | 163
Future Revenues from Remaining Performance Obligations
As at December 31, 2023, future revenues from long-term pipeline capacity arrangements and transportation as well as natural
gas storage and other contracts extending through 2055 are approximately $22.9 billion, of which approximately $4.9 billion is
expected to be recognized in 2024.
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. Future revenues exclude lease income from the Company's Mexico natural gas pipelines
on projects that have not been placed into service.
7. KEYSTONE XL
Asset Impairment Charge and Other
Following the revocation of the Presidential Permit for the Keystone XL pipeline project on January 20, 2021, the Company
terminated the Keystone XL pipeline project and evaluated the Keystone XL investment for impairment in 2021. 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.
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 activities
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
The estimated fair value of $175 million at December 31, 2021 related to plant and equipment was based on the price that was
expected to be received from selling these assets in their current condition and is updated as required. The initial 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.
164 | TC Energy Consolidated Financial Statements 2023
In 2023, the Company received $10 million (2022 – $571 million) towards its contractual recoveries, resulting in a remaining
balance of $117 million at December 31, 2023 (December 31, 2022 – $130 million).
In 2022, the Company revised its estimate of contractual and legal obligations related to termination activities based on a review
of costs and commitments incurred, which resulted in a $54 million reduction to the asset impairment charge. No revision to the
estimate was made in 2023. The Company paid $2 million in 2023 (2022 – $24 million; 2021 – $192 million) towards contractual
and legal obligations related to termination activities. At December 31, 2023, the remaining balance accrued was $45 million
(December 31, 2022 – $48 million).
In 2023, the Company sold plant and equipment with a carrying value of approximately $63 million (2022 – $25 million;
2021 – $16 million), resulting in a gain of $36 million (2022 – $64 million; 2021 – nil) recorded in Goodwill and asset impairment
charges and other in the Consolidated statement of income.
As part of the Keystone XL impairment charge and other, the Company recorded a $14 million income tax recovery in 2023
(2022 – $96 million expense) in relation to the termination of the Keystone XL pipeline project.
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.
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. On
January 8, 2021, the Company exercised its call right with the Government of Alberta 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.
This transaction was funded by draws on the project-level credit facility. 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). Following the
cancellation of the Keystone XL pipeline project, the Government of Alberta repaid the full outstanding balance in June 2021 in
accordance with the terms of the guarantee, and the credit facility was subsequently terminated. Additionally, 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. As part of this arrangement,
TC Energy issued $91 million of Class C Interests in the Keystone XL subsidiaries which entitled the Government of Alberta to
future liquidation proceeds from specified Keystone XL project assets. The entire $91 million was recorded (net of distributions)
in Accounts payable and other on the Consolidated balance sheet. During 2023, it was determined that the Company would
exceed the $91 million of Class C distributions and the Company increased the Class C Interests carrying value by $32 million with
a corresponding amount recorded in Goodwill and asset impairment charges and other in the Consolidated statement of income.
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 2021. For the year ended December 31, 2023, the Company made Class C
distributions to the Government of Alberta of $49 million (2022 – $43 million; 2021 – $16 million).
TC Energy Consolidated Financial Statements 2023 | 165
8. COASTAL GASLINK
Impairment of Equity Investment in Coastal GasLink LP
In July 2022, amended agreements were executed between Coastal GasLink LP, LNG Canada, TC Energy and its Coastal GasLink LP
partners (collectively, the July 2022 agreements). These amendments revised the commercial terms between LNG Canada and
Coastal GasLink LP, as well as funding provisions between the partners of Coastal GasLink LP.
With the expectation that additional equity contributions under a subordinated loan agreement between TC Energy and the
Coastal GasLink LP partners will be predominantly funded by TC Energy as limited partner of Coastal GasLink LP, in accordance
with the July 2022 agreements, the Company completed valuation assessments during the first three quarters of 2023 and
concluded that, for each period an assessment was performed, the fair value of its investment in Coastal GasLink LP was below
its carrying value and that these were other-than-temporary impairments. As a result, a pre-tax impairment charge of
$2,100 million ($1,943 million after tax) was recognized during the year ended December 31, 2023 in Impairment of equity
investment in the Consolidated statement of income in the Canadian Natural Gas Pipelines segment (2022 – $3,048 million;
$2,643 million after tax). The carrying value of the investment in Coastal GasLink LP was $294 million at December 31, 2023
(2022 – nil), which reflects the balance of amounts, net of impairments, drawn on the subordinated loan to date at
December 31, 2023 and other changes to TC Energy's equity investment. The impairment charge reflected the net impact of
$2,020 million drawn on and a $250 million repayment of the subordinated loan for the nine months ended September 30, 2023,
along with TC Energy’s proportionate share of unrealized gains and losses on interest rate derivatives in Coastal GasLink LP and
other changes to the equity investment. The cumulative pre-tax impairment charge recognized at December 31, 2023 is
$5,148 million ($4,586 million after tax).
A deferred income tax recovery was recognized on the pre-tax impairment charge, net of certain unrealized tax losses not
recognized. The impairment of the subordinated loan resulted in unrealized non-taxable capital losses that are not recognized.
Refer to Note 20, Income taxes, for additional information.
At December 31, 2023, TC Energy expects to fund an additional $0.9 billion related to the capital cost estimates to complete the
Coastal GasLink pipeline, which is consistent with the capital cost profile that was included in the September 30, 2023
impairment calculation. At December 31, 2023, there were no events or changes in circumstances since September 30, 2023
indicating a significant adverse impact on the estimated fair value of the Company’s investment in Coastal GasLink LP.
The fair value of TC Energy’s investment in Coastal GasLink LP at September 30, 2023 and December 31, 2022 was estimated
using a 40-year discounted cash flow model and is classified as a Level III fair value measurement.
The discounted cash flow is most sensitive to assumptions related to the capital cost estimates for the Coastal GasLink pipeline of
approximately $14.5 billion (2022 – $14.5 billion), discount rate and long-term financing plans.
Other assumptions included in the discounted cash flow model include contractually agreed upon terms and extension
provisions in the TSAs between Coastal GasLink LP and the LNG Canada participants, potential expansion projects and estimated
completion date.
Subordinated Loan Agreement
In 2021, TC Energy entered into a subordinated loan agreement with Coastal GasLink LP. This loan agreement was amended as
part of the July 2022 agreements, and subsequent draws on this loan by Coastal GasLink LP will be provided through an
interest-bearing loan, subject to a floating market-based interest rate to fund the capital cost to complete the Coastal GasLink
pipeline. Committed capacity under the subordinated loan agreement between TC Energy and Coastal GasLink LP was
$3.4 billion, with $2.5 billion drawn on the loan at December 31, 2023.
Any amounts outstanding on the loan will be repaid by Coastal GasLink LP to TC Energy once final project costs are known, which
will be determined after the pipeline is placed into service. Coastal GasLink LP partners, including TC Energy, will contribute
equity to Coastal GasLink LP to ultimately fund Coastal GasLink LP’s repayment of this subordinated loan to TC Energy. The
Company expects that these additional equity contributions will be predominantly funded by TC Energy. Amounts drawn on this
loan subsequent to amended agreements executed in July 2022 are accounted for as in-substance equity contributions and are
presented as Contributions to equity investments on the Company’s Consolidated statement of cash flows. Interest and principal
repayments on this loan, which are expected to be predominantly funded by TC Energy, will be accounted for as an equity
investment distribution to the Company once received.
166 | TC Energy Consolidated Financial Statements 2023
The table below reflects the changes in this loan receivable balance.
at December 31
(millions of Canadian $)
Outstanding balance at beginning of year
Issuances
Repayments
Outstanding balance at end of year
Impairment during the year
Carrying value at end of year
9. OTHER CURRENT ASSETS
at December 31
(millions of Canadian $)
Fair value of derivative contracts (Note 29)
Current portion of net investment in leases (Note 11)
Contract assets (Note 6)
Current portion of Keystone environmental provision recovery (Note 18)
Cash provided as collateral
Emissions credits
Prepaid expenses
Keystone XL contractual recoveries (Note 7)
Regulatory assets (Note 14)
Keystone XL assets held for sale
Other
2023
250
2,520
(250)
2,520
(2,020)
500
2023
1,285
306
151
150
120
94
92
83
76
58
88
2022
238
112
(100)
250
(250)
—
2022
614
291
155
410
106
36
118
86
67
122
147
2,503
2,152
TC Energy Consolidated Financial Statements 2023 | 167
10. PLANT, PROPERTY AND EQUIPMENT
at December 31
2023
2022
Cost
Accumulated
Depreciation
Net
Book Value
Cost
Accumulated
Depreciation
Net
Book Value
20,232
6,603
1,589
6,855
2,349
830
4,254
759
13,377
18,119
Under construction
787
—
787
29,211
10,034
19,177
28,424
10,034
18,390
6,265
1,518
25,902
1,552
27,454
10,472
4,328
692
15,492
269
15,761
1,984
455
2,439
45,654
6,285
2,224
769
9,278
—
9,278
7,852
3,247
285
11,384
—
11,384
1,624
—
1,624
22,286
11,834
4,041
749
16,624
1,552
18,176
2,620
1,081
407
4,108
269
4,377
360
455
815
23,368
10,729
4,437
729
7,996
3,354
308
15,895
11,658
147
—
16,042
11,658
1,682
—
1,682
23,374
2,733
1,083
421
4,237
147
4,384
1,164
23
1,187
24,748
(millions of Canadian $)
Canadian Natural Gas Pipelines
NGTL System
Pipeline
Compression
Metering and other
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
2,846
23
2,869
48,122
12,952
5,310
4,074
22,336
771
23,107
2,117
3,928
1,625
7,670
404
8,074
1,247
11,705
12,471
1,069
11,402
559
372
2,178
—
2,178
657
773
458
1,888
—
1,888
4,751
3,702
5,190
4,026
20,158
21,687
771
659
20,929
22,346
1,460
3,155
1,167
5,782
404
6,186
2,066
3,785
1,666
7,517
328
7,845
495
346
1,910
—
1,910
641
734
440
1,815
—
1,815
4,695
3,680
19,777
659
20,436
1,425
3,051
1,226
5,702
328
6,030
168 | TC Energy Consolidated Financial Statements 2023
at December 31
(millions of Canadian $)
Other U.S. Natural Gas Pipelines
Columbia Gulf
GTN
Great Lakes
Other2
Under construction
Mexico Natural Gas Pipelines3
Pipeline
Compression
Metering and other
Under construction
Liquids Pipelines
Keystone Pipeline System
Pipeline
Pumping equipment
Tanks and other
Under construction
Intra-Alberta Pipelines
Power and Energy Solutions
Natural Gas Power Generation
Natural Gas Storage and Other
Renewable Power Generation
Under construction
Corporate
2023
2022
Cost
Accumulated
Depreciation
Net
Book Value
Cost
Accumulated
Depreciation
Net
Book Value
3,600
2,992
2,359
2,071
11,022
584
11,606
42,787
2,280
370
482
3,132
4,823
7,955
9,569
1,096
3,658
14,323
54
14,377
203
14,580
1,239
845
581
2,665
153
2,818
909
256
1,295
1,401
800
3,752
—
3,752
7,818
387
79
123
589
—
589
2,212
312
913
3,437
—
3,437
25
3,462
637
256
19
912
—
912
447
3,344
1,697
958
1,271
7,270
584
7,854
34,969
3,511
2,964
2,367
1,928
10,770
328
11,098
41,289
1,893
2,299
291
359
2,543
4,823
7,366
7,357
784
2,745
374
487
3,160
2,547
5,707
9,777
1,064
3,723
10,886
14,564
54
96
10,940
14,660
178
199
11,118
14,859
602
589
562
1,753
153
1,906
462
1,260
820
—
2,080
80
2,160
900
224
1,239
1,387
760
3,610
—
3,610
7,335
348
59
113
520
—
520
2,056
288
859
3,203
—
3,203
19
3,222
642
238
—
880
—
880
386
3,287
1,725
980
1,168
7,160
328
7,488
33,954
1,951
315
374
2,640
2,547
5,187
7,721
776
2,864
11,361
96
11,457
180
11,637
618
582
—
1,200
80
1,280
514
117,171
36,602
80,569
110,569
34,629
75,940
1
2
3
Includes Foothills, Ventures LP and Great Lakes Canada.
Includes Portland, North Baja, Tuscarora, Crossroads and mineral rights business.
During the year ended December 31, 2023, the Company derecognized $407 million (2022 – $2,319 million) of Plant, property and equipment and recorded a
corresponding asset for net investment in leases for the in-service TGNH pipelines. Refer to Note 11, Leases, for additional information.
TC Energy Consolidated Financial Statements 2023 | 169
11. 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 or when
certain conditions are met. 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:
at December 31
(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
170 | TC Energy Consolidated Financial Statements 2023
2023
118
(4)
114
2023
72
84
2023
13 years
3.3%
2022
106
(5)
101
2022
67
49
2022
8 years
3.5%
2023
2022
72
68
66
59
58
225
548
(89)
459
68
65
62
60
54
187
496
(63)
433
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 19)
2023
58
401
459
2022
54
379
433
As at December 31, 2023, the carrying value of the ROU assets recorded under operating leases was $437 million
(2022 – $415 million) and is included in Plant, property and equipment on the Consolidated balance sheet.
As a Lessor
Operating Leases
The Grandview and Bécancour power plants in the Power and Energy Solutions 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 operating 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, 2023 was
$116 million (2022 – $118 million; 2021 – $126 million).
Future lease payments to be received under operating leases are as follows:
at December 31
(millions of Canadian $)
Less than one year
One to two years
Two to three years
Three to four years
2023
2022
113
94
70
—
277
113
111
94
70
388
The cost and accumulated depreciation for facilities accounted for as operating leases was $796 million and $370 million,
respectively, at December 31, 2023 (2022 – $802 million and $360 million, respectively).
Sales-Type Leases
On August 4, 2022, TC Energy announced a strategic alliance with Mexico’s state-owned electric utility, the Comisión Federal de
Electricidad (CFE), for the development of new natural gas infrastructure in central and southeast Mexico. This alliance
consolidates previous TSAs executed between TC Energy’s Mexico-based subsidiary TGNH and the CFE in connection with the
Company's natural gas pipeline assets in central Mexico (including the Tamazunchale, Villa de Reyes and Tula pipelines) under a
single, U.S. dollar-denominated take-or-pay TSA that extends through 2055.
The consolidated TSA contains a lease with multiple lease and non-lease components. The lease components represent the
capacity available to the CFE provided by the in-service pipelines which, at December 31, 2023, included the Tamazunchale
pipeline, the north and lateral sections of the Villa de Reyes pipeline and the east section of the Tula pipeline. The non-lease
components represent the Company’s services with respect to operation and maintenance of the TGNH pipelines in service.
The consolidated TSA provides the CFE with substantially all of the economic benefits from the use of each identified in-service
asset, therefore, the lease arrangements in the consolidated TSA are classified as sales-type leases.
TC Energy Consolidated Financial Statements 2023 | 171
The Company allocated a portion of the contract consideration to non-lease components for the provision of operating and
maintenance services based on the stand-alone selling price using an expected cost plus margin approach. The remaining
consideration was allocated to the lease components using the residual approach due to uncertainty surrounding the
stand-alone selling price.
During 2023, the Company recognized an additional $407 million in net investment in leases (2022 – $2,319 million) to reflect
sales type-leases placed into service. At the inception of the lease term, the Company applied judgment to determine that the
fair value of the underlying assets approximated the carrying value and residual value of the lease based on the rate-regulated
nature of the assets within the TGNH system.
The following table lists the components of the aggregate net investment in leases reflected on the Company's Consolidated
balance sheet:
at December 31
(millions of Canadian $)
Net Investment in Leases
Minimum lease payments
Unearned lease income
Lease receivable
Expected credit loss provision1
Present value of unguaranteed residual value
Current portion included in Other current assets (Note 9)
1
Includes nil (2022 – $1 million) of foreign currency translation losses.
Future lease payments to be received under the existing sales-type leases are as follows:
at December 31
(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
2023
2022
9,627
(7,006)
2,621
(76)
24
2,569
(306)
2,263
2023
305
305
305
305
305
8,102
9,627
9,457
(7,132)
2,325
(150)
11
2,186
(291)
1,895
2022
291
291
291
291
291
8,002
9,457
Future lease payments will increase as assets associated with sales-type leases come into service.
For the year ended December 31, 2023, the Company recorded $279 million (2022 – $127 million) of sales-type lease income in
Mexico Natural Gas Pipelines revenues.
For the year ended December 31, 2023, the Company recorded a $73 million ECL recovery (2022 – an expense of $149 million;
2021 – nil) in Plant operating costs and other relating to net investment in leases. Refer to Note 29, Risk management and
financial instruments, for additional information.
172 | TC Energy Consolidated Financial Statements 2023
12. EQUITY INVESTMENTS
(millions of Canadian $)
Canadian Natural Gas Pipelines
TQM1
Coastal GasLink1
U.S. Natural Gas Pipelines
Northern Border
Millennium
Iroquois
Other
Mexico Natural Gas Pipelines
Sur de Texas
Liquids Pipelines
Grand Rapids1
Port Neches Link LLC2,3
HoustonLink Pipeline1
Northern Courier1,4
Power and Energy Solutions
Bruce Power1
Other
Ownership
Interest at
December 31, 2023
Income (Loss) from Equity
Investments
Equity
Investments
year ended December 31
at December 31
2023
2022
2021
2023
2022
50.0%
35.0%
50.0%
47.5%
50.0%
Various
60.0%
50.0%
74.9%
50.0%
nil
48.3%
Various
17
203
101
109
98
16
78
53
13
1
—
17
1
92
103
77
20
150
54
—
1
—
690
(2)
1,377
537
2
1,054
12
—
80
91
55
18
166
294
599
476
227
120
165
—
516
500
237
122
160
1,078
1,050
54
—
1
16
411
—
898
932
124
18
—
6,242
38
10,314
964
149
19
—
5,783
30
9,535
1
2
3
4
Classified as a VIE. Refer to Note 33, Variable interest entities, for additional information.
Classified as a VIE in 2021.
In December 2023, TC Energy sold a 20.1 per cent equity interest in Port Neches Link LLC.
In November 2021, TC Energy sold its remaining 15 per cent equity interest in Northern Courier. Refer to Note 31, Acquisitions and dispositions, for additional
information.
Coastal GasLink Incentive Payment
The Coastal GasLink project reached mechanical completion in November 2023 and was ready to deliver commissioning gas to
the LNG Canada facility by the end of 2023. These milestones entitle Coastal GasLink LP to receive a $200 million incentive
payment from LNG Canada. In accordance with the contractual terms between the Coastal GasLink LP partners, the amount
accrues in full to TC Energy as the project developer and was settled through a cash distribution on February 12, 2024. The
Company recognized the incentive payment as Income (loss) from equity investments in the Consolidated statement of income
for the year ended December 31, 2023 and recorded a corresponding amount in Accounts receivable on the Consolidated
balance sheet.
Impairment of Equity Investment
In the fourth quarter of 2022, the Company announced that a material increase in the Coastal GasLink pipeline project costs was
expected. On February 1, 2023, Coastal GasLink LP announced an increase in the revised capital cost of the Coastal GasLink
pipeline project. The increase in project costs and the Company's corresponding funding requirements were indicators that a
decrease in the value of the Company's equity investment had occurred. As a result, the Company completed a valuation
assessment and concluded that the fair value of TC Energy's investment was below its carrying value at December 31, 2022.
The Company completed valuation assessments at each of the first three quarters of 2023 and concluded that an
other-than-temporary impairment of its investment had occurred. This resulted in a pre-tax impairment charge of $2,100 million
($1,943 million after tax) and $3,048 million ($2,643 million after tax) recorded in the year ended December 31, 2023 and 2022,
respectively. Refer to Note 8, Coastal GasLink, for additional information.
TC Energy Consolidated Financial Statements 2023 | 173
Distributions and Contributions
Distributions received from equity investments and contributions made to equity investments for the years ended
December 31, 2023, 2022 and 2021 were as follows:
year ended December 31
(millions of Canadian $)
Distributions
Distributions received from operating activities of equity investments
Sur de Texas debt repayments1,2
Other1
Contributions1
Contributions to Coastal GasLink
Sur de Texas debt financing2
Contributions made to other equity investments
2023
2022
2021
1,254
—
23
1,277
3,231
—
918
4,149
1,025
2,404
228
3,657
1,414
1,199
820
3,433
975
73
—
1,048
92
—
1,118
1,210
1
2
Included in Investing activities in the Consolidated statement of cash flows.
Represents TC Energy's proportionate share of the Sur de Texas debt financing requirements and subsequent repayments. Refer to Note 13, Loans receivable
from affiliates, for additional information.
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
2023
2022
2021
6,425
(3,450)
2,584
1,377
5,891
(3,390)
2,147
1,054
5,447
(3,293)
1,859
898
2023
2022
3,526
42,933
(2,431)
(21,895)
3,414
37,713
(2,856)
(17,690)
At December 31, 2023, the cumulative carrying value of the Company’s equity investments was $183 million
(2022 – $299 million) lower than the cumulative underlying equity in the net assets primarily due to the impairment of the
equity investment in Coastal GasLink LP, partially offset by fair value adjustments at the time of acquisition or partial disposition
as well as interest capitalized during construction. Refer to Note 8, Coastal GasLink, for additional information.
174 | TC Energy Consolidated Financial Statements 2023
13. LOANS RECEIVABLE FROM AFFILIATES
Related party transactions are conducted in the normal course of business and are measured at the exchange amount, which is
the amount of consideration established and agreed to by the related parties.
Coastal GasLink Pipeline Limited Partnership
TC Energy holds a 35 per cent equity interest in 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 has a capacity of
$100 million (2022 – $100 million) with no outstanding balance at December 31, 2023 and 2022. This revolver was not impacted
by the impairment charges recognized to date.
Subordinated Loan Agreement
In 2021, TC Energy entered into a subordinated loan agreement with Coastal GasLink LP, which was amended on July 28, 2022. At
December 31, 2023, the total capacity committed by TC Energy under this subordinated loan agreement was $3.4 billion
(2022 – $1.3 billion) with an outstanding balance of $2,520 million (2022 – $250 million). In the year ended December 31, 2023,
$2,020 million (2022 – $250 million) was impaired. Refer to Note 8, Coastal GasLink, for additional information.
Sur de Texas
TC Energy holds a 60 per cent equity interest in a joint venture with IEnova to own the Sur de Texas pipeline, for which TC Energy
is the operator. In 2017, TC Energy entered into a MXN$21.3 billion unsecured revolving credit facility with the joint venture,
which bore interest at a floating rate and was fully repaid upon maturity on March 15, 2022 in the amount of $1.2 billion.
The Company's Consolidated statement of income reflects the related interest income and foreign exchange impact on this loan
receivable until its repayment on March 15, 2022, 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 $)
2023
2022
2021
Affected line item in the
Consolidated statement of income
Interest income1
Interest expense2
Foreign exchange losses1
Foreign exchange gains1
—
—
—
—
19
(19)
(28)
28
87
Interest income and other
(87)
Income (loss) from equity investments
(41)
Foreign exchange (gains) losses, net
41
Income from equity investments
1
2
Included in the Corporate segment.
Included in the Mexico Natural Gas Pipelines segment.
On March 15, 2022, as part of refinancing activities with the Sur de Texas joint venture, the peso-denominated inter-affiliate loan
discussed above was replaced with a new U.S. dollar-denominated inter-affiliate loan of an equivalent $1.2 billion
(US$938 million) with a floating interest rate. On July 29, 2022, the Sur de Texas joint venture entered into an unsecured term
loan agreement with third parties, the proceeds of which were used to fully repay the U.S. dollar-denominated inter-affiliate
loan with TC Energy.
TC Energy Consolidated Financial Statements 2023 | 175
14. 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). The Impact Assessment Agency of Canada continues to assess designated projects.
The CER regulates the construction and operation of facilities and the terms and conditions of services, including rates, for the
Company's Canadian regulated natural gas transmission systems under federal jurisdiction.
TC Energy's Canadian natural gas transmission services are supplied under natural gas transportation tariffs that provide for cost
recovery, including return of and on capital as approved by the CER. 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 regulator generally allows 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 is operating under the 2020-2024 Revenue Requirement Settlement which includes an approved 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 its customers.
Canadian Mainline
The Canadian Mainline currently operates under the terms of the 2015-2030 Tolls Application approved in 2014
(the 2014 Decision). In April 2020, the CER approved the six-year unanimous negotiated settlement (2021-2026 Mainline
Settlement) effective January 1, 2021. Similar to the previous settlement, 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 customers and TC Energy.
Toll stabilization is achieved using deferral accounts, including the toll-stabilization account and the short-term adjustment
accounts (STAA), which capture the surplus or shortfall between system revenues and cost of service each year under the
2021-2026 Mainline Settlement. A portion of the STAA commenced amortization in 2023 according to the terms outlined in the
2021-2026 Mainline Settlement as predetermined thresholds per the settlement agreement were met. Similar to the STAA, the
long-term adjustment account (LTAA) and bridging account were used to capture the surplus or shortfall between the
Company's revenues and cost of service during the previous settlement and are amortized over the life of 2021-2026 Settlement
and the 2014 Decision respectively.
176 | TC Energy Consolidated Financial Statements 2023
U.S. Regulated Operations
TC Energy's U.S. regulated natural gas pipelines operate under the provisions of the Natural Gas Act of 1938 (NGA), 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, acquisition 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.
Columbia Gas
Columbia Gas' natural gas transportation and storage services are provided under a tariff at rates subject to FERC approval.
Columbia Gas reached a settlement with its customers effective February 2021 and received FERC approval in
February 2022. As part of the settlement, there is a moratorium on any further rate changes until April 1, 2025. Columbia Gas
must file for new rates with an effective date no later than April 1, 2026. Previously accrued rate refund liabilities were refunded
to customers, including interest, in second quarter 2022.
Additionally, Columbia Gas maintains a FERC-approved modernization program allowing for the cost recovery and return on
additional investment up to US$1.2 billion over a four-year period through 2024 to modernize the Columbia Gas system, thereby
improving system integrity and enhancing service reliability and flexibility.
ANR Pipeline
ANR Pipeline operated under rates established through a 2016 FERC-approved rate settlement until July 31, 2022. To meet terms
of the 2016 settlement, in January 2022, ANR Pipeline filed a Section 4 Rate Case with FERC requesting an increase to maximum
transportation rates. In December 2022 ANR Pipeline filed a Stipulation and Agreement of Settlement (2022 ANR Settlement)
with FERC. The 2022 ANR Settlement reflects the agreement of ANR Pipeline, its customers and FERC staff to resolve all
outstanding issues pertaining to the original rate case filing in January 2022 and was effective August 2022. The 2022 ANR
Settlement received FERC approval on April 11, 2023. As part of the settlement, there is a moratorium on any further rate changes
until November 1, 2025. ANR must file for new rates with an effective date no later than August 1, 2028. In second quarter 2023,
previously accrued rate refund liabilities, including interest, were refunded to customers.
Columbia Gulf
Columbia Gulf operates under a settlement approved by FERC in December 2019 (2019 Columbia Gulf Settlement), which
requires Columbia Gulf to file a general rate case under Section 4 of the NGA no later than January 31, 2027. The 2019 Columbia
Gulf Settlement included a moratorium that expired in August 2022. In July 2023 Columbia Gulf, in advance of its obligation to
file a general rate case from the 2019 Columbia Gulf Settlement, reached a settlement with its customers effective March 1, 2024
and received FERC approval in August 2023 (2023 Columbia Gulf Settlement). As part of the 2023 Columbia Gulf Settlement,
there is a moratorium on any further rate changes through February 28, 2027 and Columbia Gulf must file for new rates no later
than March 1, 2029.
Great Lakes
Great Lakes operates under a settlement approved by FERC in February 2018, which does not include a moratorium; however,
Great Lakes was required to file for new rates no later than March 31, 2022.
In March 2022, Great Lakes filed a rate settlement (2022 Great Lakes Settlement) with FERC that satisfies the obligations from
the 2017 settlement that Great Lakes file for rates to become effective no later than October 2022. The 2022 Great Lakes
Settlement, approved by FERC in April 2022, maintains Great Lakes' existing maximum transportation rates through
October 31, 2025. The 2022 Great Lakes Settlement contains a moratorium until October 31, 2025. Great Lakes will be required to
file for new rates no later than April 30, 2025, with such new rates effective no later than November 1, 2025.
Tuscarora
Tuscarora operates under rates established as part of the FERC-approved rate settlement effective August 2019. Under the terms
of this settlement, Tuscarora was required to file for new rates to be effective no later than February 1, 2023. Tuscarora filed a
general NGA Section 4 Rate Case with FERC in July 2022, requesting an increase to its maximum rates effective February 1, 2023,
subject to refund. On March 24, 2023, Tuscarora filed a Stipulation and Agreement of Settlement with FERC, which was
approved on September 6, 2023.
TC Energy Consolidated Financial Statements 2023 | 177
Gas Transmission Northwest
Gas Transmission Northwest (GTN) operates under rates established as part of the FERC-approved rate settlement effective
November 18, 2021 (2021 GTN Settlement). The 2021 GTN Settlement satisfies the obligations from the 2015 and 2018 rate
settlements that GTN file for rates to become effective no later than January 1, 2022 and extends existing maximum
transportation rates at their current levels. GTN’s annual depreciation rates remain unchanged. The 2021 GTN Settlement
contains a moratorium until December 31, 2023. Additionally, the 2021 GTN Settlement authorizes GTN to recover payments that
it incurs in the states of Oregon and Washington for carbon/greenhouse gas-related taxes. GTN is required to file for new rates to
become effective no later than April 1, 2024. Accordingly, GTN filed a general NGA Section 4 Rate Case with FERC on
September 29, 2023, requesting an increase to GTN's maximum rates to become effective April 1, 2024, and subject to refund.
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 are in compliance with CRE economic regulations that provide for cost
recovery, including a return of and on invested capital.
178 | TC Energy Consolidated Financial Statements 2023
Regulatory Assets and Liabilities
at December 31
(millions of Canadian $)
Regulatory Assets
Deferred income taxes1
Operating and debt-service regulatory assets2
Pensions and other post-retirement benefits1,3
Foreign exchange on long-term debt1,4
Other
Less: Current portion included in Other current assets (Note 9)
Regulatory Liabilities
Pipeline abandonment trust balances5
Deferred income taxes – U.S. Tax Reform6
Canadian Mainline short-term adjustment and toll-stabilization accounts7,8
Canadian Mainline bridging amortization account7
Cost of removal9
Deferred income taxes1
Canadian Mainline long-term adjustment account7,10
ANR post-employment and retirement benefits other than pension11
Operating and debt-service regulatory liabilities2
Pensions and other post-retirement benefits3
Other
Less: Current portion included in Accounts payable and other (Note 18)
Remaining
Recovery/
Settlement
Period
(years)
n/a
1
n/a
1-6
n/a
n/a
n/a
n/a
7
n/a
n/a
3
n/a
1
n/a
n/a
2023
2022
2,204
1,817
29
54
11
108
2,406
76
2,330
2,355
1,137
437
376
351
198
111
42
23
6
54
5,090
284
4,806
2
28
19
111
1,977
67
1,910
2,014
1,197
284
429
337
181
149
43
50
10
99
4,793
273
4,520
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.
Operating and debt-service regulatory assets and liabilities represent the accumulation of cost and revenue variances to be included in determination of rates in
the following year.
These balances represent the regulatory offset to pension plan and other post-retirement benefit obligations to the extent the amounts are expected to be
collected from or refunded to customers in future rates.
Foreign exchange on long-term debt of the NGTL System represents the variance resulting from revaluing foreign currency-denominated debt instruments to
the current foreign exchange rate from the historical foreign exchange rate at the time of issue. Foreign exchange gains and losses realized when foreign debt
matures or is redeemed early are expected to be recovered or refunded through the determination of future tolls.
This balance represents the amounts collected in tolls from customers and included in the LMCI restricted investments to fund future abandonment of the
Company's CER-regulated pipeline facilities.
The U.S. corporate income tax rate was reduced from 35 per cent to 21 per cent in 2017 as a result of H.R.1, the Tax Cuts and Jobs Act (U.S. Tax Reform). This U.S.
regulated operations balance, where applicable, represents established regulatory liabilities driven by 2018 FERC prescribed changes related to U.S. Tax Reform
being 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.
Under the terms of the 2021-2026 Mainline Settlement, a portion of the STAA account commenced amortization in 2023 as predetermined thresholds were
met, over the terms outlined per the settlement agreement.
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.
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
$42 million (US$32 million) balance at December 31, 2023 is subject to resolution through future regulatory proceedings and, accordingly, a settlement period
cannot be determined at this time.
TC Energy Consolidated Financial Statements 2023 | 179
15. GOODWILL
The Company's Goodwill balance on the Consolidated balance sheet is comprised of the following amounts:
at December 31
(millions)
Columbia Pipeline Group, Inc.
ANR
Great Lakes
North Baja
Tuscarora
Changes in Goodwill were as follows:
(millions of Canadian $)
Balance at January 1, 2022
Great Lakes impairment charge
Foreign exchange rate changes
Balance at December 31, 2022
Foreign exchange rate changes
Balance at December 31, 2023
2023
Canadian
dollars
2022
U.S.
dollars
Canadian
dollars
9,708
2,570
161
63
30
7,351
1,946
122
48
23
9,948
2,634
165
65
31
U.S.
dollars
7,351
1,946
122
48
23
12,532
9,490
12,843
9,490
U.S. Natural
Gas Pipelines
12,582
(571)
832
12,843
(311)
12,532
As part of the annual goodwill impairment assessment at December 31, 2023, the Company evaluated qualitative factors
impacting the fair value of the underlying reporting units for all reporting units other than for the Tuscarora and North Baja
reporting units. It was determined that it was more likely than not that the fair value of these reporting units exceeded their
carrying amounts, including goodwill.
180 | TC Energy Consolidated Financial Statements 2023
Columbia
On October 4, 2023, as part of the asset divestiture program announced in 2022, the Company successfully completed the sale
of a 40 per cent non-controlling equity interest in Columbia Gas and Columbia Gulf. In conjunction with the process leading up
to the sale, the Company performed a quantitative goodwill impairment test at June 30, 2023.
The estimated fair value measurements used in the Company's goodwill impairment analysis are classified as Level III of the fair
value hierarchy. In the determination of the fair value utilized in the quantitative goodwill impairment test for the Columbia
reporting unit, the Company performed a discounted cash flow model analysis using projections of future cash flows and applied
a risk-adjusted discount rate and value multiple which involved significant estimates and judgments. It was determined that the
fair value of the Columbia reporting unit, inclusive of the Columbia Gas and Columbia Gulf business units, exceeded its carrying
value, including goodwill. Although goodwill was not impaired, the estimated fair value in excess of the carrying value was less
than 10 per cent. There is a risk that reductions in future cash flow forecasts and adverse changes in other key assumptions could
result in a future impairment of a portion of the goodwill balance relating to Columbia.
The Company evaluated qualitative factors impacting the fair value of the Columbia reporting unit from June 30, 2023 to
December 31, 2023 and determined that it was more likely than not that the fair value remains higher than the carrying amount,
including goodwill.
North Baja and Tuscarora
The Company elected to proceed directly to a quantitative annual impairment test at December 31, 2023 for the $63 million of
goodwill related to the North Baja reporting unit due to the passage of time from the previous quantitative test at
December 31, 2018. The Company also elected to proceed directly to a quantitative annual impairment test for the $30 million of
goodwill related to the Tuscarora reporting unit due to the passage of time from the previous quantitative test at
December 31, 2018, and subsequent to the Tuscarora Section 4 rate case settlement in 2023. It was determined that the fair
values of North Baja and Tuscarora exceeded their carrying values, including goodwill, at December 31, 2023.
Great Lakes
In March 2022, Great Lakes reached a pre-filing settlement with its customers and filed an unopposed rate case settlement with
FERC by which Great Lakes and the settling parties agreed to maintain existing recourse rates through October 31, 2025.
Management performed a quantitative impairment test which evaluated a range of assumptions through a discounted cash flow
model analysis using a risk-adjusted discount rate. It was determined that the estimated fair value of the Great Lakes reporting
unit no longer exceeded its carrying value, including goodwill, and that an impairment charge was necessary. As a result, the
Company recorded a pre-tax goodwill impairment charge of $571 million ($531 million after tax) for the year ended
December 31, 2022 within the U.S. Natural Gas Pipelines segment that is included in Goodwill and asset impairment charges and
other in the Company's Consolidated statement of income. The remaining goodwill balance related to Great Lakes was
US$122 million at December 31, 2022. There is a risk that continued reductions in future cash flow forecasts and adverse changes
in other key assumptions could result in a future impairment of the goodwill balance relating to Great Lakes. The majority of the
Great Lakes goodwill impairment charge was allocated to non-deductible goodwill and the income tax recovery of $40 million
was attributable to the portion of the goodwill that was deductible for income tax purposes. The estimated fair value
measurements used in the Company's goodwill impairment analysis is classified as Level III of the fair value hierarchy. In the
determination of the fair value utilized in the quantitative goodwill impairment test for each reporting unit, the Company used
its projections of future cash flows and applied a risk-adjusted discount rate which involved significant estimates and judgments.
Asset Divestiture Program
TC Energy is progressing the asset divestiture program announced in 2022, which may involve the divestiture of reporting units,
or portions thereof. These divestitures could include assets that have associated goodwill. To the extent that a sale transaction
indicates a value lower than previously estimated, goodwill could be impaired. In the event of a partial sale of such assets, the
anticipated proceeds will be considered in management’s assessment of fair value of the retained interest and any associated
goodwill. The Company will continue to evaluate incremental capital rotation opportunities.
TC Energy Consolidated Financial Statements 2023 | 181
16. OTHER LONG-TERM ASSETS
at December 31
(millions of Canadian $)
Deferred income tax assets (Note 20)
Employee post-retirement benefits (Note 28)
Long-term contract assets (Note 6)
Capital projects in development
Fair value of derivative contracts (Note 29)
Keystone XL contractual recoveries (Note 7)
Keystone environmental provision recovery (Note 18)
Other
2023
1,332
518
457
237
155
34
33
252
3,018
2022
1,070
563
355
99
91
44
240
323
2,785
182 | TC Energy Consolidated Financial Statements 2023
17. NOTES PAYABLE
at December 31
2023
2022
(millions of Canadian $, unless otherwise noted)
Outstanding
Canada1
Mexico (2023 – nil; 2022 – US$215)2
—
—
—
Weighted
Average
Interest Rate
per Annum
—
—
Outstanding
5,971
291
6,262
Weighted
Average
Interest Rate
per Annum
4.9%
6.0%
1
2
At December 31, 2023, Notes payable consisted of Canadian dollar-denominated notes of nil (2022 – $2,810 million) and U.S. dollar-denominated notes of nil
(2022 – US$2,336 million).
In January 2023, the Company's Mexico subsidiary fully repaid the outstanding balance and terminated its MXN$5.0 billion demand senior unsecured revolving
credit facility.
On August 25, 2023, TransCanada PipeLines Limited (TCPL) fully repaid and retired its 364-day $1.5 billion senior unsecured term
loan bearing interest at a floating rate entered into on November 22, 2022.
At December 31, 2022, Notes payable reflects short-term borrowings in Canada by TCPL and in Mexico by a wholly-owned
Mexican subsidiary.
At December 31, 2023, total committed revolving and demand credit facilities were $11.6 billion (2022 – $12.9 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)
2023
Borrowers
Description
Matures
Total
Facilities
Unused
Capacity1
2022
Total
Facilities
Committed, syndicated, revolving, extendible, senior unsecured credit facilities2:
TCPL
Supports commercial paper program and
for general corporate purposes
December
2028
TCPL / TCPL USA
TCPL / TCPL USA
Supports commercial paper programs and
for general corporate purposes of the
borrowers, guaranteed by TCPL
Supports commercial paper programs and
for general corporate purposes of the
borrowers, guaranteed by TCPL
December
2024
December
2026
3.0
3.0
3.0
US 2.5
US 2.5
US 3.0
US 2.5
US 2.5
US 2.5
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
2.0 3
1.0
2.1 3
Mexico subsidiary
For Mexico general corporate purposes,
guaranteed by TCPL
Demand
—
—
MXN 5.0 3
1
2
3
Unused capacity is net of commercial paper outstanding and facility draws.
Provisions of various trust indentures and 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 trust indentures and credit arrangements also require the Company to comply with various affirmative and negative
covenants and maintain certain financial ratios. At December 31, 2023, the Company was in compliance with all financial covenants.
Or the U.S. dollar equivalent.
For the year ended December 31, 2023, the cost to maintain the above facilities was $14 million (2022 – $14 million;
2021 – $17 million).
TC Energy Consolidated Financial Statements 2023 | 183
18. ACCOUNTS PAYABLE AND OTHER
at December 31
(millions of Canadian $)
Trade payables
Fair value of derivative contracts (Note 29)
Regulatory liabilities (Note 14)
Keystone environmental provision
Contract liabilities (Note 6)
Class C Interests (Note 7)
Coastal GasLink contractual contribution (Notes 8, 12 and 33)
Other
2023
4,832
1,143
284
122
69
19
—
518
6,987
2022
4,330
871
273
650
62
37
537
389
7,149
Keystone Environmental Provision
In December 2022, a pipeline incident occurred in Washington County, Kansas on the Keystone Pipeline System. At
December 31, 2022, the Company accrued an environmental liability of $650 million, before expected insurance recoveries and
not including potential fines and penalties which continue to be indeterminable. At June 30, 2023, the cost estimate for the
incident was adjusted to $794 million based on a review of costs and commitments incurred and, at December 31, 2023,
remains unchanged. Amounts paid for the environmental remediation liability were $676 million at December 31, 2023
(December 31, 2022 – nil). The remaining balance reflected in Accounts payable and other and Other long-term liabilities
on the Company’s Consolidated balance sheet was $122 million and $9 million, respectively at December 31, 2023
(December 31, 2022 – $650 million and nil, respectively).
The expected recovery of the remaining estimated environmental remediation costs recorded in Other current assets and Other
long-term assets were $150 million and $33 million, respectively at December 31, 2023 (December 31, 2022 – $410 million and
$240 million, respectively). An additional $36 million was accrued during the year, which is expected to be recoverable from
TC Energy's wholly-owned captive insurance subsidiary. This amount was recorded as an expense in Interest income and other in
the Consolidated statement of income. During the year, the Company received $575 million (2022 – nil) from its insurance
policies related to the costs for environmental remediation. Restoration activities are ongoing and expected to continue into
2024.
19. OTHER LONG-TERM LIABILITIES
at December 31
(millions of Canadian $)
Operating lease obligations (Note 11)
Fair value of derivative contracts (Note 29)
Employee post-retirement benefits (Note 28)
Asset retirement obligations
Long-term contract liabilities (Note 6)
Other
184 | TC Energy Consolidated Financial Statements 2023
2023
2022
401
106
97
64
12
335
1,015
379
151
111
79
32
265
1,017
20. INCOME TAXES
Geographic Components of Income before Income Taxes
year ended December 31
(millions of Canadian $)
Canada
Foreign
Income before Income Taxes
Provision for Income Taxes
year ended December 31
(millions of Canadian $)
Current
Canada
Foreign
Deferred
Canada
Foreign
Income Tax Expense
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
Income tax differential related to regulated operations
Foreign income tax rate differentials
Income from non-controlling interests and equity investments
Valuation allowance (release)
Non-taxable capital (gains) and losses
Mexico foreign exchange exposure
Impact of Mexico inflationary adjustments
Settlement of Mexico prior years' income tax assessments
U.S. minimum tax
Non-deductible goodwill impairment
Other
Income Tax Expense
2023
(446)
4,456
4,010
2022
(2,154)
3,528
1,374
2021
(292)
2,458
2,166
2023
2022
2021
73
858
931
(39)
50
11
942
43
372
415
(467)
641
174
589
29
276
305
(327)
142
(185)
120
2023
4,010
23.0%
2022
1,374
23.0%
2021
2,166
23.0%
922
(260)
(174)
(56)
197
196
132
1
—
(14)
—
(2)
942
316
(174)
(271)
(54)
199
173
9
24
196
96
91
(16)
589
498
(139)
(230)
(70)
(8)
—
10
32
—
—
—
27
120
TC Energy Consolidated Financial Statements 2023 | 185
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
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
Financial instruments
Other
Net Deferred Income Tax Liabilities
The above deferred tax amounts have been classified on the Consolidated balance sheet as follows:
at December 31
(millions of Canadian $)
Deferred Income Tax Assets
Other long-term assets (Note 16)
Deferred Income Tax Liabilities
Deferred income tax liabilities
Net Deferred Income Tax Liabilities
2023
2022
1,833
1,519
569
206
73
2,681
730
1,951
6,816
1,115
493
160
160
8,744
6,793
571
333
193
2,616
640
1,976
6,686
1,152
397
126
193
8,554
6,578
2023
2022
1,332
1,070
8,125
6,793
7,648
6,578
At December 31, 2023, the Company has recognized the benefit of non-capital loss carryforwards of $6,593 million
(2022 – $5,429 million) for federal and provincial purposes in Canada, which expire from 2030 to 2043. The Company has not yet
recognized the benefit of capital loss carryforwards of $478 million (2022 – $251 million) for federal and provincial purposes in
Canada which have no expiry date. The Company also has Ontario corporate minimum tax (CMT) credits of $140 million
(2022 – $126 million), which expire from 2026 to 2043. As of December 31, 2023, the Company has not recognized the benefit of
CMT credits of $22 million (2022 – $22 million).
At December 31, 2023, the Company has recognized the benefit of net operating loss carryforwards of US$47 million
(2022 – US$69 million) in Mexico, which expire from 2024 to 2033.
186 | TC Energy Consolidated Financial Statements 2023
TC Energy recorded an income tax valuation allowance of $730 million and $640 million against the deferred income tax asset
balances at December 31, 2023 and 2022, respectively. The increase in the valuation allowance is primarily a result of the foreign
exchange movement on unrecognized capital losses and the unrealized non-taxable capital losses on the Coastal GasLink equity
investment. At December 31, 2023, the Company recorded a total of $358 million (2022 – $173 million) in valuation allowance as
a result of the Coastal GasLink equity investment impairment that resulted in a portion of the impairment having unrealized
non-taxable capital losses. These losses have not been recognized as of December 31, 2023. 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, 2023, 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.
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, 2023 by approximately
$1,629 million (2022 – $1,216 million) if there had been a provision for these taxes.
Income Tax Payments
Income tax payments of $836 million, net of refunds, were made in 2023 (2022 – payments, net of refunds, of $394 million;
2021 – payments, net of refunds, of $371 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
2023
2022
2021
91
9
(1)
16
(30)
85
80
6
—
7
(2)
91
52
5
(1)
26
(2)
80
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, 2023 reflects $3 million interest expense (2022 – $6 million; 2021 – $1 million). At
December 31, 2023, the Company had accrued $21 million in interest expense (2022 – $18 million; 2021 – $12 million). The
Company incurred no penalties associated with income tax uncertainties related to income tax expense for the years ended
December 31, 2023, 2022 and 2021 and no penalties were accrued as at December 31, 2023, 2022 and 2021.
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 2015. Substantially all material U.S. federal, state and local
income tax matters have been concluded for years through 2015. Substantially all material Mexico income tax matters have been
concluded for years through 2017.
TC Energy Consolidated Financial Statements 2023 | 187
Mexico Tax Audit
In 2019, the Mexican tax authority, the 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 that 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 to challenge it. In January 2022, TC Energy received the tax court’s ruling on the 2013 tax
return, which upheld the SAT assessment. 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 income and withholding taxes, interest, penalties and other financial
charges.
During 2022, TC Energy settled with the SAT on all of the above matters for the tax years 2013 through 2021 and recorded
$196 million (US$153 million) of income tax expense, inclusive of withholding taxes, interest, penalties and other financial
charges for the year ended December 31, 2022.
188 | TC Energy Consolidated Financial Statements 2023
21. LONG-TERM DEBT
at December 31
(millions of Canadian $, unless otherwise noted)
TRANSCANADA PIPELINES LIMITED
Medium Term Notes
Canadian
Senior Unsecured Notes
2023
2022
Maturity
Dates
Outstanding
Interest
Rate1
Outstanding
Interest
Rate1
2024 to 2052
15,466
4.6%
13,966
4.5%
U.S. (2023 – US$16,167; 2022 – US$15,542)
2024 to 2049
21,349
36,815
5.0%
21,032
34,998
4.9%
NOVA GAS TRANSMISSION LTD.
Debentures and Notes
Canadian
U.S. (2023 – nil; 2022 – US$200)
Medium Term Notes
Canadian
U.S. (2023 and 2022 – US$33)
COLUMBIA PIPELINE GROUP, INC.
Senior Unsecured Notes2
U.S. (2023 – nil; 2022 – US$1,500)
COLUMBIA PIPELINES OPERATING COMPANY LLC
Senior Unsecured Notes2
2024
2025 to 2030
2026
9.9%
—
7.4%
7.5%
100
—
504
43
647
9.9%
7.9%
7.4%
7.5%
100
271
504
44
919
—
—
2,030
4.9%
U.S. (2023 – US$6,100; 2022 – nil)
2025 to 2063
8,055
6.1%
—
—
COLUMBIA PIPELINES HOLDING COMPANY LLC
Senior Unsecured Notes2
U.S. (2023 – US$1,000; 2022 – nil)
2026 to 2028
1,320
6.2%
—
—
ANR PIPELINE COMPANY
Senior Unsecured Notes
U.S. (2023 and 2022 – US$1,172)
2024 to 2037
1,548
4.1%
1,587
4.1%
TC PIPELINES, LP
Senior Unsecured Notes
U.S. (2023 and 2022 – US$850)
2025 to 2027
1,122
4.2%
1,150
4.2%
TC Energy Consolidated Financial Statements 2023 | 189
at December 31
(millions of Canadian $, unless otherwise noted)
GAS TRANSMISSION NORTHWEST LLC
Senior Unsecured Notes
2023
2022
Maturity
Dates
Outstanding
Interest
Rate1
Outstanding
Interest
Rate1
U.S. (2023 – US$375; 2022 – US$325)
2030 to 2035
495
4.4%
440
4.3%
PORTLAND NATURAL GAS TRANSMISSION SYSTEM
Senior Unsecured Notes
U.S. (2023 and 2022 – US$250)
2030 to 2031
330
2.8%
338
2.8%
GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP
Senior Unsecured Notes
U.S. (2023 – US$125; 2022 – US$146)
2028 to 2030
165
7.6%
198
7.6%
TUSCARORA GAS TRANSMISSION COMPANY
Unsecured Term Loan
U.S. (2023 – nil; 2022 – US$34)
TC ENERGÍA MEXICANA, S. DE R.L. DE C.V.
Senior Unsecured Term Loan
—
—
46
6.5%
U.S. (2023 – US$1,800; 2022 – nil)
2028
2,377
7.7%
Senior Unsecured Revolving Credit Facility
U.S. (2023 – US$185; 2022 – nil)
2028
244
7.7%
Current portion of long-term debt
Unamortized debt discount and issue costs
Fair value adjustments3
2,621
53,118
(2,938)
(312)
108
49,976
—
—
—
—
—
41,706
(1,898)
(239)
76
39,645
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.
On August 8, 2023, US$1.5 billion senior unsecured notes were assigned from Columbia Pipelines Group, Inc. to Columbia Pipelines Operating Company LLC in
advance of the October 4, 2023 sale of a 40 per cent non-controlling equity interest in Columbia Gas and Columbia Gulf. Preceding this sale, US$5.6 billion of
senior unsecured notes were issued. Refer to Note 24, Non-controlling interests, for additional information.
The fair value adjustments include $119 million (2022 – $140 million) related to the acquisition of Columbia Pipeline Group, Inc. These adjustments also include a
decrease of $11 million (2022 – $64 million) related to hedged interest rate risk. Refer to Note 29, Risk management and financial instruments, for additional
information.
Principal Repayments
At December 31, 2023, 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
2024
2,938
2025
2,779
2026
5,287
2027
3,096
2028
6,232
190 | TC Energy Consolidated Financial Statements 2023
Long-Term Debt Issued
The Company issued long-term debt over the three years ended December 31, 2023 as follows:
(millions of Canadian $, unless otherwise noted)
Company
Issue Date
Type
Maturity Date
Amount
Interest Rate
TRANSCANADA PIPELINES LIMITED
May 2023
Senior Unsecured Term Loan1 May 2026
US 1,024
Floating
March 2023
Senior Unsecured Notes
March 2023
Senior Unsecured Notes
March 20262
March 20262
March 2023
Medium Term Notes
July 2030
March 2023
Medium Term Notes
March 2023
Medium Term Notes
May 2022
May 2022
May 2022
Medium Term Notes
Medium Term Notes
Medium Term Notes
March 20262
March 20262
May 2032
May 2026
May 2052
US 850
US 400
1,250
600
400
800
400
300
October 2021
Senior Unsecured Notes
October 2024
US 1,250
October 2021
Senior Unsecured Notes
October 2031
US 1,000
6.20%
Floating
5.28%
5.42%
Floating
5.33%
4.35%
5.92%
1.00%
2.50%
June 2021
June 2021
June 2021
Medium Term Notes
Medium Term Notes
June 2024
June 2031
Medium Term Notes
September 2047
750
500
250
Floating
2.97%
4.33% 3
COLUMBIA PIPELINES OPERATING COMPANY LLC
August 2023
Senior Unsecured Notes
November 2033
US 1,500
August 2023
Senior Unsecured Notes
November 2053
US 1,250
August 2023
Senior Unsecured Notes
August 2030
August 2023
Senior Unsecured Notes
August 2043
August 2023
Senior Unsecured Notes
August 2063
COLUMBIA PIPELINES HOLDING COMPANY LLC
August 2023
Senior Unsecured Notes
August 2028
August 2023
Senior Unsecured Notes
August 2026
US 750
US 600
US 500
US 700
US 300
6.04%
6.54%
5.93%
6.50%
6.71%
6.04%
6.06%
GAS TRANSMISSION NORTHWEST LLC
TC ENERGÍA MEXICANA, S. DE R.L. DE C.V.
June 2023
Senior Unsecured Notes
June 2030
US 50
4.92%
ANR PIPELINE COMPANY
January 2023
January 2023
Senior Unsecured Term Loan
Senior Unsecured Revolving
Credit Facility
January 2028
US 1,800
Floating
January 2028
US 500
Floating
May 2022
May 2022
May 2022
May 2022
Senior Unsecured Notes
May 2032
Senior Unsecured Notes
May 2034
Senior Unsecured Notes
May 2037
Senior Unsecured Notes
May 2029
US 300
US 200
US 200
US 100
3.43%
3.58%
3.73%
3.26%
PORTLAND NATURAL GAS TRANSMISSION SYSTEM
October 2021
Senior Unsecured Notes
October 2031
US 125
2.68%
TC Energy Consolidated Financial Statements 2023 | 191
(millions of Canadian $, unless otherwise noted)
Company
Issue Date
Type
Maturity Date
Amount
Interest Rate
TUSCARORA GAS TRANSMISSION COMPANY
August 2021
Unsecured Term Loan
August 2024
US 13
Floating
KEYSTONE XL SUBSIDIARIES4
COLUMBIA PIPELINE GROUP, INC.5
Various
Project-Level Credit Facility
June 2021
US 849
Floating
January 2021
Unsecured Term Loan
June 2022
US 4,040
Floating
1
2
3
4
5
This loan was fully repaid and retired in September 2023. Related unamortized debt issue costs of $3 million were included in Interest expense in the
Consolidated statement of income.
Callable at par in March 2024 or at any time thereafter.
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 4.19 per cent.
In January 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 7, 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.
On January 9, 2024, Columbia Pipelines Holding Company LLC issued US$500 million senior unsecured notes due January 2034,
bearing interest at a fixed rate of 5.68 per cent.
192 | TC Energy Consolidated Financial Statements 2023
Long-Term Debt Retired/Repaid
The Company retired/repaid long-term debt over the three years ended December 31, 2023 as follows:
(millions of Canadian $, unless otherwise noted)
Company
TRANSCANADA PIPELINES LIMITED
TUSCARORA GAS TRANSMISSION COMPANY
NOVA GAS TRANSMISSION LTD.
TC ENERGÍA MEXICANA, S. DE R.L. DE C.V.
COLUMBIA PIPELINE GROUP, INC.
NORTH BAJA PIPELINE, LLC
TC PIPELINES, LP
ANR PIPELINE COMPANY
Retirement/
Repayment Date
Type
Amount
Interest Rate
October 2023
Senior Unsecured Notes
September 2023
Senior Unsecured Notes1
July 2023
Medium Term Notes
December 2022
Medium Term Notes
August 2022
Senior Unsecured Notes
November 2021
Medium Term Notes
January 2021
Debentures
US 625
US 1,024
750
25
US 1,000
500
US 400
3.75%
Floating
3.69%
9.95%
2.50%
3.65%
9.88%
November 2023
Unsecured Term Loan
US 32
Floating
April 2023
Debentures
US 200
7.88%
Various
Senior Unsecured Revolving
Credit Facility
US 315
Floating
December 2021
Unsecured Term Loan2
US 4,040
Floating
December 2021
Unsecured Term Loan
US 50
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
9.63%
GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP
November 2021
Senior Unsecured Notes
US 10
9.09%
PORTLAND NATURAL GAS TRANSMISSION SYSTEM
KEYSTONE XL SUBSIDIARIES3
October 2021
Unsecured Loan Facility
US 93
Floating
June 2021
Project-Level Credit Facility
US 849
Floating
1
2
3
In May 2023, the Company entered into a US$1,024 million senior unsecured term loan and the full amount was drawn. The loan was fully repaid and retired in
September 2023. Related unamortized debt issue costs of $3 million were included in Interest expense in the Consolidated statement of income.
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 7, Keystone XL, for additional information.
In March 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.
TC Energy Consolidated Financial Statements 2023 | 193
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
2023
2,562
617
165
(187)
106
2022
1,883
543
153
(27)
36
2021
1,841
453
10
(22)
78
3,263
2,588
2,360
1
Amortization and other financial charges include 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 $2,931 million in 2023 (2022 – $2,478 million; 2021 – $2,299 million) on long-term
debt, junior subordinated notes and short-term debt, net of interest capitalized.
194 | TC Energy Consolidated Financial Statements 2023
22. JUNIOR SUBORDINATED NOTES
at December 31
(millions of Canadian $, unless otherwise noted)
TRANSCANADA PIPELINES LIMITED
US$1,000 issued 2007 at 6.35%2
US$750 issued 2015 at 5.88%3,4
US$1,200 issued 2016 at 6.13%3,4
US$1,500 issued 2017 at 5.55%3,4
$1,500 issued 2017 at 4.90%3,4
US$1,100 issued 2019 at 5.75%3,4
$500 issued 2021 at 4.45%3,5
US$800 issued 2022 at 5.85%3,5
Unamortized debt discount and issue costs
2023
2022
Maturity
Date
Outstanding
Effective
Interest Rate1
Outstanding
Effective
Interest Rate1
2067
2075
2076
2077
2077
2079
2081
2082
6.5%
7.8%
8.3%
7.5%
7.0%
8.0%
5.7%
7.1%
1,320
990
1,585
1,981
1,500
1,453
500
1,056
10,385
(98)
10,287
6.2%
7.4%
8.0%
7.1%
6.8%
7.6%
5.7%
7.2%
1,353
1,015
1,624
2,030
1,500
1,488
500
1,083
10,593
(98)
10,495
1
2
3
4
5
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$1.0 billion were issued in 2007 at a fixed rate of 6.35 per cent and converted in 2017 to bear interest at a floating rate.
The Junior subordinated notes were issued to TransCanada Trust (the Trust), a financing trust subsidiary wholly-owned by TCPL. While the obligations of the
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 coupon rate is initially a fixed interest rate for the first 10 years and resets every five years thereafter.
The Junior subordinated notes are subordinated in right of payment to existing and future senior indebtedness or other
obligations of TCPL.
In March 2022, TransCanada Trust (the Trust) issued US$800 million of Trust Notes – Series 2022-A to investors with a fixed
interest rate of 5.60 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 US$800 million of junior subordinated notes
of TCPL at an initial fixed rate of 5.85 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 2032 until March 2052 to the then Five-Year Treasury
Rate, as defined in the document governing the subordinated notes, plus 4.236 per cent per annum; from March 2052 until
March 2082, the interest rate will reset every five years to the then Five-Year Treasury Rate plus 4.986 per cent per annum. The
junior subordinated notes are callable at TCPL's option at any time from December 7, 2031 to March 7, 2032 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 March 2021, 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 every five years 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.
TC Energy Consolidated Financial Statements 2023 | 195
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.
23. FOREIGN EXCHANGE (GAINS) LOSSES, NET
year ended December 31
(millions of Canadian $)
Derivative instruments held for trading (Note 29)
Other
24. NON-CONTROLLING INTERESTS
Disposition of Equity Interest
2023
(401)
81
(320)
2022
151
34
185
2021
(37)
27
(10)
Columbia Gas and Columbia Gulf
On October 4, 2023, TC Energy completed the sale of a 40 per cent non-controlling equity interest in Columbia Gas and
Columbia Gulf to Global Infrastructure Partners (GIP) for proceeds of $5.3 billion (US$3.9 billion). The Company continues to have
a controlling interest in these companies and will remain the operator of the pipelines. TC Energy and GIP will each fund their
proportionate share of annual maintenance, modernization and sanctioned growth capital expenditures through internally
generated cash flows, debt financing within the Columbia entities, or from proportionate contributions from TC Energy and GIP.
The sale was accounted for as an equity transaction of which $9.5 billion (US$6.9 billion) was recorded as Non-controlling
interests to reflect the 40 per cent change in the Company’s ownership interest in Columbia Gulf and Columbia Gas. The
difference between the non-controlling ownership interest recognized and the consideration received was recorded as a
reduction to Additional paid-in capital of $3.5 billion (US$3.0 billion), net of tax and transaction costs.
Preceding the close of the equity sale, on August 8, 2023, Columbia Pipelines Operating Company LLC and Columbia Pipelines
Holding Company LLC issued US$4.6 billion and US$1.0 billion of long-term, senior unsecured debt, respectively, with all
proceeds paid to TC Energy. The net proceeds from the offerings and equity sale were used to repay existing intercompany and
third-party debt. Refer to Note 21, Long-term debt, for additional information.
Acquisitions
Texas Wind Farms
On March 15, 2023 and June 14, 2023, TC Energy acquired 100 per cent of the Class B Membership Interests in Fluvanna Wind
Farm (Fluvanna) and Blue Cloud Wind Farm (Blue Cloud), respectively. Each of these operating assets has a tax equity investor
which owns 100 per cent of the Class A Membership Interests, to which a percentage of earnings, tax attributes and cash flows
are allocated. The tax equity investors' interests were recorded as non-controlling interests at their aggregate estimated fair
value of $222 million (US$167 million).
TC Energy has determined that the use of the Hypothetical Liquidation at Book Value (HLBV) method of allocating earnings
between the Company and the tax equity investors is appropriate as the earnings, tax attributes and cash flows from Fluvanna
and Blue Cloud are allocated to its Class A and Class B Membership Interest owners on a basis other than ownership percentages.
Using the HLBV method, the Company's earnings from the projects is calculated based on how the projects would allocate and
distribute cash if the net assets were sold at their carrying amounts on the reporting date under the provisions of the tax equity
agreements.
TC Energy determined it has a controlling financial interest in both projects and has consolidated the acquired entities as voting
interest entities. The tax equity investors’ interests were recorded as Non-controlling interests at their estimated fair values of
$106 million (US$80 million) for Fluvanna and $116 million (US$87 million) for Blue Cloud. These transactions are accounted for as
asset acquisitions and therefore did not result in the recognition of goodwill.
196 | TC Energy Consolidated Financial Statements 2023
TC PipeLines, LP
On March 3, 2021, the Company acquired 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. Under this transaction, 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 income (loss)
Non-controlling interests
Deferred income tax liabilities
Other
March 3, 2021
2,063
(398)
353
(1,563)
(443)
(12)
Non-controlling interests
The Company's Net income (loss) attributable to non-controlling interests included in the Consolidated statement of income
and Non-controlling interests included on the Consolidated balance sheet were as follows:
(millions of Canadian $)
Columbia Gas and Columbia Gulf
Portland Natural Gas Transmission System
Texas Wind Farms
TC PipeLines, LP
Redeemable non-controlling
interest (Note 7)
Non-Controlling
Interests
Ownership at
December 31, 2023
Income (Loss) Attributable to
Non-Controlling Interests
Non-Controlling Interests
year ended December 31
at December 31
2023
2022
2021
40.0%
38.3%
100% 1
nil 2
nil
143
41
(38)
—
—
146
—
37
—
—
—
37
—
30
—
60
1
91
2023
9,167
106
182
—
—
2022
—
126
—
—
—
9,455
126
1
2
Non-controlling interests in the Texas Wind Farms comprises Class A Membership Interests.
Prior to the March 3, 2021 acquisition, the non-controlling interest in TC PipeLines, LP was 74.5 per cent.
TC Energy Consolidated Financial Statements 2023 | 197
25. COMMON SHARES
Outstanding at January 1, 2021
Acquisition of TC PipeLines, LP, net of transaction costs (Note 24)
Exercise of options
Outstanding at December 31, 2021
Issued under public offering1
Dividend reinvestment and share purchase plan
Exercise of options
Outstanding at December 31, 2022
Dividend reinvestment and share purchase plan
Exercise of options
Outstanding at December 31, 2023
Number of Shares
Amount
(thousands)
(millions of Canadian $)
940,064
37,955
2,797
980,816
28,400
5,916
2,830
1,017,962
19,464
62
1,037,488
24,488
2,063
165
26,716
1,754
342
183
28,995
1,003
4
30,002
1
Net of underwriting commissions and deferred income taxes.
Common Shares Issued and Outstanding
The Company is authorized to issue an unlimited number of common shares without par value.
Common Shares Issued Under Public Offering
On August 10, 2022, TC Energy issued 28,400,000 common shares at a price of $63.50 each for total gross proceeds of
approximately $1.8 billion.
Dividend Reinvestment and Share Purchase Plan
Under the Company's Dividend Reinvestment and Share Purchase Plan (DRP), eligible holders of common and preferred shares of
TC Energy can reinvest their dividends and make optional cash payments to obtain additional TC Energy common shares. From
August 31, 2022 to July 31, 2023, common shares were issued from treasury at a discount of two per cent to market prices over a
specified period.
For the periods between January 1, 2021 and August 31, 2022 and after July 31, 2023, common shares purchased with reinvested
cash dividends under TC Energy's DRP are acquired on the open market at 100 per cent of the weighted average purchase price.
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 24, Non-controlling interests, for additional information.
Basic and Diluted Net Income (Loss) per Common Share
Net income (loss) per common share is calculated by dividing Net income (loss) 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, from August 31, 2022 to July 31, 2023, common
shares issuable from treasury under the DRP.
Weighted Average Common Shares Outstanding
(millions)
Basic
Diluted
2023
1,030
1,030
2022
995
996
2021
973
974
198 | TC Energy Consolidated Financial Statements 2023
Stock Options
Options outstanding at January 1, 2023
Options granted
Options exercised
Options forfeited/expired
Options Outstanding at December 31, 2023
Options Exercisable at December 31, 2023
Number of
Options
(thousands)
Weighted
Average
Exercise Prices
Weighted
Average
Remaining
Contractual Life
(years)
6,109
1,933
(62)
(544)
7,436
4,375
$63.86
$56.66
$48.44
$60.60
$62.36
$64.47
4.1
3.0
At December 31, 2023, an additional 2,267,871 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 and applied the following weighted
average assumptions:
year ended December 31
Weighted average fair value
Expected life (years)1
Interest rate
Volatility2
Dividend yield
2023
$7.88
5.1
2.9%
24%
6.3%
2022
$8.24
5.4
1.6%
22%
5.5%
2021
$7.39
5.4
0.5%
25%
6.0%
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 $9 million in 2023
(2022 – $10 million; 2021 – $12 million). At December 31, 2023, unrecognized compensation costs related to non-vested stock
options were $12 million. The cost is expected to be fully recognized over a weighted average period of two years.
The following table summarizes additional stock option information:
year ended December 31
(millions of Canadian $, unless otherwise noted)
Total intrinsic value of options exercised
Total fair value of options that have vested
Total options vested
2023
—
76
2022
33
89
2021
28
110
1.5 million
1.6 million
1.9 million
As at December 31, 2023, the aggregate intrinsic values of the total options exercisable and the total options outstanding were
nil.
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.
TC Energy Consolidated Financial Statements 2023 | 199
26. PREFERRED SHARES
at
December 31,
2023
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
2023
(millions of Canadian $)
2022
2021
Series 1
Series 2
Series 3
Series 4
Series 5
Series 6
Series 7
Series 9
Series 11
Series 15
14,577
7,423
9,997
4,003
12,071
1,929
3.48%
Floating 4
1.69%
Floating 4
1.95% 5
Floating 4
$0.86975
$25.00
December 31, 2024
Series 2
360
360
360
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
246
June 30, 2025
Series 3
97
97
97
$0.48725
$25.00
January 30, 2026
Series 6
294
294
294
Floating
$25.00
January 30, 2026
Series 5
48
48
48
24,000
3.90%
$0.97575
$25.00
April 30, 2024
Series 8
589
589
589
18,000
3.76%
$0.9405
$25.00
October 30, 2024
Series 10
442
442
442
10,000
3.35%
$0.83775
$25.00
November 28, 2025
Series 12
244
244
244
—
—
—
—
—
—
—
—
988
2,499 2,499 3,487
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), or 2.96 per cent (Series 12). 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), or 2.96 per cent (Series 11).
Net of underwriting commissions and deferred income taxes.
The floating quarterly dividend rate for the Series 2 preferred shares is 6.96 per cent for the period starting December 29, 2023 to, but excluding,
March 28, 2024. The floating quarterly dividend rate for the Series 4 preferred shares is 6.32 per cent for the period starting December 29, 2023 to, but
excluding, March 28, 2024. The floating quarterly dividend rate for the Series 6 preferred shares is 6.69 per cent for the period starting October 30, 2023 to, but
excluding, January 30, 2024. These rates will reset each quarter going forward.
The fixed rate dividend for Series 5 preferred shares decreased from 2.26 per cent to 1.95 per cent on January 30, 2021 and is due to reset on every fifth
anniversary thereafter.
The holders of preferred shares are entitled to receive a fixed cumulative quarterly preferential dividend as and when declared by
the Board with the exception of Series 2, Series 4 and Series 6 preferred shares. The holders of Series 2, Series 4 and Series 6
preferred shares are entitled to receive quarterly floating rate cumulative preferential dividends as and when declared by the
Board. The holders will have the right, subject to certain conditions, to convert their first preferred shares of a specified series
into first preferred shares of another specified series on the conversion option date and every fifth anniversary thereafter as
indicated in the table above.
TC Energy may, at its option, redeem all or a portion of the outstanding preferred shares for the redemption price per share, plus
all accrued and unpaid dividends on the applicable redemption option date and on every fifth anniversary thereafter. In
addition, Series 2, Series 4 and Series 6 preferred shares are redeemable by TC Energy at any time other than on a designated
date for $25.50 per share plus all accrued and unpaid dividends on such redemption date.
On May 31, 2022, TC Energy redeemed all 40,000,000 issued and outstanding Series 15 preferred shares at a redemption price of
$25.00 per share and paid the final quarterly dividend of $0.30625 per Series 15 preferred share, for the period up to but
excluding May 31, 2022. The Company used the proceeds from the March 2022 issuance of US$800 million of junior subordinated
notes through the Trust to finance this preferred share redemption.
200 | TC Energy Consolidated Financial Statements 2023
In May 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. 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.
In February 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.
27. OTHER COMPREHENSIVE INCOME(LOSS) AND ACCUMULATED OTHER COMPREHENSIVE INCOME(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, 2023
(millions of Canadian $)
Foreign currency translation gains and losses on net investment in foreign
operations
Change in fair value of net investment hedges
Reclassification to net income of (gains) losses on cash flow hedges
Unrealized actuarial gains (losses) on pension and other post-retirement benefit
plans
Other comprehensive income (loss) on equity investments
Other Comprehensive Income (Loss)
year ended December 31, 2022
(millions of Canadian $)
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) losses on cash flow hedges
Unrealized actuarial gains (losses) on pension and other post-retirement benefit
plans
Reclassification to net income of actuarial (gains) losses on pension and other
post-retirement benefit plans
Other comprehensive income (loss) on equity investments
Other Comprehensive Income (Loss)
Before Tax
Amount
Income Tax
(Expense)
Recovery
Net of Tax
Amount
(1,148)
23
97
(15)
(283)
(1,326)
7
(6)
(23)
4
72
54
(1,141)
17
74
(11)
(211)
(1,272)
Before Tax
Amount
Income Tax
(Expense)
Recovery
Net of Tax
Amount
1,410
(48)
(58)
63
81
9
1,156
2,613
84
12
19
(21)
(18)
(3)
(289)
(216)
1,494
(36)
(39)
42
63
6
867
2,397
year ended December 31, 2021
(millions of Canadian $)
Before Tax
Amount
Income Tax
(Expense)
Recovery
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) losses on cash flow hedges
Unrealized actuarial gains (losses) on pension and other post-retirement benefit
plans
Reclassification to net income of actuarial (gains) losses on pension and other
post-retirement benefit plans
Other comprehensive income (loss) on equity investments
Other Comprehensive Income (Loss)
(100)
(3)
(13)
68
208
20
714
894
(8)
1
3
(13)
(50)
(6)
(179)
(252)
(108)
(2)
(10)
55
158
14
535
642
TC Energy Consolidated Financial Statements 2023 | 201
The changes in AOCI by component, net of tax, are as follows:
(millions of Canadian $)
AOCI balance at January 1, 2021
Other comprehensive income (loss) before reclassifications1
Amounts reclassified from AOCI
Net current period other comprehensive income (loss)
Acquisition of TC PipeLines, LP2
AOCI balance at December 31, 2021
Other comprehensive income (loss) before reclassifications1
Amounts reclassified from AOCI
Net current period other comprehensive income (loss)
AOCI balance at December 31, 2022
Other comprehensive income (loss) before reclassifications1
Amounts reclassified from AOCI3
Net current period other comprehensive income (loss)
Impact of non-controlling interest4
AOCI balance at December 31, 2023
Currency
Translation
Adjustments
Cash Flow
Hedges
Pension and
Other Post-
Retirement
Benefit Plan
Adjustments
Equity
Investments
Total
(1,273)
(98)
—
(98)
362
(1,009)
1,450
—
1,450
441
(231)
—
(231)
(527)
(317)
(143)
(11)
55
44
(13)
(112)
(39)
42
3
(109)
—
74
74
—
(35)
(285)
(738)
(2,439)
158
14
172
—
(113)
63
6
69
(44)
(11)
—
(11)
—
(55)
506
28
534
4
(200)
870
(3)
867
667
(195)
(16)
(211)
—
456
555
97
652
353
(1,434)
2,344
45
2,389
955
(437)
58
(379)
(527)
49
1
2
3
4
Other comprehensive income(loss) before reclassifications on currency translation adjustments, cash flow hedges and equity investments are net of
non-controlling interest loss of $366 million (2022 – gains of $8 million; 2021 – losses of $12 million), nil (2022 – nil; 2021 – gains of $1 million), and
nil (2022 – nil; 2021 – gains of $1 million), respectively.
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 24, Non-controlling
interests, for additional information.
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 $4 million
($3 million, net of tax) at December 31, 2023. 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 the 40 per cent non-controlling equity interest in Columbia Gas and Columbia Gulf upon its sale on October 4, 2023. Refer
to Note 24, Non-controlling interests, for additional information.
202 | TC Energy Consolidated Financial Statements 2023
Details about reclassifications out of AOCI into the Consolidated statement of income were as follows:
year ended December 31
Amounts Reclassified
From AOCI
(millions of Canadian $)
2023
2022
2021
Affected Line Item in the Consolidated
Statement of Income1
Cash flow hedges
Commodities
Interest rate
Pension and other post-retirement benefit plan
adjustments
Amortization of actuarial gains (losses)
Settlement gain (loss)
Equity investments
Equity income (loss)
(85)
(12)
(97)
23
(74)
—
—
—
—
—
22
(6)
16
(47)
(16)
(63)
21
(42)
(22)
(46)
(68)
Revenues (Power and Energy Solutions)
Interest expense
Total before tax
13
Income tax (expense) recovery
(55)
Net of tax
(11)
(22)
Plant operating costs and other2
2
(9)
3
(6)
4
(1)
3
2
Plant operating costs and other2
(20)
Total before tax
6
Income tax (expense) recovery
(14)
Net of tax
(37)
Income (loss) from equity investments
9
Income tax (expense) recovery
(28)
Net of tax
1
2
Amounts in parentheses indicate expenses to the Consolidated statement of income.
These AOCI components are included in the computation of net benefit cost. Refer to Note 28, Employee post-retirement benefits, for additional information.
TC Energy Consolidated Financial Statements 2023 | 203
28. EMPLOYEE POST-RETIREMENT BENEFITS
The Company sponsors DB Plans for certain employees. Pension benefits provided under the DB Plans are generally based on
years of service and highest average earnings over three to five consecutive years of employment. Effective January 1, 2019,
there were certain amendments made to the Canadian DB Plan for new members. Subsequent to that date, and up until the
Canadian DB Plan was closed to new entrants on January 1, 2024, 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 for employees hired
prior to January 1, 2019. In 2023, TC Energy announced a plan amendment to the Canadian OPEB Plan. This plan will be closed for
any eligible active employees that do not retire by December 31, 2024. All active employees who no longer meet the eligibility
for the OPEB Plan will be eligible for a new plan that provides an annual health spending account to retirees and their
dependents from retirement to age 65.
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 was approximately nine years at
December 31, 2023 (2022 – nine years; 2021 – 10 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 12 years at December 31, 2023 (2022 – 12 years and 2021 – 11 years). In
2023, the Company expensed $64 million (2022 – $64 million and 2021 – $58 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
2023
28
9
64
101
2022
78
8
64
150
2021
105
8
58
171
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. Total letters of credit provided to the Canadian DB plan at
December 31, 2023 was $244 million (2022 – $322 million; 2021 – $322 million).
The most recent actuarial valuation of the pension plans for funding purposes was as at January 1, 2023 and the next required
valuation is at January 1, 2024.
In 2022, a settlement occurred for the U.S. DB Plan as a result of lump sum payments made during the year. The impact of the
settlement was determined using actuarial assumptions consistent with those employed at December 31, 2022. The settlement
gain decreased the U.S. DB Plan's unrealized actuarial gain by $2 million which was included in OCI, and was recorded in net
benefit cost in 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 in 2021, a settlement and curtailment occurred for the U.S. DB Plan and a
curtailment occurred in the U.S. OPEB Plan. The impact of these amounts was 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. The curtailment loss decreased the OPEB Plan's unrealized actuarial gain
by $3 million which was included in OCI and increased the OPEB Plan obligation by $3 million, resulting in no adjustment to net
benefit cost in 2021.
204 | TC Energy Consolidated Financial Statements 2023
The Company's funded status was comprised of the following:
at December 31
Pension
Benefit Plans
Other Post-Retirement
Benefit Plans
(millions of Canadian $)
2023
2022
2023
2022
Change in Benefit Obligation1
Benefit obligation – beginning of year
Service cost
Interest cost
Employee contributions
Benefits paid
Actuarial (gain) loss
Foreign exchange rate changes
Benefit obligation – end of year
Change in Plan Assets
Plan assets at fair value – beginning of year
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
3,081
4,027
93
158
7
(185)
219
(17)
3,356
3,481
385
28
7
(185)
(19)
3,697
341
145
125
6
(324)
(949)
51
3,081
4,145
(483)
78
6
(324)
59
3,481
400
310
3
16
2
(44)
2
(4)
285
354
24
9
2
(23)
(8)
358
73
419
5
13
2
(24)
(120)
15
310
431
(89)
8
2
(24)
26
354
44
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.
The Company reduced letters of credit by $78 million in the Canadian DB Plan (2022 – nil) for funding purposes.
The actuarial loss realized on the defined benefit plan obligation is primarily attributable to a decrease in the weighted average
discount rate from 5.15 per cent in 2022 to 4.75 per cent in 2023.
The actuarial loss realized on the OPEB Plan obligation is primarily due to a decrease in the weighted average discount rate from
5.45 per cent in 2022 to 5.10 per cent in 2023.
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
Pension
Benefit Plans
Other Post-Retirement
Benefit Plans
(millions of Canadian $)
2023
2022
2023
Other long-term assets (Note 16)
Accounts payable and other
Other long-term liabilities (Note 19)
341
—
—
341
400
—
—
400
177
(7)
(97)
73
2022
163
(8)
(111)
44
TC Energy Consolidated Financial Statements 2023 | 205
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
2023
2022
—
—
—
—
—
—
2023
(104)
—
(104)
2022
(119)
—
(119)
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
2023
(3,090)
3,697
607
2022
(2,880)
3,481
601
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, 2023 and December 31, 2022.
The Company pension plans' weighted average asset allocations and target allocations by asset category were as follows:
at December 31
Fixed income securities
Equity securities
Other investments
Percentage of
Plan Assets
2023
41%
44%
15%
100%
2022
38%
44%
18%
100%
Target
Allocations
2023
30% to 50%
30% to 55%
10% to 25%
Fixed income and equity securities include the Company's debt and common shares as follows:
at December 31
(millions of Canadian $)
Fixed income securities
Equity securities
2023
2022
7
2
7
3
Percentage of
Plan Assets
2023
0.2%
0.1%
2022
0.2%
0.1%
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 may be used to hedge certain liabilities.
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.
206 | TC Energy Consolidated Financial Statements 2023
The following table presents plan assets for DB Plans and OPEB Plans measured at fair value, which have been categorized into
the three categories based on a fair value hierarchy. Refer to Note 29, Risk management and financial instruments, for additional
information.
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 $)
2023
2022
2023
2022
2023
2022
2023
2022
2023
2022
Asset Category
Cash and Cash Equivalents
68
55
1
1
69
56
2
1
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
Net forward contracts
Other Investments:
Real estate
Infrastructure
Private equity funds
121
965
167
—
54
—
—
—
—
185
—
312
4
—
43
—
—
—
—
117
897
172
—
50
—
—
—
—
177
—
345
5
—
36
—
—
—
—
Funds held on deposit
138
144
—
—
187
74
140
266
314
16
143
—
—
172
75
127
221
249
12
108
240
158
1
74
11
83
17
1
94
6
58
1
(131)
(78)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
121
965
354
74
194
266
314
16
143
425
1
386
15
83
60
117
897
344
75
177
221
249
12
108
335
1
439
11
58
37
(131)
(78)
—
—
—
—
—
—
—
—
283
269
10
—
336
296
—
—
283
269
10
138
336
296
—
144
3
24
9
2
5
7
8
—
4
10
—
10
—
2
1
(4)
7
7
—
3
3
24
9
2
5
6
6
—
3
9
—
11
—
1
1
(2)
9
8
—
4
2,057
1,998
1,436
1,205
562
632
4,055
3,835
100
100
The following table presents the net change in the Level III fair value category:
(millions of Canadian $, pre-tax)
Balance at December 31, 2021
Purchases and sales
Realized and unrealized gains (losses)
Balance at December 31, 2022
Purchases and sales
Realized and unrealized gains (losses)
Balance at December 31, 2023
565
52
15
632
(76)
6
562
TC Energy Consolidated Financial Statements 2023 | 207
In 2024, the Company's expects to make funding contributions of $6 million for the other post-retirement benefit plans,
approximately $70 million for the savings plans and DC Plans and no contributions for the DB Plans. The Company is not
expecting to issue any additional letters of credit for the funding of solvency requirements to the Canadian DB plan in 2024.
The following are estimated future benefit payments, which reflect expected future service:
at December 31
(millions of Canadian $)
2024
2025
2026
2027
2028
2029 to 2033
Pension Benefits
Other Post-Retirement
Benefits
204
207
211
214
216
1,127
23
23
23
22
22
104
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, 2023. 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
2023
4.75%
3.20%
2022
5.15%
3.30%
2023
5.10%
—
2022
5.45%
—
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
2023
2022
2021
2023
2022
2021
Discount rate
Expected long-term rate of return on plan assets
Rate of compensation increase
5.15%
6.45%
3.25%
3.05%
6.10%
3.00%
2.70%
6.15%
2.60%
5.45%
4.50%
—
3.10%
3.25%
—
2.80%
3.00%
—
208 | TC Energy Consolidated Financial Statements 2023
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 and asset mix 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 5.95 per cent weighted-average annual rate of increase in the per capita cost of covered health care benefits was assumed for
2024 measurement purposes. The rate was assumed to decrease gradually to 4.80 per cent by 2030 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
2023
93
158
(234)
—
—
—
—
(76)
17
2022
145
125
(239)
10
12
—
(2)
(94)
51
2021
171
119
(234)
23
27
(5)
(2)
(72)
99
2023
2022
2021
3
5
6
16
(16)
—
—
—
—
—
3
13
(14)
1
1
—
—
1
6
12
(13)
2
2
—
—
3
9
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
2023
2022
2021
(millions of Canadian $)
Pension
Benefits
Other Post-
Retirement
Benefits
Pension
Benefits
Other Post-
Retirement
Benefits
Pension
Benefits
Other Post-
Retirement
Benefits
Net loss
71
6
38
24
147
5
Pre-tax amounts recognized in OCI were as follows:
year ended December 31
2023
2022
2021
(millions of Canadian $)
Amortization of net gain (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
—
—
—
33
33
—
—
—
(18)
(18)
(10)
—
2
(101)
(109)
(1)
—
—
20
19
(23)
—
2
(190)
(211)
(2)
3
—
(18)
(17)
TC Energy Consolidated Financial Statements 2023 | 209
29. RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Risk Management Overview
TC Energy has exposure to various financial risks 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. TC Energy's risks are managed within limits that are established by the
Company's Board, implemented by senior management and monitored by the Company's risk management, internal audit and
business segment groups. The Board's Audit Committee oversees how management monitors compliance with 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 demand for 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.
The physical and transition risks related to climate change could impact commodity prices and fossil fuel supply and demand
dynamics which could affect the Company's financial performance. TC Energy evaluates the financial resilience of the Company’s
asset portfolio against a range of future pricing and supply and demand outcomes as part of the Company’s strategic planning
process. TC Energy’s exposure to climate change-related transition risks 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. The Company factors physical and
transition risks into capital planning, financial risk management and operational activities and is working towards reducing the
GHG emissions intensity of existing operations.
210 | TC Energy Consolidated Financial Statements 2023
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.
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 portion of the Company's Mexico Natural Gas Pipelines monetary assets and liabilities are peso-denominated, while
TC Energy's Mexico operations' financial results are denominated in 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. In addition, foreign exchange gains or losses calculated for Mexico income tax purposes on the revaluation of
U.S. dollar‑denominated monetary assets and liabilities result in a peso‑denominated income tax exposure for these entities,
leading to fluctuations in Income from equity investments and Income tax expense. These exposures are actively managed using
foreign exchange derivatives, although some unhedged exposure remains.
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 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
2023
2022
(millions of Canadian $, unless otherwise noted)
U.S. dollar foreign exchange options (maturing 2024)
U.S. dollar cross-currency interest rate swaps (maturing 2024 to 2025)3
Fair
Value1,2
Notional
Amount
Fair
Value1,2
8
2
10
US 1,000
US 200
US 1,200
(22)
(5)
(27)
Notional
Amount
US 3,600
US 300
US 3,900
1
2
3
Fair value equals carrying value.
No amounts have been excluded from the assessment of hedge effectiveness.
In 2023, Net income (loss) includes net realized gains of less than $1 million (2022 – 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)
2023
2022
Notional amount
Fair value
27,800 (US 21,100)
32,500 (US 24,000)
26,600 (US 20,200)
30,800 (US 22,700)
TC Energy Consolidated Financial Statements 2023 | 211
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, net investment in leases and certain contract
assets in Mexico.
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
• the competitive position of the Company's assets and the demand for the Company's services
• 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 reasonable and supportable
forecasts to determine any impairment, which is recognized in Plant operating costs and other.
The Company’s net investment in leases and certain contract assets are financial assets subject to ECL. TC Energy’s methodology
for assessing the ECL regarding these financial assets includes consideration of the probability of default (the probability that the
customer will default on its obligation), the loss given default (the economic loss as a proportion of the financial asset balance in
the event of a default) and the exposure at default (the financial asset balance at the time of a hypothetical default) with
one-year forward-looking information that includes assumptions for future macroeconomic conditions under three
probability-weighted future scenarios.
The macroeconomic factors considered most relevant to the Company's net investment in leases and contract assets include
Mexico's GDP, Mexico's government debt to GDP and Mexico's inflation. The ECL amount is updated at each reporting date to
reflect changes in assumptions and forecasts for future economic conditions.
For the year ended December 31, 2023, the Company recorded a $73 million ECL recovery (2022 – an expense of $149 million;
2021 – nil) with respect to the net investment in leases associated with the in-service TGNH pipelines and a $10 million ECL
recovery (2022 – $14 million expense; 2021 – nil) for contract assets related to certain other Mexico natural gas pipelines.
Other than the ECL provision noted above, the Company had no significant credit losses at December 31, 2023 and 2022. At
December 31, 2023 and 2022, there were no significant credit risk concentrations and no significant amounts past due or
impaired.
TC Energy has significant credit and performance exposure to financial institutions that 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. TC Energy's portfolio of financial sector exposure consists
primarily of highly-rated investment grade, systemically important financial institutions.
Non-Derivative Financial Instruments
Fair value of non-derivative financial instruments
Available-for-sale assets are recorded at fair value which is calculated using quoted market prices where available. Certain
non-derivative financial instruments included in Cash and cash equivalents, Accounts receivable, Other current assets, Restricted
investments, Net investment in leases, 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 of the fair value hierarchy.
Credit risk has been taken into consideration when calculating the fair value of non-derivative financial instruments.
212 | TC Energy Consolidated Financial Statements 2023
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 21)1,2
Junior subordinated notes (Note 22)
2023
2022
Carrying
Amount
(52,914)
(10,287)
(63,201)
Fair
Value
Carrying
Amount
(52,815)
(9,217)
(62,032)
(41,543)
(10,495)
(52,038)
Fair
Value
(39,505)
(9,415)
(48,920)
1
2
Long-term debt is recorded at amortized cost, except for US$2.0 billion (2022 – US$1.6 billion) that is attributed to hedged risk and recorded at fair value.
Net income (loss) for 2023 included unrealized losses of $53 million (2022 – unrealized gains of $64 million) for fair value adjustments attributable to the
hedged interest rate risk associated with interest rate swap fair value hedging relationships on US$2.0 billion of long-term debt at December 31, 2023
(2022 – US$1.6 billion). There were no other unrealized gains or losses from fair value adjustments to the non-derivative financial instruments.
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
2023
2022
LMCI Restricted
Investments
Other Restricted
Investments1
LMCI Restricted
Investments
Other Restricted
Investments1
1
8
1,340
102
883
2,334
35
291
—
—
—
326
—
—
1,153
77
749
1,979
54
106
—
—
—
160
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
2023
2022
2021
(millions of Canadian $)
Net unrealized gains (losses)
Net realized gains (losses)3
LMCI
Restricted
Investments1
Other
Restricted
Investments2
LMCI
Restricted
Investments1
Other
Restricted
Investments2
LMCI
Restricted
Investments1
Other
Restricted
Investments2
190
(34)
13
—
(244)
(32)
(7)
—
45
3
(2)
—
1
2
3
Unrealized and realized gains (losses) arising from changes in the fair value of LMCI restricted investments impact the subsequent amounts to be collected
through tolls to cover future pipeline abandonment costs. As a result, the Company records these gains and losses as regulatory liabilities or regulatory assets.
Unrealized and realized gains (losses) on other restricted investments are included in Interest income and other in the Company's Consolidated statement of
income.
Realized gains (losses) on the sale of LMCI restricted investments are determined using the average cost basis.
Derivative Instruments
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.
TC Energy Consolidated Financial Statements 2023 | 213
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 refunded or recovered 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 rate payers in subsequent years when the derivative settles.
Balance sheet presentation of derivative instruments
The balance sheet classification of the fair value of derivative instruments was as follows:
at December 31, 2023
(millions of Canadian $)
Other current assets (Note 9)
Commodities2
Foreign exchange
Other long-term assets (Note 16)
Commodities2
Foreign exchange
Interest rate
Total Derivative Assets
Accounts payable and other (Note 18)
Commodities2
Foreign exchange
Interest rate
Other long-term liabilities (Note 19)
Commodities2
Foreign exchange
Interest rate
Total Derivative Liabilities
Total Derivatives
Cash Flow
Hedges
Fair Value
Hedges
Net
Investment
Hedges
Held for
Trading
Total Fair
Value of
Derivative
Instruments1
9
—
9
3
—
—
3
12
(1)
—
—
(1)
—
—
—
—
(1)
11
—
—
—
—
—
36
36
36
—
—
(18)
(18)
—
—
(29)
(29)
(47)
(11)
—
10
10
—
—
—
—
10
—
—
—
—
—
—
—
—
—
10
1,195
71
1,266
86
30
—
116
1,382
1,204
81
1,285
89
30
36
155
1,440
(1,110)
(1,111)
(14)
—
(14)
(18)
(1,124)
(1,143)
(75)
(2)
—
(77)
(1,201)
181
(75)
(2)
(29)
(106)
(1,249)
191
1
2
Fair value equals carrying value.
Includes purchases and sales of power, natural gas and liquids.
214 | TC Energy Consolidated Financial Statements 2023
The balance sheet classification of the fair value of derivative instruments was as follows:
at December 31, 2022
(millions of Canadian $)
Other current assets (Note 9)
Commodities2
Foreign exchange
Other long-term assets (Note 16)
Commodities2
Foreign exchange
Interest rate
Total Derivative Assets
Accounts payable and other (Note 18)
Commodities2
Foreign exchange
Interest rate
Other long-term liabilities (Note 19)
Commodities2
Foreign exchange
Interest rate
Total Derivative Liabilities
Total Derivatives
Cash Flow
Hedges
Fair Value
Hedges
Net
Investment
Hedges
Held for
Trading
Total Fair
Value of
Derivative
Instruments1
—
—
—
—
—
—
—
—
(72)
—
—
(72)
(2)
—
—
(2)
(74)
(74)
—
—
—
—
—
12
12
12
—
—
(26)
(26)
—
—
(50)
(50)
(76)
(64)
—
6
6
—
2
—
2
8
—
(31)
—
(31)
—
(4)
—
(4)
(35)
(27)
597
11
608
62
15
—
77
685
(584)
(158)
—
(742)
(75)
(20)
—
(95)
(837)
(152)
597
17
614
62
17
12
91
705
(656)
(189)
(26)
(871)
(77)
(24)
(50)
(151)
(1,022)
(317)
1
2
Fair value equals carrying value.
Includes purchases and sales of power, natural gas and liquids.
The majority of derivative instruments held for trading have been entered into for risk management purposes and all are subject
to the Company's risk management strategies, policies and limits. These include derivatives that have not been designated as
hedges or do not qualify for hedge accounting treatment but have been entered into as economic hedges to manage the
Company's exposures to market risk.
Derivatives in fair value hedging relationships
The following table details amounts recorded on the Consolidated balance sheet in relation to cumulative adjustments for fair
value hedges included in the carrying amount of the hedged liabilities:
at December 31
(millions of Canadian $)
Long-term debt
Carrying Amount
Fair Value Hedging Adjustments1
2023
(2,630)
2022
(2,101)
2023
11
2022
64
1
At December 31, 2023 and 2022, adjustments for discontinued hedging relationships included in these balances were nil.
TC Energy Consolidated Financial Statements 2023 | 215
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, 2023
Net sales (purchases)1,2
Millions of U.S. dollars
Millions of Mexican pesos
Maturity dates
Power
Natural Gas
Liquids
Foreign
Exchange
Interest Rate
9,209
—
—
50
—
—
(7)
—
—
—
4,978
20,000
—
2,000
—
2024-2044
2024-2029
2024
2024-2026
2030-2034
1
2
Volumes for power, natural gas and liquids derivatives are in GWh, Bcf and MMBbls, respectively.
In 2023, the Company entered into contracts to sell 50 MW of power commencing in 2025 with terms ranging from 15 to 20 years and provided from specified
renewable sources in the Province of Alberta.
at December 31, 2022
Net sales (purchases)1
Millions of U.S. dollars
Millions of Mexican pesos
Maturity dates
Power
Natural Gas
Liquids
Foreign
Exchange
Interest Rate
673
—
—
(96)
—
—
11
—
—
—
5,997
9,747
—
1,600
—
2023-2026
2023-2027
2023-2024
2023-2026
2030-2032
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
Unrealized gains (losses) in the year
Commodities
Foreign exchange (Note 23)
Realized gains (losses) in the year
Commodities
Foreign exchange (Note 23)
Derivative Instruments in Hedging Relationships2
Realized gains (losses) in the year
Commodities
Interest rate
2023
2022
2021
96
246
811
155
(2)
(43)
14
(149)
759
(2)
(73)
(3)
9
(203)
287
240
(44)
(32)
1
2
Realized and unrealized gains (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 (losses) on foreign exchange held-for-trading derivative instruments are included on a net basis in Foreign exchange
(gains) losses, net.
In 2023, there were no gains or losses included in Net Income (loss) relating to discontinued cash flow hedges where it was probable that the anticipated
transaction would not occur (2022 – nil; 2021 – realized loss of $10 million).
216 | TC Energy Consolidated Financial Statements 2023
Derivatives in cash flow hedging relationships
The components of OCI (Note 27) 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)
Gains (losses) in fair value of derivative instruments recognized in OCI1
Commodities
Interest rate
2023
2022
2021
—
—
—
(94)
36
(58)
(35)
22
(13)
1
No amounts have been excluded from the assessment of hedge effectiveness.
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 gains (losses) on derivative instruments from AOCI to
Net income (loss)2,3
Commodity contracts4
Interest rate contracts1
2023
2022
2021
(98)
(43)
(85)
(12)
(30)
(1)
(47)
(16)
—
—
(22)
(46)
1
2
3
4
Presented within Interest expense in the Consolidated statement of income.
Refer to Note 27, Other comprehensive income (loss) and accumulated other comprehensive income (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 Energy Solutions) 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.
TC Energy Consolidated Financial Statements 2023 | 217
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, 2023
(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
1,293
111
36
1,440
(1,186)
(16)
(47)
(1,249)
(1,099)
(16)
(5)
(1,120)
1,099
16
5
1,120
194
95
31
320
(87)
—
(42)
(129)
1
Amounts available for offset do not include cash collateral pledged or received.
at December 31, 2022
(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
659
34
12
705
(733)
(213)
(76)
(1,022)
(591)
(33)
(4)
(628)
591
33
4
628
68
1
8
77
(142)
(180)
(72)
(394)
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 $149 million and letters of
credit of $83 million at December 31, 2023 (2022 – $138 million and $68 million, respectively) to its counterparties. At
December 31, 2023, the Company held less than $1 million in cash collateral and $15 million in letters of credit (2022 – less than
$1 million and $10 million, 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, 2023, the aggregate fair value of all derivative instruments with
credit-risk-related contingent features that were in a net liability position was $3 million (2022 – $19 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, 2023, 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.
218 | TC Energy Consolidated Financial Statements 2023
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
Level III
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.
This category includes long-dated commodity transactions in certain markets where liquidity is low. The Company uses the
most observable inputs available or alternatively long-term broker quotes or negotiated commodity prices that have been
contracted for under similar terms in determining an appropriate estimate of these transactions. Where appropriate, these
long-dated prices are discounted to reflect the expected pricing from the applicable markets.
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, 2023
(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
Inputs
(Level II)1
Significant
Unobservable
Inputs
(Level III)1
1,054
—
—
(1,002)
—
—
52
229
111
36
(163)
(16)
(47)
150
10
—
—
(21)
—
—
(11)
Total
1,293
111
36
(1,186)
(16)
(47)
191
1
There were no transfers from Level II to Level III for the year ended December 31, 2023.
In 2023, the Company entered into contracts to sell 50 MW of power commencing in 2025 with terms ranging from 15 to 20
years and provided from specified renewable sources in the Province of Alberta. The fair value of these contracts is classified in
Level III of the fair value hierarchy and is based on the assumption that the contract volumes will be sourced approximately
80 per cent from wind generation, 10 per cent from solar generation and 10 per cent from the market.
TC Energy Consolidated Financial Statements 2023 | 219
at December 31, 2022
(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
Inputs
(Level II)1
Significant
Unobservable
Inputs
(Level III)1
515
—
—
(478)
—
—
37
142
34
12
(242)
(213)
(76)
(343)
2
—
—
(13)
—
—
(11)
Total
659
34
12
(733)
(213)
(76)
(317)
1
There were no transfers from Level II to Level III for the year ended December 31, 2022.
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
Net gains (losses) included in Net income (loss)
Net gains (losses) included in OCI
Transfers out of Level III
Settlements
Balance at End of Year1
2023
2022
(11)
(2)
—
2
—
(11)
(6)
(10)
(3)
7
1
(11)
1
Revenues include unrealized losses of $2 million attributed to derivatives in the Level III category that were still held at December 31, 2023 (2022 – unrealized
losses of $10 million).
30. CHANGES IN OPERATING WORKING CAPITAL
year ended December 31
(millions of Canadian $)
(Increase) decrease in Accounts receivable
(Increase) decrease in Inventories
(Increase) decrease in Other current assets
Increase (decrease) in Accounts payable and other
Increase (decrease) in Accrued interest
(Increase) Decrease in Operating Working Capital
2023
(394)
(56)
618
(206)
245
207
2022
(575)
(190)
118
(83)
91
(639)
2021
(925)
(93)
(141)
890
(18)
(287)
220 | TC Energy Consolidated Financial Statements 2023
31. ACQUISITIONS AND DISPOSITIONS
U.S. Natural Gas Pipelines
Disposition of Equity Interest
On October 4, 2023, the Company completed the sale of a 40 per cent non-controlling equity interest in Columbia Gas and
Columbia Gulf for $5.3 billion (US$3.9 billion). The sale was accounted for as an equity transaction of which $9.5 billion
(US$6.9 billion) was recorded as Non-controlling interests to reflect the 40 per cent change in the Company’s ownership interest
in Columbia Gulf and Columbia Gas. The difference between the non-controlling ownership interest recognized and the
consideration received was recorded as a reduction to Additional paid-in capital of $3.5 billion (US$3.0 billion), net of tax and
transaction costs.
Liquids Pipelines
Northern Courier
In November 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 sale of assets in the Consolidated statement of income.
Power and Energy Solutions
Texas Wind Farms
On March 15, 2023, TC Energy closed the acquisition of 100 per cent of the Class B Membership Interests in the 155 MW Fluvanna
Wind Farm located in Scurry County, Texas for US$99 million, before post-closing adjustments. On June 14, 2023, the Company
closed the acquisition of 100 per cent of the Class B Membership Interests in the 148 MW Blue Cloud Wind Farm located in Bailey
County, Texas for US$125 million, before post-closing adjustments. The Fluvanna and Blue Cloud assets have tax equity investors
that own 100 per cent of the Class A Membership Interests, to which a percentage of earnings, tax attributes and cash flows are
allocated.
32. 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 2023 were $397 million (2022 – $362 million; 2021 – $239 million).
The Company has entered into PPAs with solar and wind-power generating facilities ranging from 2024 to 2038 that require the
purchase of generated energy and associated environmental attributes. At December 31, 2023, the total planned capacity
secured under the PPAs is approximately 800 MW with the generation subject to operating availability and capacity factors.
These PPAs do not meet the definition of a lease or derivative. Future payments and their timing cannot be reasonably estimated
as they are dependent on when certain underlying facilities are placed into service and the amount of energy generated. Certain
of these purchase commitments have offsetting sale PPAs for all or a portion of the related output from the facility.
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, 2023, TC Energy had approximately $2.1 billion of capital
expenditure commitments, primarily consisting of:
• $0.3 billion for its U.S. natural gas pipelines, primarily related to construction costs associated with ANR and other pipeline
projects
• $1.3 billion for its Mexico natural gas pipelines related to construction of the Southeast Gateway pipeline.
Contingencies
TC Energy is subject to laws and regulations governing environmental quality and pollution control. At December 31, 2023, the
Company had accrued approximately $19 million (2022 – $20 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 Consolidated Financial Statements 2023 | 221
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. The Company assesses all legal matters on an ongoing basis, including those of its equity
investments, to determine if they meet the requirements for disclosure or accrual of a contingent loss. With the potential
exception of the matters discussed below, for which the claims are material and there is a reasonable possibility of loss, but have
not been assessed as probable and a reasonable estimate of loss cannot be made, it is the opinion of management that the
ultimate resolution of such proceedings and actions will not have a material impact on the Company's consolidated financial
position or results of operations.
Coastal GasLink LP
Coastal GasLink LP is in dispute with a number of contractors related to construction of the Coastal GasLink pipeline. Material
legal matters pertaining to Coastal GasLink are summarized as follows:
SA Energy Group
Coastal GasLink LP is in arbitration with SA Energy Group (SAEG), which is one of the prime construction contractors on the
Coastal GasLink pipeline. While still engaged as prime contractor, SAEG filed a request to arbitrate in February 2022, seeking
damages for incremental costs resulting from alleged project delays. In order to mitigate cost, schedule and environmental risk
while the project was in active construction, Coastal GasLink LP advanced without prejudice payments to SAEG which Coastal
GasLink LP now seeks to recover via set off. By agreement among the parties, the scope of the arbitration is limited to damages
for project work completed prior to December 29, 2022. In November 2023, SAEG filed materials purporting to seek damages in
excess of $1.1 billion. Coastal GasLink LP continues to dispute the merits of SAEG’s claims and to assert its right to set off.
Arbitration is scheduled to proceed in late 2024. At December 31, 2023, the final outcome of this matter cannot be reasonably
estimated.
Pacific Atlantic Pipeline Construction Ltd.
Coastal GasLink LP is in arbitration with one of its previous prime contractors, Pacific Atlantic Pipeline Construction Ltd. (PAPC).
Coastal GasLink LP terminated its contract with PAPC for cause, due to the failure of PAPC to complete work as scheduled and
made a demand on the parental guarantee for payment of the guaranteed obligations. Following Coastal GasLink LP’s demand
on the guarantee, in August 2022, PAPC initiated arbitration. As of November 2023, PAPC purports to seek at least $428 million in
damages for wrongful termination for cause, termination damages and payments alleged to be outstanding. Coastal GasLink LP
disputes the merits of PAPC’s claims and has counterclaimed against PAPC and its parent company and guarantor, Bonatti S.p.A.,
citing delays and failures by PAPC to perform and manage work in accordance with the terms of its contract. Coastal GasLink LP
estimates its damages to be $1.2 billion. Arbitration is scheduled to proceed in late 2024. At December 31, 2023, the final
outcome of this matter cannot be reasonably estimated.
Separately, Coastal GasLink LP has sought to draw down on a $117 million irrevocable standby letter of credit (LOC) provided by
PAPC based on a bona fide belief that Coastal GasLink LP’s damages are in excess of the face value of the LOC. PAPC has applied
for an injunction restraining Coastal GasLink LP from drawing on the LOC pending the completion of the arbitration between
Coastal GasLink LP, PAPC, and Bonatti, which is the subject of further court proceedings.
Keystone XL
In 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.
In 2022, the International Centre for Settlement of Investment Disputes formally constituted a tribunal to hear TC Energy's
request for arbitration under NAFTA. In April 2023, the tribunal suspended the proceeding, granting a request from the U.S.
Department of State to decide the jurisdictional grounds of the case as a preliminary matter. A hearing on the jurisdictional
matter is set to occur in second quarter of 2024. In April 2023, the Government of Alberta filed its own request for arbitration,
which will proceed separately from the Company's claim. Termination activities undertaken in 2023, including asset dispositions
and preservation, will continue through the first half of 2024. The Company will continue to coordinate with regulators,
stakeholders and Indigenous groups to meet its environmental and regulatory commitments.
222 | TC Energy Consolidated Financial Statements 2023
2016 Columbia Pipeline Acquisition Lawsuit
In 2023, the Delaware Chancery Court issued its decision in the class action lawsuit commenced by former shareholders of
Columbia Pipeline Group Inc. (CPG) related to the acquisition of CPG by TC Energy in 2016. The Court found that the former CPG
executives breached their fiduciary duties, that the former CPG Board breached its duty of care in overseeing the sale process
and that TC Energy aided and abetted those breaches. The Court awarded US$1 per share in damages to the plaintiffs and total
damages, which is presently estimated at US$400 million plus statutory interest. Post-trial briefing and argument has concluded
and a decision from the Court allocating liability as between TC Energy and the CPG executives is expected sometime in the first
half of 2024. Until the allocation of damages is known, the amount that TC Energy is liable for cannot be reasonably estimated,
therefore, the Company has not accrued a provision for this claim at December 31, 2023. Management expects to proceed with
an appeal following the Court’s determination of total damages and TC Energy’s allocated share.
Guarantees
TC Energy and its partner on the Sur de Texas pipeline, IEnova, have jointly guaranteed the financial performance of the entity
which owns the pipeline. Such agreements include a guarantee and a letter of credit which are primarily related to the delivery
of natural gas.
TC Energy and its joint venture partner on Bruce Power, BPC Generation Infrastructure Trust, have each severally guaranteed
certain contingent financial obligations of Bruce Power related to a lease agreement and contractor and supplier services.
The Company and its partners in certain other jointly-owned entities have either: i) jointly and severally; ii) jointly or
iii) severally guaranteed the financial performance of these entities. Such agreements include guarantees and letters of credit
which are primarily related to construction services and the payment of liabilities. For certain of these entities, any payments
made by TC Energy under these guarantees in excess of its ownership interest are to be reimbursed by its partners.
The carrying value of these guarantees has been recorded in Other long-term liabilities on the Consolidated balance sheet.
Information regarding the Company’s guarantees were as follows:
at December 31
(millions of Canadian $)
Term
Sur de Texas
Bruce Power
Renewable to 2053
Renewable to 2065
Other jointly-owned entities
to 2043
2023
Potential
Exposure1
Carrying Value
2022
Potential
Exposure1
Carrying Value
97
88
80
265
—
—
3
3
100
88
81
269
—
—
3
3
1
TC Energy's share of the potential estimated current or contingent exposure.
TC Energy Consolidated Financial Statements 2023 | 223
33. VARIABLE INTEREST ENTITIES
Consolidated VIEs
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
Regulatory Assets
Goodwill
LIABILITIES
Current Liabilities
Accounts payable and other
Accrued interest
Current portion of long-term debt
Regulatory Liabilities
Other Long-Term Liabilities
Deferred Income Tax Liabilities
Long-Term Debt
20231
2022
190
476
90
49
805
27,649
823
12
439
29,728
1,135
210
28
1,373
280
56
22
11,388
13,119
60
98
32
14
204
3,997
748
—
449
5,398
234
18
31
283
78
1
16
2,136
2,514
1
Columbia Gas and Columbia Gulf were classified as a VIE upon TC Energy's sale of a 40 per cent non-controlling equity interest on October 4, 2023. Refer to
Note 24, Non-controlling interests, and Note 31, Acquisitions and dispositions, for additional information.
224 | TC Energy Consolidated Financial Statements 2023
Non-Consolidated VIEs
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 Exposure
Equity investments
Bruce Power
Pipeline equity investments and other
Off-Balance Sheet Exposure1
Bruce Power
Coastal GasLink2
Pipeline equity investments
Maximum exposure to loss
2023
2022
6,241
1,411
1,538
855
58
10,103
5,783
1,148
2,025
3,300
58
12,314
1
2
Includes maximum potential exposure to guarantees and future funding commitments.
TC Energy is contractually obligated to fund the capital costs to complete the Coastal GasLink pipeline by funding the remaining equity requirements of Coastal
GasLink LP through incremental capacity on the subordinated loan agreement with Coastal GasLink LP until final costs are determined. At December 31, 2023,
the total capacity committed by TC Energy under this subordinated loan agreement was $3,375 million (December 31, 2022 – $1,262 million). In the year ended
December 31, 2023, $2,520 million was drawn on the subordinated loan, reducing the Company's funding commitment under the subordinated loan agreement
to $855 million. Refer to Note 8, Coastal GasLink, for further information.
In July 2022, the Company entered into revised project agreements relating to its investment in Coastal GasLink LP and
committed to make additional equity contributions, which did not result in a change in the Company’s 35 per cent ownership.
These revisions and additional equity contributions were determined to be a VIE reconsideration event for TC Energy’s
investment in Coastal GasLink LP. The Company performed a re-assessment of control and determined that Coastal GasLink LP
continued to meet the definition of a VIE in which the Company held a variable interest. The re-assessment further determined
that TC Energy was not the primary beneficiary of Coastal GasLink LP as the Company does not have the power, either explicit or
implicit through voting rights or otherwise, to direct the activities that most significantly impact the economic performance of
Coastal GasLink LP. Accordingly, the Company continued to account for its investment using the equity method of accounting.
Refer to Note 8, Coastal GasLink, for additional information.
TC Energy Consolidated Financial Statements 2023 | 225
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
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TRANSFER AGENT
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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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February 2024