UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
SCHEDULE 14A
Proxy Statement Pursuant to Section 14(a) of the
Securities Exchange Act of 1934 (Amendment No. )
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Columbia Pipeline Partners LP | ||
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TransCanada Corporation | ||
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Corporate Profile
January 2017
Forward Looking Information and Non-GAAP Measures
This presentation includes certain forward looking information, including future oriented financial information or financial outlook, which is intended to help current and
potential investors 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 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 presentation. Our forward-looking information in this presentation includes statements related to:
future dividend growth, the completion of the transactions contemplated by our agreements to sell our U.S. Northeast power assets and our agreement to acquire all of the
outstanding common units of Columbia Pipeline Partners LP (CPPL), the future growth of our Mexican natural gas pipeline business and our successful integration of
Columbia.
Our forward looking information is based on certain key assumptions and is subject to risks and uncertainties, including but not limited to: our ability to successfully
implement our strategic initiatives and whether they will yield the expected benefits including the expected benefits of the acquisition of Columbia and the expected growth
of our Mexican natural gas pipeline business, timing and completion of our planned asset sales, the operating performance of our pipeline and energy assets, economic and
competitive conditions in North America and globally, the availability and price of energy commodities and changes in market commodity prices, the amount of capacity
sold and rates achieved in our pipeline businesses, the amount of capacity payments and revenues we receive from our energy business, regulatory decisions and
outcomes, outcomes of legal proceedings, including arbitration and insurance claims, performance of our counterparties, changes in the political environment, changes in
environmental and other laws and regulations, construction and completion of capital projects, labour, equipment and material costs, access to capital markets, interest,
inflation and foreign exchange rates, weather, cyber security and technological developments. You can read more about these risks and others in our Quarterly Report to
shareholders dated November 1, 2016 and 2015 Annual Report filed with Canadian securities regulators and the SEC and available at www.transcanada.com.
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.
This presentation contains reference to certain financial measures (non-GAAP measures) that do not have any standardized meaning as prescribed by U.S. generally
accepted accounting principles (GAAP) and therefore may not be comparable to similar measures presented by other entities. These non-GAAP measures may include
Comparable Earnings, Comparable Earnings per Share, Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA), Funds Generated from Operations,
Comparable Funds Generated from Operations and Comparable Distributable Cash Flow (DCF). Reconciliations to the most closely related GAAP measures are included in
this presentation and in our Quarterly Report to shareholders dated November 1, 2016 filed with Canadian securities regulators and the SEC and available at
www.transcanada.com.
Additional Information
Additional Information and Where to Find it:
In connection with the proposed acquisition of the outstanding common units of Columbia Pipeline Partners LP (CPPL), CPPL has filed with the SEC a proxy statement with
respect to a special meeting of its unitholders to be convened to approve the transaction. The definitive proxy statement will be mailed to the unitholders of CPPL.
INVESTORS ARE URGED TO READ THE PROXY STATEMENT AND ANY OTHER RELEVANT DOCUMENTS WHEN THEY BECOME AVAILABLE, BECAUSE THEY WILL CONTAIN
IMPORTANT INFORMATION ABOUT THE TRANSACTION.
Investors will be able to obtain these materials, and other documents filed with the SEC free of charge at the SEC’s website, www.sec.gov. In addition, copies of the proxy
statement, when available, may be obtained free of charge by accessing CPPL’s website at www.columbiapipelinepartners.com. Investors may also read and copy any
reports, statements and other information filed by CPPL with the SEC, at the SEC public reference room at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at
1-800-SEC-0330 or visit the SEC’s website for further information on its public reference room.
Participants in the Merger Solicitation
Columbia Pipeline Group, Inc. (Columbia), an indirect wholly owned subsidiary of the Company, and certain of its directors, executive officers and other members of
management and employees may be deemed to be participants in the solicitation of proxies in respect of the transaction. Information regarding Columbia’s directors and
executive officers is available in its Current Report on Form 8-K filed with the SEC on July 1, 2016. Other information regarding the participants in the proxy solicitation and
a description of their direct and indirect interests, by security holdings or otherwise, may be obtained by reading the proxy statement and other relevant materials filed with
the SEC.
Key Themes
Proven Strategy – Low Risk Business Model
• Following monetization of U.S. Northeast Power business, over 95% of EBITDA
derived from regulated assets or long-term contracts
US$13 Billion Acquisition of Columbia Pipeline is Transformational
• Created one of North America’s largest regulated natural gas transmission
businesses and positions the company for long-term growth
Visible Growth Through 2020
• $26 billion of near-term growth projects
• Over $45 billion of commercially secured long-term projects
Dividend Poised to Grow Through 2020
• Expected annual dividend growth at upper end of 8 to 10%
Financial Discipline
• Finance long-term assets with long-term capital
• Value ‘A’ grade credit rating
• Corporate structure is simple and understandable
TransCanada Today
• One of North America’s Largest
Natural Gas Pipeline Networks
• 90,300 km (56,100 mi) of pipeline
• 664 Bcf of storage capacity
• 23 Bcf/d or approximately 27% of
continental demand
• Premier Liquids Pipeline System
• 4,300 km (2,700 mi) of pipeline
• 545,000 bbl/d or 20% of Western
Canadian exports
• One of the Largest Private Sector
Power Generators in Canada
• 17 power plants, 10,700 MW
• Market Capitalization of $52 billion
as of December 30, 2016
Portfolio of Complementary
Energy Infrastructure Assets
Risks are Known and Contained
• Volumetric
• Spot movements on southern portion of Keystone System and on Great Lakes
• Availability at Bruce Power
• Commodity
• Alberta cogens and non-regulated natural gas storage
• Substantially reduced exposure upon sale of U.S. Northeast power portfolio and
Alberta PPA terminations
• Counterparty
• Strong counterparty support on contracted assets
• Cost-of-service or regulated businesses with strong underlying fundamentals
• Interest Rates
• Largely fixed-rate debt financed (~90%) with long duration
• 17-year average term at 5.3% coupon rate
• Foreign Exchange
• U.S. dollar assets and income streams predominately hedged with U.S.
dollar-denominated debt
$26 Billion Visible Near-Term Capital Program
Illustrates the configuration of TransCanada’s near-term projects
Project
Estimated
Capital
Cost*
Expected
In-Service Date*
Columbia US7.7 2016-2020
NGTL System 6.0 2016-2020
Canadian Mainline 0.7 2016-2017
Mazatlan US0.4 2016
Topolobampo US1.0 2017
Tula US0.5 2017
Villa de Reyes US0.6 2018
Sur de Texas US1.3 2018
Grand Rapids 0.9 2017
Northern Courier 1.0 2017
Napanee 1.1 2018
Bruce Power Life Extension 1.2 2016-2020
Total Canadian Equivalent
(1.31 exchange rate)
CAD26.0
* TransCanada share in billions of dollars. Certain projects are subject to various conditions including
corporate and regulatory approvals.
Expected to Generate Significant
Growth in Earnings and Cash Flow
*Map to be
updated
'00 '01 '02 '03 '04 '05 '06 '07 '08 '09 '10 '11 '12 '13 '14 '15 '16 '17E '18E '19E '20E
Dividend Growth Outlook Through 2020
8 - 10%
CAGR
7%
CAGR
Expected Annual Dividend Growth at the Upper End of 8 to 10 Per Cent
Supported by Expected Growth in Earnings and Cash Flow
0.80
2.26
Columbia Pipeline Acquisition
• Transformational acquisition created one of
North America’s largest regulated natural gas
transmission businesses and provides a new
platform for growth
• Acquisition closed July 1, 2016
• Significant progress made in integrating
Columbia’s operations
• Expect to realize targeted US$250 million of
annualized benefits associated with acquisition
• Advancing US$7.7 billion portfolio of growth
initiatives and modernization investments
Illustrates the configuration of TransCanada’s natural gas pipeline network
Premium Natural Gas
Pipeline Network
Complements Our
Existing Assets
North American
Natural Gas Supply/Demand Balance
Source: TransCanada
0
10
20
30
40
50
60
70
80
90
100
110
120
130
2000 2005 2010 2015 2020 2025 2030
Supply
LNG Exports
Forecast History
Electric
Generation
Industrial
Commercial
Residential
NGV
Our Natural Gas Pipelines
Bcf/d
Incumbent Position in
North America’s Most Prolific,
Low Cost Natural Gas Basins
Columbia Pipeline Capital Program
* Columbia share in billions of U.S. dollars. Certain projects are subject to various conditions including regulatory approvals.
Asset Project
Estimated
Capital Cost
(US$)* FERC Status
Expected
In-Service
Gas
Modernization I 0.6 Approved 2016 – 2017
Modernization II 1.1 Approved 2018 - 2020
Leach XPress 1.4 Filed 2017
WB XPress 0.9 Filed 2018
Mountaineer XPress 2.0 Filed 2018
Gulf
Rayne XPress 0.4 Filed 2017
Cameron Access 0.3 Approved 2018
Gulf XPress 0.7 Filed 2018
Midstream Gibraltar 0.3 N/A 2017
T tal US7.7
Project Gas Flow Direction
and Capacity from the
Marcellus/Utica
(1) Shaded area represents the Marcellus and Utica shale gas production areas
NGTL System’s Unparalleled Position
• Primary transporter of WCSB supply with NIT hub
providing optionality and liquidity
• Averaging ~11.2 Bcf/d in 2016 year-to-date
• Significant new firm contracts
• Key connections to Alberta and export markets
• 2016/17 Revenue Requirement Settlement
• Includes a ROE of 10.1% on 40% deemed common
equity plus certain incentives
• $6.0 billion of new investments
• Expected in-service 2016 through 2020
• Includes $1.7 billion North Montney pipeline
• $4.0 billion approved by regulator
• Average investment base expected to increase
significantly from $6.7 billion in 2015
• Growth expected to continue
Footprint Uniquely Positioned to
Capture Supply & Demand Growth
Mexico – Solid Position and Growing
• Pipelines underpinned by long-term contracts
with the Comisión Federal de Electricidad (CFE)
• Guadalajara and Tamazunchale pipelines are
in-service
• Five new projects will increase investment in
Mexico to over US$5 billion
• US$1 billion Topolobampo pipeline substantially
completed and recognizing revenue
• US$400 million Mazatlan pipelines (physical
construction complete, awaiting natural gas to
commence in-service under the contract)
• US$500 million Tula pipeline (2017)
• US$550 million Villa de Reyes pipeline (2018)
• US$1.3 billion* Sur de Texas pipeline joint venture
with IEnova (2018)
• Once completed, portfolio is expected to
generate annual EBITDA of approximately
US$575 million up from US$181 million in 2015
* TransCanada share
Keystone - A Premier Crude Oil Pipeline System
• Critical crude oil system that transports
~20% of Western Canadian exports to key
U.S. refinery markets
• 545,000 bbl/d of long-haul, take or pay
contracts
• 15-year average remaining contract length
• Remain committed to advancing Keystone XL
*Comparable EBITDA is a non-GAAP measure. See the non-GAAP measures slide at the front of this
presentation for more information.
Northern Courier
• $1 billion capital investment
• 25-year contract with Fort Hills
Partnership
• In-service in 2017
Grand Rapids
• $900 million* capital investment
• 50/50 joint venture investment with
Brion Energy
• Long-term contract with Brion Energy
• In-service in 2017
Northern Courier and Grand Rapids
* TransCanada share
• Substantially less merchant power exposure
• Remaining assets underpinned primarily by
long-term contracts with solid counterparties
Energy Footprint Following Sale of U.S. Northeast Power and
Termination of Alberta PPAs
* Our proportionate share of power generation capacity
~5,700 MW or 93% of operating capacity underpinned
by long-term contracts with strong counterparties
Long-term Contracted Assets
Plant
Capacity
(MW)*
Counterparty
Contract
Expiry
Coolidge 575 Salt River Project 2031
Bécancour 550 Hydro-Québec 2026
Cartier Wind 365 Hydro-Québec 2026-2032
Grandview 90 Irving Oil 2024
Halton Hills 683 IESO 2030
Portlands 275 IESO 2029
Ontario Solar 76 IESO 2032-2034
Bruce Power Units 1-8 3,104 IESO Up to 2064
Napanee (under construction) 900 IESO
20 Years from
In-Service
Bruce Power
• TransCanada owns a 48.5% interest in
Bruce Power
• World’s largest operating nuclear facility
• 8 reactors, 6,400 MW of capacity
• Power sold under long-term contract
with the Ontario Independent Electricity
System Operator (IESO)
• Spent fuel, waste and decommissioning
liabilities are the responsibility of
Ontario Power Generation
• Contracted through 2064
• $6.5 billion* investment through 2033
to refurbish 6 reactors
*TransCanada’s share in 2014 dollars
Numerous Levers Available to Fund Near-Term Capital Program
• Strong and growing internally generated cash flow
• Access to capital markets including:
• Senior debt
• Preferred shares and hybrid securities
• Raised $1 billion of preferred shares at an initial rate of 4.90 per cent per annum in
November
• Dividend Reinvestment Plan and ATM, if appropriate
• $175 million or 39 per cent of third quarter 2016 dividends reinvested in common shares
• Portfolio management including dropdowns to TC PipeLines, LP
Funding Near-Term Growth
Well Positioned to Fund Future Growth
$45 Billion+ of Commercially Secured Long-Term Projects*
* TransCanada share in billions of dollars. Certain projects are subject to various conditions
including corporate and regulatory approvals.
• Bruce Power Life Extension Agreement
• Asset Management and Major Component
Replacement post-2020 ($5.3 billion)
• Extends operating life of facility to 2064
• Four transformational projects
• Energy East ($15.7 billion) and related
Eastern Mainline Expansion ($2.0 billion)
• Keystone XL (US$8 billion)
• Prince Rupert Gas Transmission ($5 billion)
• Coastal GasLink ($4.8 billion)
• Establish us as leaders in the transportation of
crude oil and natural gas for LNG export
• 2 million bbl/d of liquids pipeline capacity
• 4+ Bcf/d of natural gas pipeline export capacity
Strong
Financial Position
‘A’ grade credit rating
Numerous levers available to
fund future growth
Track Record of Delivering
Long-Term Shareholder Value
14% average annual return since 2000
Visible
Growth Portfolio
$26 billion to 2020
Additional opportunity set
includes over $45 billion of
medium to longer-term
projects
Attractive, Growing
Dividend
3.7% yield at current price
8-10% expected CAGR
through 2020
Attractive Valuation Relative to North American Peers
Key Takeaways
Corporate Profile
January 2017
Natural Gas Pipelines
NGTL Near-Term Growth
• $6.0 billion of new investments
• Expected in-service 2016 through 2020
• Includes $1.7 billion North Montney
pipeline
• $4.0 billion approved by regulator
• Average investment base expected
to increase significantly from $6.7
billion in 2015
• Growth expected to continue
Canadian Mainline – Critically Important Infrastructure
$1.4 B
-0.4
$1.0 B
$1.9 B
+2.0
$3.9 B
$4.6 B
+0.3
$4.9 B
2015 Investment Base
Delta
2020 Investment Base
Western
Leg
Eastern
Triangle
Northern
Ontario
Total
$1.3 B
-1.3
$0.0 B
• LDC Settlement creates long-term stability and reduces risk considerably
• Multi-year agreement commenced in 2015 with certain elements expiring in 2020 and 2030
• Base ROE of 10.1% on 40% deemed common equity
• Annual contribution and incentives could result in ROE of 8.7% to 11.5%
• Strong delivery volumes averaging ~4.4 Bcf/d in 2016 year-to-date
Mainline Significantly De-Risked
Mainline Growth through Expansion within Eastern Triangle
• $0.7 billion of new facility expansion
projects required as part of LDC
Settlement
• Provides increased access to growing
supply of U.S. shale gas
• Expected in-service dates range from
2016 to 2017, subject to regulatory
approvals
Growing the U.S. Gas Pipelines Network
• Majority of portfolio highly contracted
over the long-term
• Well-positioned in key geographic
areas with access to multiple supply
basins and large market centres
• FERC approved ANR’s uncontested
rate case settlement
• 34.8% increase in rates effective
August 1, 2016
• Three year, US$837 million capital
program for reliability and modernization
projects
Columbia Pipeline Group Asset Overview
• Columbia Gas Transmission (91.6% interest)
• 11,272 mile (18,141 km) FERC pipeline with
average throughput of 3.9 Bcf/d
• 286 Bcf of working gas storage capacity
• Strong base business undergoing significant
expansion to connect growing Marcellus/Utica
supply
• Columbia Gulf Transmission (91.6% interest)
• 3,341 mile (5,377 km) FERC pipeline with
average throughput of 1.5 Bcf/d
• System reversal and expansion offers
competitive path to the Gulf Coast
• Millennium Pipeline (43.5% interest)
• 253 mile (407 km) FERC pipeline with average
throughput of 1.1 Bcf/d
• Connects Pennsylvania supply to New York
market
Premium Natural Gas Pipeline Network
Illustrates the configuration of material systems within Columbia’s natural gas pipeline network
0
5
10
15
20
25
30
35
2010 2015 2020E
Marcellus Utica
Positioned to Capture Growing Marcellus and Utica Production
• Significant growth in production expected
• Asset footprint favourably situated relative to production
Source: EIA and IHS CERA, February 2016
Bcf/d
Illustrates the configuration of material systems within Columbia’s natural gas pipeline network
Master Limited Partnership Strategic Review
• Entered into agreement to acquire the outstanding common units of Columbia Pipeline
Partners LP (CPPL) for cash at a price of US$17.00 per common unit
• US$915 million acquisition subject to unitholder approval
• Expect acquisition to close in first quarter 2017
• Results in 100 per cent ownership of Columbia’s core assets, is expected to be accretive to
earnings per share and simplifies corporate structure
TransCanada
Corporation
(TSX, NYSE:TRP)
TC PipeLines, LP
(NYSE:TCP)
Columbia Pipeline
Partners LP
(NYSE:CPPL)
CPPL Public
Unit Holders
46.5%
Indirect Ownership
TCP Public
Unit Holders
53.5% 72.9%*
27.1%*
Indirect Ownership
*As of September 30, 2016
Acquiring outstanding common units
TC PipeLines, LP Remains a Core Element of TransCanada’s Strategy
~US$4.0 billion market capitalization
• 6.3% yield as at December 30, 2016
Limited variability
• Seven FERC regulated natural gas pipelines
with long-term, ship-or-pay contracts
• No commodity price exposure
• Very little volume risk
Financial flexibility and liquidity
• Solid balance sheet
• Investment grade credit ratings
TransCanada
• Operates assets, owns general partner and
27.1% interest
• Current 25% GP/LP IDR split; high split max
of 25%
TC PipeLines, LP (NYSE:TCP)
Maintaining Full Ownership in Mexican Natural Gas Pipeline Business
• Guadalajara and Tamazunchale in-service
• US$3.8 billion being invested in five new
pipelines which are expected to enter service
by the end of 2018
• Underpinned by 25-year, U.S. dollar contracts
with Comisión Federal de Electricidad (CFE)
• US$1.4 billion Topolobampo and Mazatlan
projects substantially complete
• Once completed, portfolio is expected to
generate annual EBITDA of approximately
US$575 million up from US$181 million in
2015
• More compelling to maintain full ownership
interest and access capital markets
• Maximizes short- and long-term value
• Retain future growth opportunities
• Simple corporate structure
Accretive to Earnings Per Share
Positioned to Benefit from West Coast LNG
• Two large-scale projects underpinned by
long-term contracts
• $5 billion Prince Rupert Gas Transmission
(PRGT) project
• $4.8 billion Coastal GasLink (CGL) project
• PRGT and CGL have received their pipeline
and facilities permits from the B.C. Oil and
Gas Commission
• The Pacific NorthWest LNG project received
Federal Government approval to proceed;
the LNG project, and by extension PRGT,
are now subject to a Final Investment
Decision by PNW
• Also working with LNG Canada to
determine the appropriate pace of work
activities following their decision to delay
the Final Investment Decision. LNG Canada
has also received regulatory approval.
• No development cost risk and minimal
capital cost risk on either project
Liquids Pipelines
Our Liquids Pipelines Strategy
Source: CAPP 2015, IHS, EIA, Statistics Canada
PADD I
[1,090]
Eastern Canada
[690]
Domestic
Other Imports
Canada
[2014 total refinery demand
in 000’s of barrels per day]
60%
38%
2%
40%
34%
26%
79%
21%
Asia [20,150]
India [4,500]
Europe [12,500]
PADD III
[8,390]
• Leverage existing
infrastructure
• Connect growing WCSB
and U.S. shale oil supply
to key refining markets
• Capture Alberta and U.S.
regional liquids
opportunities
• Value chain participation
expansion
Extending Keystone System’s U.S. Gulf Coast Market Reach
• U.S. Gulf Coast is largest refining centre
in North America (~8 Mbbl/d of
capacity)
• Extending system’s reach to over
4.5 Mbbl/d of Gulf Coast refinery
capacity:
• Port Arthur
• Houston/Texas City
• Lake Charles
• Expected to enhance volumes on
Keystone System
• Platform for growth and regional
infrastructure expansion
• Commenced legal actions
following U.S. Administration’s
decision to deny a Presidential
Permit, actions include:
• Claim under NAFTA
• Lawsuit in U.S. Federal Court asserting
that the President’s decision to deny
construction of Keystone XL exceeded
his power under the U.S. Constitution
• $2.9 billion after-tax write-down
recorded in Fourth Quarter 2015
as a result of the denial
• Remain fully committed to
advancing Keystone XL
Keystone XL – Maintaining a Valuable Option
Remains a Competitive
Transportation Solution
to U.S. Gulf Coast
• $1 billion capital investment
• 25-year contract with Fort Hills
Partnership
• Transports bitumen and diluent
between the Fort Hills mine site
and Suncor’s terminal
• In-service in 2017
Northern Courier - Visible Liquids Pipeline Growth
Keystone XL
Energy East
Keystone
20” and 36” pipelines
20” pipeline
36” pipeline
(Phase II)
• 50/50 joint venture investment with
Brion Energy, a subsidiary of PetroChina
• Long-term contract with Brion Energy
• Transports crude oil and diluent
between northern Alberta and the
Edmonton/Heartland region
• Keyera joint venture between Edmonton
and Heartland enhances diluent supply
• 20-inch pipeline ($900 million*)
expected to be in-service in 2017
• Phase II ($700 million*) to be aligned
with market demand
Grand Rapids Pipeline – Bringing Supply to Market
Capturing Production Growth and
Meeting Diluent Requirements
* TransCanada share
Energy East – Critical to Reach Eastern Refineries and Tidewater
• $15.7 billion investment
• 1.1 million bbl/d of capacity
underpinned by long-term,
take-or-pay contracts
• Would serve Montréal, Québec City
and Saint John refineries
• Also provides tidewater access
• Project is subject to regulatory
approvals
• National Energy Board (NEB) review process
expected to take 21-months culminating in a
formal recommendation to the Governor in
Council (Federal Cabinet)
• The Governor in Council will then have six
months to decide whether to approve the
project
• NEB panel members recently recused
themselves; hearings adjourned until new
panel appointed
Québec
400 kbbl/d
Atlantic Canada
415 kbbl/d
Energy
Our Energy Strategy
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
2000 2005 2010 2015 2020 2025 2030 2035
Natural Gas
Renewables
Hydro
Nuclear
Coal
Oil
North American Power Production TWh
History Forecast
Sale of U.S. Northeast Power Assets
and Termination of Alberta PPAs
Enhances Cash Flow Stability
Source: TransCanada, EIA, StatsCan, SENER, Others
Organic Growth of
Existing Footprint
Bruce
Refurbishment and Life
Extension Alberta Opportunities:
Transition from Coal
Maximize Value of
Existing Assets
Overall Shift to Gas-fired &
Renewable Generation
Mexican Power
Opportunities
Bruce Power Life Extension Agreement
• Amended agreement with the Ontario IESO to extend the life of Bruce Power, effective
January 1, 2016 through December 31, 2064
• Multi-stage investment plan to refurbish Units 3 - 8
• Asset Management (AM) capital ~$2.5 billion*, including $600 million* through 2020
• Major Component Replacement (MCR) capital ~$4 billion* through 2033
• Uniform power price of $66.38/MWh effective April 1, 2016
• Incorporates return of/on capital from historic investment, sustaining capital, O&M costs and first six years of
AM capital
• Power price is adjusted annually for inflation; Future AM and MCR capital cost estimates are finalized and also
reflected in the power price over time
• Off-ramps provide ability to exit future refurbishments if investment does not provide sufficient economic
benefits
*TransCanada’s share in 2014 dollars
Unit 5
Unit 7
Unit 8
Planned MCR Outage Schedule
2030 2031 2032 2033
Unit 6
Unit 4
2025 2026 2027 2028 2029
Unit 3
2020 2021 2022 2023 2024
Napanee Generating Station
• $1.1 billion, 900 MW combined-cycle
gas-fired plant
• 20-year PPA with the Ontario IESO
• Construction nearing 50% complete
• In-service in 2018
Monetization of U.S. Northeast Power Business
• Expect to realize ~US$3.7 billion for business
• Entered agreements to sell Ravenswood, Ironwood, Ocean State Power and Kibby Wind for US$2.2 billion and
TC Hydro for US$1.065 billion
• Remainder attributable to power marketing business which is expected to be realized going forward
• Proceeds to repay a portion of Columbia bridge loan facilities
• Expected to result in a ~$1.1 billion after-tax net loss including a goodwill impairment of $656 million
recorded in third quarter 2016
• Sales expected to close in first half of 2017, subject to regulatory and other approvals and will
include closing adjustments
Exiting U.S. Merchant Power Business;
Expected to Increase Predictability and Stability of EBITDA
Asset
Generating
Capacity (MW) Type of Fuel
TC Hydro 583 Hydro
Kibby Wind 132 Wind
Ravenswood 2,480 Natural Gas and Oil
Ironwood 778 Natural Gas
Ocean State Power 560 Natural Gas
Total 4,533
Termination of Alberta Power Purchase Arrangements
• Announced decision to terminate our Alberta Power Purchase
Arrangements on March 7, 2016
• Reached a settlement with Government of Alberta
• Includes transfer of carbon offsets to the government
• Resolves all outstanding items related to the termination
• Continue to own four gas-fired cogeneration plants with
capacity totaling 438 MW
• Also have an interest in two non-regulated natural gas
storage facilities with 118 Bcf of capacity
Finance
Financial Strategy
• Invest in low-risk assets that generate predictable and
sustainable growth in earnings, cash flow and dividends
• Finance long-term assets with long-term capital
• Maintain financial strength and flexibility
• Value ‘A’ grade credit rating
• Effectively manage foreign exchange, interest rate and
counterparty exposures
• Disciplined cost and capital management
• Simplicity and understandability of corporate structure
Built For All Phases of the Economic Cycle
30%
4%
5%
61%
Financial Position Remains Strong
• Significant financial flexibility
• ‘A’ grade credit ratings
• $2.3 billion cash on hand as of September 30, 2016
• Reinstated common share issuance from treasury
at a two per cent discount under dividend
reinvestment plan
• $175 million or 39 per cent of third quarter 2016
dividends reinvested in common shares
• Raised $3.5 billion of common equity by issuing
60.2 million shares at $58.50 per share in November
• Raised $1 billion of preferred shares at an initial rate
of 4.90 per cent per annum in November
• Well positioned to finance $26 billion near-term
capital program with multiple attractive funding
options
Consolidated
Capital Structure*
(at September 30, 2016)
Debt (net of cash)
Preferred Shares
Common Equity
Junior Sub Notes
* Common equity includes non-controlling interests in TC PipeLines, LP, Columbia Pipeline Partners LP and Portland.
Financial Highlights – Nine Months ended September 30 (Non-GAAP)
2015 20162015 20162015 2016
1.84
2.02
4,381
4,757
Comparable
Earnings per Share*
(Dollars)
Comparable
EBITDA*
($Millions)
*Comparable Earnings per Share, Comparable EBITDA and Comparable Funds Generated from Operations are non-GAAP measures. See the non-GAAP measures slide at the
front of this presentation for more information.
3,374 3,529
Comparable Funds
Generated from
Operations*
($Millions)
Predictability and Stability of EBITDA
*Based on amounts reported for the nine months ended September 30, 2016. Comparable EBITDA is a non-GAAP measure. See the non-GAAP measures slide at the front of this presentation for more information.
Comparable EBITDA*
Regulated &
Contracted
Natural Gas
Pipelines
62%
Contracted
Liquids
Pipelines
18%
Contracted
Energy
10%
Merchant
Energy
10%
Monetization of U.S. Northeast Power Will Further Reduce Merchant Energy Exposure
Strong Historical Financial Performance
0
1
2
3
4
5
6
2010 2011 2012 2013 2014 2015
Comparable EBITDA*
($Billions)
Significant Growth in
Comparable EBITDA and Funds Generated from Operations
0
1
2
3
4
5
6
2010 2011 2012 2013 2014 2015
Funds Generated from Operations*
($Billions)
10% CAGR
7% CAGR
*Comparable EBITDA and Funds Generated from Operations are non-GAAP measures. See the non-GAAP measures slide at the front of this presentation for more information.
0
25
50
75
100
125
2010 2011 2012 2013 2014 2015
Comparable Earnings per Share*
Funds Generated from Operations*
Comparable Distributable Cash Flow per Share*
Long Track Record of Dividend Growth
0.00
0.50
1.00
1.50
2.00
2.50
2010 2011 2012 2013 2014 2015
Dividends Declared per Share
(Dollars)
Supported by Industry-Leading Coverage Ratios
Dividend Payout Ratio
(Percent)
5% CAGR
*Comparable Earnings per Share, Comparable Distributable Cash Flow per Share and Funds Generated from Operations are non-GAAP measures. See the non-GAAP measures slide at the front of this presentation for
more information.
Appendix – Reconciliation of Non-GAAP Measures
*Comparable Earnings and Comparable Earnings per Share are non-GAAP measures. See the non-GAAP measures slide at the front of this presentation for more information.
2016 2015
Net (Loss)/Income Attributable to Common Shares 482 1,218
Specific items (net of tax):
Ravenswood goodwill impairment 656 -
Alberta PPA terminations 176 -
Acquisition related costs - Columbia 206 -
Keystone XL income tax recoveries (28) -
Keystone XL asset costs 24 -
Restructuring costs 10 14
TC Offshore loss on sale 3 -
U.S. Northeast Power business monetization 3 -
Alberta corporate income tax rate increase - 34
Risk management activities (50) 36
Comparable Earnings* 1,482 1,302
Net (Loss)/Income Per Common Share $0.66 $1.72
Specific items (net of tax):
Ravenswood goodwill impairment 0.89 -
Alberta PPA terminations 0.25 -
Acquisition related costs - Columbia 0.29 -
Keystone XL income tax recoveries (0.04) -
Keystone XL asset costs 0.03 -
Restructuring costs 0.01 0.02
U.S. Northeast Power business monetization - -
Alberta corporate income tax rate increase - 0.05
Risk management activities (0.07) 0.05
Comparable Earnings Per Common Share* $2.02 $1.84
Average Common Shares Outstanding (millions) 734 709
Nine months ended
September 30
Appendix – Reconciliation of Non-GAAP Measures continued
*Comparable EBITDA, Comparable EBIT, Comparable interest expense, Comparable interest income and other, Comparable income tax expense, Comparable net income attributable to
non-controlling interests and Comparable Earnings are non-GAAP measures. See the non-GAAP measures slide at the front of this presentation for more information.
2016 2015
Comparable EBITDA* 4,757 4,381
Depreciation and amortization (1,425) (1,313)
Comparable EBIT* 3,332 3,068
Other income statement items
Comparable interest expense* (1,341) (990)
Comparable interest income and other* 385 108
Comparable income tax expense* (630) (668)
Comparable net income attributable to non-controlling interests* (187) (145)
Preferred share dividends (77) (71)
Comparable Earnings* 1,482 1,302
Specific items (net of tax):
Ravenswood goodwill impairment (656) -
Alberta PPA terminations (176) -
Acquisition related costs - Columbia (206) -
Keystone XL income tax recoveries 28 -
Keystone XL asset costs (24) -
Restructuring costs (10) (14)
TC Offshore loss on sale (3) -
U.S. Northeast Power business monetization (3) -
Alberta corporate income tax rate increase - (34)
Risk management activities 50 (36)
Net Income Attributable to Common Shares 482 1,218
Nine months ended
September 30
Appendix – Reconciliation of Non-GAAP Measures continued
*Funds Generated from Operations, and Comparable Funds Generated from Operations are non-GAAP measures. See the non-GAAP measures slide at the front of this presentation for
more information.
2016 2015
Net Cash Provided by Operations 3,277 2,976
Increase/(decrease) in operating working capital (28) 378
Funds Generated from Operations* 3,249 3,354
Specific items:
Acquisition related costs - Columbia 238 -
Keystone XL asset costs 37 -
Restructuring costs - 20
U.S. Northeast Power business monetization 5 -
Current income taxes - -
Comparable Funds Generated from Operations* 3,529 3,374
Nine months ended
September 30
Corporate Profile
January 2017