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. )
Filed by the Registrant ¨ | |
Filed by a Party other than the Registrant x | |
Check the appropriate box: | |
¨ | Preliminary Proxy Statement |
¨ | Confidential, for Use of the Commission Only (as permitted by Rule 14a‑6(e)(2)) |
¨ | Definitive Proxy Statement |
¨ | Definitive Additional Materials |
x | Soliciting Material under §240.14a‑12 |
Columbia Pipeline Partners LP | ||
(Name of Registrant as Specified In Its Charter) | ||
TransCanada Corporation | ||
(Name of Person(s) Filing Proxy Statement, if other than the Registrant) | ||
Payment of Filing Fee (Check the appropriate box): | ||
x | No fee required. | |
¨ | Fee computed on table below per Exchange Act Rules 14a‑6(i)(1) and 0‑11. | |
(1) | Title of each class of securities to which transaction applies: | |
(2) | Aggregate number of securities to which transaction applies: | |
(3) | Per unit price or other underlying value of transaction computed pursuant to Exchange Act Rule 0‑11 (set forth the amount on which the filing fee is calculated and state how it was determined): | |
(4) | Proposed maximum aggregate value of transaction: | |
(5) | Total fee paid: | |
¨ | Fee paid previously with preliminary materials. | |
¨ | Check box if any part of the fee is offset as provided by Exchange Act Rule 0‑11(a)(2) and identify the filing for which the offsetting fee was paid previously. Identify the previous filing by registration statement number, or the Form or Schedule and the date of its filing. | |
(1) | Amount Previously Paid: | |
(2) | Form, Schedule or Registration Statement No.: | |
(3) | Filing Party: | |
(4) | Date Filed: | |
Persons who are to respond to the collection of information contained in this form are not required to respond unless the form displays a currently valid OMB control number. Being filed herewith is an investor presentation. | ||
Corporate Profile
November 2016
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), 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, when they are available, 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 or by writing
CPPL at 5151 San Felipe Street, Suite 2500, Houston, Texas 77056, Attention: Corporate Secretary. 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, will be contained in the proxy statement and other relevant materials to be filed with the
SEC when they become available.
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
• $25 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 $52 billion
as of November 16, 2016
Portfolio of Complementary
Energy Infrastructure Assets
Financial Highlights – Nine Months ended September 30 (Non-GAAP)
2015 20162015 20162015 2016
1.84
2.02
4,381
4,757
Comparable
Earnings per Share*
(Dollars)
Comparable
EBITDA*
($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)
Strategic Plan Update Highlights – November 2016
Maintaining Full Ownership Interest in Mexico
• US$3.8 billion of projects targeted to enter service by the end of 2018
• Annual EBITDA expected to increase to approximately US$575 million from US$181 million in 2015
Reached Agreement to Acquire Columbia Pipeline Partners LP Common Units for US$17.00 per Unit
• US$915 million acquisition subject to unitholder approval and other customary closing conditions
Expect to Realize ~US$3.7 Billion from Monetization of U.S. Northeast Power Business
• Proceeds to repay a portion of the US$6.9 billion senior unsecured asset bridge term loan credit facilities
(Columbia bridge loan facilities) used to partially finance the Columbia acquisition
Common Share Issue
• Issued ~$3.5 billion of common shares under a bought deal including a 10 per cent over-allotment option
• Proceeds to repay a portion of the Columbia bridge loan facilities following decision to maintain current
ownership interest in Mexico
Actions Expected to be Accretive to Earnings Per Share, Strengthen Financial Position and
Support Annual Dividend Growth at the Upper End of 8 to 10 Per Cent Through 2020
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
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
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
Columbia Pipeline Integration
• Transformational acquisition created one of
North America’s largest regulated natural gas
transmission businesses and provides a new
platform for growth
• CPPL acquisition increases ownership in principal
Columbia assets to 100 per cent
• 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 11
Incumbent Position in
North America’s Most Prolific,
Low Cost Natural Gas Basins
$25 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 5.4 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)
CAD25.4
* TransCanada share in billions of dollars. Certain projects are subject to various conditions including
corporate and regulatory approvals.
12
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 Previous Guidance of 8 to 10 Per Cent
Supported by Expected Growth in Earnings and Cash Flow
13
0.80
2.26
Issued ~$3.5 Billion of Common Shares Under Bought Deal in November
• Proceeds to be used to repay a portion of the Columbia bridge loan facilities following
decision to maintain full ownership interest in Mexico
• Over-allotment option exercised, increasing issuance from $3.2 billion to $3.5 billion
Numerous Other Levers Available to Fund Growth
• $2.3 billion of cash and cash equivalents on hand as of September 30, 2016
• 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
14
Well Positioned to Fund Near-Term Capital Program
$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
15% average annual return since 2000
Visible
Growth Portfolio
$25 billion to 2020
Additional opportunity set
includes over $45 billion of
medium to longer-term
projects
Attractive, Growing
Dividend
3.8% yield at current price
8-10% expected CAGR
through 2020
Attractive Valuation Relative to North American Peers
Key Takeaways
Corporate Profile
November 2016
Natural Gas Pipelines
Our Natural Gas Pipelines Strategy
Pursue oil sands and
West Coast LNG markets
using NGTL System
Expand Mexico’s
gas network
Adapting to changing
gas flow dynamics
Maintain pre-eminent position in
WCSB and Appalachia for production
and market connections Growing Natural Gas Supply
and Demand Provides Opportunity
Capture new
demand growth
Seek optimal
use of assets
North American
Natural Gas Supply/Demand Balance
Source: TransCanada
* Includes fuel used within the LNG process
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
Bcf/d
Integrate Columbia
Pipeline Group
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
Footprint Uniquely Positioned to
Capture Supply & Demand Growth
NGTL Near-Term Growth
• $5.4 billion of new
investments
• Expected in-service
between 2016 and 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
2016-17 Facilities - $4.8 B 2018 Expansion Facilities - $0.6 B
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
• $2.0 billion Eastern Mainline Project
(EMP) ensures existing and new firm
transportation commitments are met
• Reached agreement with LDCs that
resolves their issues with Energy East
and the EMP
• Timing 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
• ANR filed a rate case settlement with
FERC for ultimate approval, which was
supported or unopposed by all parties
• 34.8% increase in rates effective
August 1, 2016
• Three year, US$837 million capital
program for reliability and modernization
projects
Columbia Pipeline Group Asset Overview
• Columbia Gas Transmission (91.6% interest)
• 11,272 mile (18,141 km) FERC pipeline with
average throughput of 3.9 Bcf/d
• 286 Bcf of working gas storage capacity
• Strong base business undergoing significant
expansion to connect growing Marcellus/Utica
supply
• Columbia Gulf Transmission (91.6% interest)
• 3,341 mile (5,377 km) FERC pipeline with
average throughput of 1.5 Bcf/d
• System reversal and expansion offers
competitive path to the Gulf Coast
• Millennium Pipeline (43.5% interest)
• 253 mile (407 km) FERC pipeline with average
throughput of 1.1 Bcf/d
• Connects Pennsylvania supply to New York
market
Premium Natural Gas Pipeline Network
Illustrates the configuration of material systems within Columbia’s natural gas pipeline network
0
5
10
15
20
25
30
35
2010 2015 2020E
Marcellus Utica
Positioned to Capture Growing Marcellus and Utica Production
• Significant growth in production expected
• Asset footprint favourably situated relative to production
Source: EIA and IHS CERA, February 2016
Bcf/d
Illustrates the configuration of material systems within Columbia’s natural gas pipeline network
Columbia Pipeline Group Capital Program
* Columbia share in billions of U.S. dollars. Certain projects are subject to various conditions including regulatory approvals.
Asset Project
Estimated
Capital Cost
(US$)* 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
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)
* TransCanada share
Opportunities for
Future Growth
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 recent 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
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
*Comparable EBITDA is a non-GAAP measure. See the non-GAAP measures slide at the front of this
presentation for more information.
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
• 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
• Capable of generating ~30% of
Ontario’s power needs
• Power sold under long-term contract
with the Ontario Independent Electricity
System Operator (IESO)
• Operations and related work are subject
to regulatory oversight by the Canadian
Nuclear Safety Commission (CNSC)
• Spent fuel, waste and decommissioning
liabilities are the responsibility of
Ontario Power Generation
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
Termination of Alberta Power Purchase Arrangements
• Announced decision to terminate our Alberta Power Purchase
Arrangements on March 7, 2016
• Arrangements contain a provision permitting PPA buyers to terminate
PPAs if there is a change in law that makes the PPAs unprofitable or
more unprofitable
• On July 25, 2016, the Government of Alberta brought an application in
the Court of Queen’s Bench to prevent the Balancing Pool from allowing
termination of a PPA held by another party which contains identically
worded termination provisions to our PPAs
• The outcome of this court application may affect resolution of the
arbitration of the Sheerness, Sundance A and Sundance B PPAs
• Unprofitable market conditions are expected to continue as costs related
to carbon emissions have increased and are forecast to continue to
increase over the remaining term of the PPA agreements
• 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 $25 billion near-term
capital program with multiple attractive funding
options
Consolidated
Capital Structure*
(at September 30, 2016)
Debt (net of cash)
Preferred Shares
Common Equity
Junior Sub Notes
* Common equity includes non-controlling interests in TC PipeLines, LP, Columbia Pipeline Partners LP and Portland.
Predictability and Stability of EBITDA
*Based on amounts reported for the nine months ended September 30, 2016. Comparable EBITDA is a non-GAAP measure. See the non-GAAP measures slide at the front of this presentation for more information.
Comparable EBITDA*
Regulated &
Contracted
Natural Gas
Pipelines
62%
Contracted
Liquids
Pipelines1
18%
Contracted
Energy
10%
Merchant
Energy
10%
Monetization of U.S. Northeast Power Will Further Reduce Merchant Energy Exposure
Risks are Known and Contained
• Volumetric
• Spot movements on southern portion of Keystone System and on Great Lakes
• Availability at Bruce Power
• Commodity
• Alberta cogens and non-regulated natural gas storage
• Substantially reduced exposure upon sale of U.S. Northeast power portfolio and
Alberta PPA terminations
• Counterparty
• Strong counterparty support on contracted assets
• Cost-of-service or regulated businesses with strong underlying fundamentals
• Interest Rates
• Largely fixed-rate debt financed (~90%) with long duration
• 17-year average term at 5.3% coupon rate
• Foreign Exchange
• U.S. dollar assets and income streams predominately hedged with U.S.
dollar-denominated debt
Strong Historical Financial Performance
0
1
2
3
4
5
6
2010 2011 2012 2013 2014 2015
Comparable EBITDA*
($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
52 *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
53
*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
54
*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
November 2016