UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

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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