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TransCanada Reports an Increase in Third Quarter Comparable Earnings to $417 Million or $0.59 Per Share

Nov 01, 2011 CALGARY, ALBERTA ,MARKETWIRE TransCanada Corporation (TSX:TRP) (NYSE:TRP) (TransCanada or the Company) today announced comparable earnings for third quarter 2011 of $417 million or $0.59 per share. Net income attributable to common shares was $384 million or $0.55 per share. TransCanada's Board of Directors also declared a quarterly dividend of $0.42 per common share for the quarter ending December 31, 2011, equivalent to $1.68 per share on an annualized basis.

"TransCanada experienced another strong quarter driven by earnings from our new assets and the Company's diverse and high-quality energy infrastructure portfolio," said Russ Girling, TransCanada's president and chief executive officer. "Comparable earnings for the first nine months of 2011 were $1.71 per share, a 20 per cent increase over the same period last year."

Since the spring of 2010, TransCanada has brought $10 billion of growth projects into service including the first and second phases of the Keystone Pipeline System, the Bison and Guadalajara natural gas pipelines, extensions and expansions of the Alberta System, phase two of the Kibby Wind farm in Maine, the Halton Hills Generating Station in Ontario and the Coolidge Generating Station in Arizona.

The Company is positioned to complete another $11 billion of new projects that will come into service by 2013 including the Keystone U.S. Gulf Coast Expansion (Keystone XL), additional extensions and expansions of the Alberta System, the Bruce Power restart program in Ontario and the final two phases of the Cartier Wind power project in Quebec. TransCanada expects these projects will generate sustained earnings and cash flow growth and deliver superior returns to our shareholders.

Third Quarter Highlights

(All financial figures are unaudited and in Canadian dollars unless noted otherwise)

-- Comparable earnings of $417 million, an increase of 11 per cent -- Comparable earnings per share of $0.59, an increase of 9 per cent -- Net income attributable to common shares of $384 million or $0.55 per share -- Comparable EBITDA of $1.258 billion, an increase of 25 per cent -- Funds generated from operations of $971 million, an increase of 13 per cent -- Common share dividend of $0.42 per share declared for the quarter ending December 31, 2011 -- Favourable Final Environmental Impact Statement (FEIS) received from the U.S. Department of State for Keystone XL -- Comprehensive tolls application for the Canadian Mainline filed with the National Energy Board (NEB) addressing tolls for 2012 and 2013 Comparable earnings for third quarter 2011 were $417 million ($0.59 per share) compared to $374 million ($0.54 per share) in the same period in 2010. Contributions from recently commissioned pipeline and power generation assets, combined with higher realized power prices in Alberta, were the primary reasons for the year over year increase in comparable earnings. Partially offsetting these increases were higher interest expense and lower contributions from the U.S. Power and Alberta Gas Storage businesses. Comparable earnings in third quarter 2010 included the positive impact of recognizing the Alberta System 2010-2012 Revenue Requirement Settlement retroactive to its January 1, 2010 effective date.

Notable recent developments in Oil Pipelines, Natural Gas Pipelines, Energy and Corporate include:

Oil Pipelines:

-- On August 26, 2011, the U.S. Department of State (DOS), the lead agency for U.S. federal regulatory approvals, released its FEIS for Keystone XL. The FEIS found that the project would have limited environmental impact and the proposed route would have the least environmental impact of the alternatives considered. -- Following the issuance of the FEIS, the DOS initiated a 90-day National Interest Determination (NID) process. As part of the NID process, the DOS held nine public comment meetings in September and October and will consult with other U.S. federal agencies to determine if granting approval for Keystone XL is in the national interest of the United States. The NID period concludes on November 25, 2011 and a decision on the Presidential Permit is expected by year end. -- In August 2011, TransCanada launched two binding open seasons both of which closed October 17, 2011. The first offered capacity to attract long-term firm service contracts for crude oil transportation from Hardisty, Alberta to Houston, Texas (Houston Lateral). The approximate US$600 million Houston Lateral project would involve the expansion of capacity through the addition of pump stations and the construction of an approximate 80-kilometre (km) (50-mile) pipeline extension from the proposed Keystone XL System. The proposed project would double the U.S. Gulf Coast refining market capacity accessible from the Keystone Pipeline System. TransCanada is currently analyzing the results of the open season. Pending sufficient shipper commitments and regulatory approvals, the Houston Lateral is expected to be operational in 2014. -- The second binding open season offered capacity to attract additional long-term firm service contracts for crude oil transportation from Cushing, Oklahoma to Port Arthur or Houston, Texas (Cushing Marketlink). The approximate US$50 million Cushing Marketlink project uses a portion of the facilities that form part of Keystone XL including the Houston Lateral. TransCanada is currently analyzing the results of the open season. Pending regulatory approvals, Cushing Marketlink is expected to begin shipping crude oil to Port Arthur in 2013 and to Houston in 2014. Natural Gas Pipelines:

-- On September 1, 2011, TransCanada filed a comprehensive application with the NEB to change the business structure and the terms and conditions of service for the Canadian Mainline, including addressing tolls for 2012 and 2013. The application includes components that affect the Alberta System and Foothills (Restructuring Proposal). The application is intended to address the long-term economic viability of the Canadian Mainline and improve the competitiveness of TransCanada's regulated Canadian natural gas transportation infrastructure and the Western Canada Sedimentary Basin (WCSB). On October 31, 2011, TransCanada filed supplementary information on cost of service and the proposed tolls for 2012 and 2013. The application results in a 2012 Nova Inventory Transfer System to Dawn toll of $1.29 per gigajoule (GJ) which is $0.80 per GJ or 38 per cent lower than the comparable tolls charged in 2011. In addition, on October 31, 2011, TransCanada filed for interim 2012 tolls on the Alberta System and annual tolls on Foothills to be effective January 1, 2012. These applications are based on the provisions of the current settlements in place for these systems. An application for interim tolls for 2012 on the Mainline is expected to be filed in mid-November 2011. Final tolls for 2012 on the Mainline and Alberta System will be determined following the NEB's decision on the Restructuring Proposal. In response to the application, the NEB held a Pre-hearing Planning Conference on October 12, 2011 for interested parties to provide suggestions on sequencing of the hearing, procedural steps required and the timing of these steps. Based on comments received, the NEB decided that it will hear all of TransCanada's Application, including cost of capital, in one proceeding before issuing a decision on the Application. The oral portion of the hearing will commence on June 4, 2012 in Calgary, Alberta. -- The Alberta System's Horn River natural gas pipeline project was approved by the NEB in January 2011 and commenced construction in March 2011, with a targeted completion date of second quarter 2012 and an estimated capital cost of $275 million. In addition, the Company has executed an agreement to extend the Horn River pipeline by approximately 100 km (62 miles) at an estimated capital cost of $230 million. As a result of the extension, additional contractual commitments of 100 million cubic feet per day (mmcf/d) are expected to commence in 2014 with volumes increasing to 300 mmcf/d by 2020. An application requesting approval to construct and operate this extension was filed with the NEB on October 14, 2011. The total currently contracted volumes for Horn River, including the extension, are expected to be approximately 900 mmcf/d by 2020. -- On June 24, 2011, the NEB approved the construction and operation of a 24 km (15 mile) extension of the Groundbirch natural gas pipeline. Construction commenced in August 2011 with an expected in-service date of April 1, 2012 and an estimated capital cost of approximately $60 million. The project is required to serve 250 mmcf/d of new transportation contracts. -- TransCanada continues to advance further pipeline development in British Columbia (B.C.) and Alberta to transport new natural gas supplies. The Company has filed several applications with the NEB requesting approval of further expansions of the Alberta System to accommodate requests for additional natural gas transmission service throughout the northwest and northeast portions of the WCSB. As at September 30, 2011, including the projects previously discussed, the NEB had approved natural gas pipeline projects with capital costs of approximately $750 million. Further pipeline projects with a total capital cost of approximately $640 million are awaiting NEB decision. -- Ongoing business with Western Canadian producers have resulted in new contracts from both the Montney and Horn River shale gas formations. Including the projects discussed above, TransCanada has firm commitments to transport 2.9 billion cubic feet per day from northwest Alberta and northeast B.C. by 2014. Energy:

-- Bruce Power continues to progress through the commissioning of Units 1 and 2. Fueling of Unit 1 will commence in November 2011 and the final phases of commissioning for Unit 2 are planned to begin in fourth quarter 2011. Subject to regulatory approval, Bruce Power expects to achieve first synchronization of Unit 2 to the electrical grid early in first quarter 2012 and commence commercial operation in late first quarter 2012. Bruce Power expects the first synchronization of Unit 1 to the electrical grid in second quarter 2012 and commercial operations to occur during third quarter 2012. TransCanada's share of the total capital cost is expected to be approximately $2.4 billion, of which $2.2 billion was incurred as of September 30, 2011. -- Construction continues on the five-stage, 590 MW Cartier Wind project in Quebec. As at September 30, 2011, 100 per cent of the wind turbines at Gros-Morne phase 1 and approximately 80 per cent of the wind turbines at Montagne-Seche had been erected. The 101 MW first phase of the Gros- Morne and 58 MW Montagne-Seche wind farm projects are expected to be operational in December 2011. The 111 MW Gros-Morne phase two is expected to be operational in December 2012. These are the fourth and fifth Quebec-based wind farms of Cartier Wind, which are 62 per cent owned by TransCanada. All of the power produced by Cartier Wind is sold under a 20-year Power Purchase Arrangement (PPA) to Hydro-Quebec. -- The dispute arising out of TransAlta Corporation's claims of force majeure and economic destruction for the Sundance A facility will be heard through a single binding arbitration process. The arbitration panel has scheduled a hearing in March and April 2012 for these claims. Assuming the hearing concludes within the time allotted, TransCanada expects to receive a decision in mid-2012. TransCanada does not believe the owner's claims meet the tests of force majeure or destruction as specified in the PPA and therefore continues to record revenues and costs as though this event is an interruption of supply, in accordance with the terms of the PPA. For the nine months ended September 30, 2011, TransCanada has recorded $99 million of EBITDA related to the Sundance A PPA. Ultimate recovery of this amount will depend upon the outcome of the arbitration process. -- Since July 2011, spot prices for capacity sales in the New York Zone J market have settled at materially lower levels than prior periods as a result of the manner in which the New York Independent System Operator (NYISO) has applied pricing rules for a new power plant that recently began service in this market. TransCanada believes that this application of pricing rules by the NYISO is in direct contravention of a series of Federal Energy Regulatory Commission (FERC) orders which direct how new entrant capacity is to be treated for the purpose of determining capacity prices. TransCanada and other parties have filed formal complaints with FERC that are currently pending. The outcome of the complaints and longer-term impact that this development may have on TransCanada's Ravenswood operations are unknown. During third quarter, the demand curve reset process was completed following FERC's acceptance of the NYISO's September 22, 2011 compliance filing. This resulted in increased demand curve rates that apply going forward to 2014 and positively impacted capacity prices in October. The impact on winter capacity prices is expected to be negligible due to excess capacity in the winter months, exacerbated by the above noted NYISO actions relative to new unit pricing. Corporate:

-- The Board of Directors of TransCanada declared a quarterly dividend of $0.42 per common share for the quarter ending December 31, 2011 on TransCanada's outstanding common shares. The quarterly amount is equivalent to $1.68 per common share on an annual basis. -- On October 14, 2011, TransCanada PipeLines Limited (TCPL) amended and restated its $2.0 billion committed, syndicated, revolving, extendible credit facility. The amended and restated facility is set to expire October 2016 and is fully available. On October 14, 2011, a wholly-owned subsidiary of the Company, TransCanada PipeLine USA Ltd., refinanced its existing US$1.0 billion credit facility with a new 364-day, US$1.0 billion committed, syndicated, revolving, extendible credit facility which is fully available. -- The Company believes it has the capacity to fund its existing capital program through internally-generated cash flow, continued access to capital markets and liquidity underpinned by in excess of $4 billion of committed credit facilities. TransCanada's financial flexibility is further bolstered by opportunities for portfolio management, including an ongoing role for TC PipeLines, LP. -- In September 2011, TransCanada was named for the tenth consecutive year to the Dow Jones Sustainability Index (DJSI). In addition, it was named to the North American Index for the seventh year in a row. The DJSI tracks the stock performance of the world's leading companies in terms of economic, environmental and social criteria. The indexes serve as benchmarks for investors who integrate sustainability considerations into their portfolios, and provide an effective engagement platform for companies who want to adopt sustainable best practices. Teleconference and Webcast - Audio and Slide Presentation:

TransCanada will hold a teleconference and webcast to discuss its 2011 third quarter financial results. Russ Girling, TransCanada president and chief executive officer and Don Marchand, executive vice-president and chief financial officer, along with other members of the TransCanada executive leadership team, will discuss the financial results and company developments before opening the call to questions from analysts and members of the media.

Event:

TransCanada 2011 third quarter financial results teleconference and webcast

Date:

Tuesday, November 1, 2011

Time:

9:00 a.m. mountain daylight time (MDT) / 11:00 a.m. eastern daylight time (EDT)

How:

Analysts, members of the media and other interested parties are invited to participate by calling 866.223.7781 or 416.340.8018 (Toronto area). Please dial in 10 minutes prior to the start of the call. No pass code is required. A live webcast of the teleconference will be available at www.transcanada.com.

A replay of the teleconference will be available two hours after the conclusion of the call until midnight (EDT) November 8, 2011. Please call 800.408.3053 or 905.694.9451 (Toronto area) and enter pass code 2786260.

With more than 60 years experience, TransCanada is a leader in the responsible development and reliable operation of North American energy infrastructure including natural gas and oil pipelines, power generation and gas storage facilities. TransCanada's network of wholly owned natural gas pipelines extends more than 57,000 kilometres (35,500 miles), tapping into virtually all major gas supply basins in North America. TransCanada is one of the continent's largest providers of gas storage and related services with approximately 380 billion cubic feet of storage capacity. A growing independent power producer, TransCanada owns, or has interests in, over 10,800 megawatts of power generation in Canada and the United States. TransCanada is developing one of North America's largest oil delivery systems. TransCanada's common shares trade on the Toronto and New York stock exchanges under the symbol TRP. For more information visit: www.transcanada.com and follow us on Twitter @TransCanada.

Forward-Looking Information

This news release may contain certain information that is forward-looking and is subject to important risks and uncertainties. The words "anticipate", "expect", "believe", "may", "should", "estimate", "project", "outlook", "forecast" or other similar words are used to identify such forward-looking information. Forward-looking statements in this document are intended to provide TransCanada security holders and potential investors with information regarding TransCanada and its subsidiaries, including management's assessment of TransCanada's and its subsidiaries' future financial and operational plans and outlook. Forward-looking statements in this document may include, among others, statements regarding the anticipated business prospects, projects and financial performance of TransCanada and its subsidiaries, expectations or projections about the future, strategies and goals for growth and expansion, expected and future cash flows, costs, schedules (including anticipated construction and completion dates), operating and financial results and expected impact of future commitments and contingent liabilities, including future abandonment costs. All forward-looking statements reflect TransCanada's beliefs and assumptions based on information available at the time the statements were made. Actual results or events may differ from those predicted in these forward-looking statements. Factors that could cause actual results or events to differ materially from current expectations include, among others, the ability of TransCanada to successfully implement its strategic initiatives and whether such strategic initiatives will yield the expected benefits, the operating performance of the Company's pipeline and energy assets, the availability and price of energy commodities, capacity payments, regulatory processes and decisions, outcomes of litigation and arbitration proceedings, changes in environmental and other laws and regulations, competitive factors in the pipeline and energy sectors, construction and completion of capital projects, labour, equipment and material costs, access to capital markets, interest and currency exchange rates, technological developments and economic conditions in North America. By its nature, forward-looking information is subject to various risks and uncertainties, which could cause TransCanada's actual results and experience to differ materially from the anticipated results or expectations expressed.

Additional information on these and other factors is available in the reports filed by TransCanada with Canadian securities regulators and with the U.S. Securities and Exchange Commission. Readers are cautioned not to place undue reliance on this forward-looking information, which is given as of the date it is expressed in this news release or otherwise specified, and not to use future-oriented information or financial outlooks for anything other than their intended purpose. TransCanada undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, except as required by law.

Non-GAAP Measures

TransCanada uses the measures Comparable Earnings, Comparable Earnings per Share, Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA), Comparable EBITDA, Earnings Before Interest and Taxes (EBIT), Comparable EBIT, Comparable Interest Expense, Comparable Interest Income and Other, Comparable Income Taxes and Funds Generated from Operations in this news release. These measures do not have any standardized meaning prescribed by Canadian generally accepted accounting principles (GAAP). They are, therefore, considered to be non-GAAP measures and may not be comparable to similar measures presented by other entities. Management of TransCanada uses these non-GAAP measures to improve its ability to compare financial results among reporting periods and to enhance its understanding of operating performance, liquidity and ability to generate funds to finance operations. These non-GAAP measures are also provided to readers as additional information on TransCanada's operating performance, liquidity and ability to generate funds to finance operations.

EBITDA is an approximate measure of the Company's pre-tax operating cash flow and is generally used to better measure performance and evaluate trends of individual assets. EBITDA comprises earnings before deducting interest and other financial charges, income taxes, depreciation and amortization, net income attributable to non-controlling interests and preferred share dividends. EBIT is a measure of the Company's earnings from ongoing operations and is generally used to better measure performance and evaluate trends within each segment. EBIT comprises earnings before deducting interest and other financial charges, income taxes, net income attributable to non-controlling interests and preferred share dividends.

Comparable Earnings, Comparable EBITDA, Comparable EBIT, Comparable Interest Expense, Comparable Interest Income and Other, and Comparable Income Taxes comprise Net Income Attributable to Common Shares, EBITDA, EBIT, Interest Expense, Interest Income and Other, and Income Taxes Expense, respectively, adjusted for specific items that are significant but are not reflective of the Company's underlying operations in the period. Specific items are subjective, however, management uses its judgement and informed decision-making when identifying items to be excluded in calculating these non-GAAP measures, some of which may recur. Specific items may include but are not limited to certain fair value adjustments relating to risk management activities, income tax refunds and adjustments, gains or losses on sales of assets, legal and bankruptcy settlements, and write-downs of assets and investments.

The Company engages in risk management activities to reduce its exposure to certain financial and commodity price risks by utilizing instruments such as derivatives. The risk management activities which TransCanada excludes from Comparable Earnings provide effective economic hedges but do not meet the specific criteria for hedge accounting treatment and, therefore, changes in their fair values are recorded in Net Income each period. The unrealized gains or losses from changes in the fair value of these derivative contracts and natural gas inventory in storage are not considered to be representative of the underlying operations in the current period or the positive margin that will be realized upon settlement. As a result, these amounts have been excluded in the determination of Comparable Earnings.

The table in the Non-GAAP Measures section of the Management's Discussion and Analysis presents a reconciliation of these non-GAAP measures to Net Income Attributable to Common Shares. Comparable Earnings per Share is calculated by dividing Comparable Earnings by the weighted average number of common shares outstanding for the period.

Funds Generated from Operations comprise Net Cash Provided by Operations before changes in operating working capital and allows management to better measure consolidated operating cash flow, excluding fluctuations from working capital balances which may not necessarily be reflective of underlying operations in the same period. A reconciliation of Funds Generated from Operations to Net Cash Provided by Operations is presented in the Third Quarter 2011 Financial Highlights table in this news release.

Third Quarter 2011 Financial Highlights

Operating Results

Three months ended Nine months ended (unaudited) September 30 September 30 (millions of dollars) 2011 2010 2011 2010 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Revenues 2,393 2,129 6,779 6,007 Comparable EBITDA(1) 1,258 1,007 3,622 2,936 Net Income Attributable to Controlling Interests 397 391 1,193 989 Net Income Attributable to Common Shares 384 377 1,152 958 Comparable Earnings(1) 417 374 1,199 977 Cash Flows Funds generated from operations(1) 971 861 2,782 2,519 Decrease/(increase) in operating working capital 94 (70) 192 (271) -------------------------------------- Net cash provided by operations 1,065 791 2,974 2,248 -------------------------------------- -------------------------------------- Capital Expenditures 696 1,297 2,135 3,565 -------------------------------------- -------------------------------------- Common Share Statistics

Three months ended Nine months ended September 30 September 30 (unaudited) 2011 2010 2011 2010 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Net Income per Share - Basic $ 0.55 $ 0.54 $ 1.64 $ 1.39 Comparable Earnings per Share(1) $ 0.59 $ 0.54 $ 1.71 $ 1.42 Dividends Declared per Share $ 0.42 $ 0.40 $ 1.26 $ 1.20 Basic Common Shares Outstanding (millions) Average for the period 703 692 701 689 End of period 703 693 703 693 -------------------------------------- -------------------------------------- (1) Refer to the Non-GAAP Measures section in this news release for further discussion of Comparable EBITDA, Comparable Earnings, Funds Generated from Operations and Comparable Earnings per Share.

Quarterly Report to Shareholders

Management's Discussion and Analysis

Management's Discussion and Analysis (MD&A) dated October 31, 2011 should be read in conjunction with the accompanying unaudited Consolidated Financial Statements of TransCanada Corporation (TransCanada or the Company) for the three and nine months ended September 30, 2011. In 2011, the Company will prepare its consolidated financial statements in accordance with Canadian generally accepted accounting principles (GAAP) as defined in Part V of the Canadian Institute of Chartered Accountants (CICA) Handbook, which is discussed further in the Changes in Accounting Policies section in this MD&A. This MD&A should also be read in conjunction with the audited Consolidated Financial Statements and notes thereto, and the MD&A contained in TransCanada's 2010 Annual Report for the year ended December 31, 2010. Additional information relating to TransCanada, including the Company's Annual Information Form and other continuous disclosure documents, is available on SEDAR at www.sedar.com under TransCanada Corporation's profile. "TransCanada" or "the Company" includes TransCanada Corporation and its subsidiaries, unless otherwise indicated. Amounts are stated in Canadian dollars unless otherwise indicated. Abbreviations and acronyms used but not otherwise defined in this MD&A are identified in the Glossary of Terms contained in TransCanada's 2010 Annual Report.

Forward-Looking Information

This MD&A may contain certain information that is forward looking and is subject to important risks and uncertainties. The words "anticipate", "expect", "believe", "may", "should", "estimate", "project", "outlook", "forecast" or other similar words are used to identify such forward-looking information. Forward-looking statements in this document are intended to provide TransCanada security holders and potential investors with information regarding TransCanada and its subsidiaries, including management's assessment of TransCanada's and its subsidiaries' future financial and operational plans and outlook. Forward-looking statements in this document may include, among others, statements regarding the anticipated business prospects, projects and financial performance of TransCanada and its subsidiaries, expectations or projections about the future, strategies and goals for growth and expansion, expected and future cash flows, costs, schedules (including anticipated construction and completion dates), operating and financial results, and expected impact of future commitments and contingent liabilities, including future abandonment costs. All forward looking statements reflect TransCanada's beliefs and assumptions based on information available at the time the statements were made.

Actual results or events may differ from those predicted in these forward-looking statements. Factors that could cause actual results or events to differ materially from current expectations include, among others, the ability of TransCanada to successfully implement its strategic initiatives and whether such strategic initiatives will yield the expected benefits, the operating performance of the Company's pipeline and energy assets, the availability and price of energy commodities, capacity payments, regulatory processes and decisions, outcomes of litigation and arbitration proceedings, changes in environmental and other laws and regulations, competitive factors in the pipeline and energy sectors, construction and completion of capital projects, labour, equipment and material costs, access to capital markets, interest and currency exchange rates, technological developments and economic conditions in North America. By its nature, forward looking information is subject to various risks and uncertainties, including those material risks discussed in the Financial Instruments and Risk Management section in this MD&A, which could cause TransCanada's actual results and experience to differ materially from the anticipated results or expectations expressed. Additional information on these and other factors is available in the reports filed by TransCanada with Canadian securities regulators and with the U.S. Securities and Exchange Commission (SEC). Readers are cautioned not to place undue reliance on this forward looking information, which is given as of the date it is expressed in this MD&A or otherwise specified, and not to use future-oriented information or financial outlooks for anything other than their intended purpose. TransCanada undertakes no obligation to update publicly or revise any forward looking information, whether as a result of new information, future events or otherwise, except as required by law.

Non-GAAP Measures

TransCanada uses the measures Comparable Earnings, Comparable Earnings per Share, Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA), Comparable EBITDA, Earnings Before Interest and Taxes (EBIT), Comparable EBIT, Comparable Interest Expense, Comparable Interest Income and Other, Comparable Income Taxes and Funds Generated from Operations in this MD&A. These measures do not have any standardized meaning prescribed by GAAP. They are, therefore, considered to be non-GAAP measures and may not be comparable to similar measures presented by other entities. Management of TransCanada uses these non-GAAP measures to improve its ability to compare financial results among reporting periods and to enhance its understanding of operating performance, liquidity and ability to generate funds to finance operations. These non-GAAP measures are also provided to readers as additional information on TransCanada's operating performance, liquidity and ability to generate funds to finance operations.

EBITDA is an approximate measure of the Company's pre-tax operating cash flow and is generally used to better measure performance and evaluate trends of individual assets. EBITDA comprises earnings before deducting interest and other financial charges, income taxes, depreciation and amortization, net income attributable to non-controlling interests and preferred share dividends. EBIT is a measure of the Company's earnings from ongoing operations and is generally used to better measure performance and evaluate trends within each segment. EBIT comprises earnings before deducting interest and other financial charges, income taxes, net income attributable to non-controlling interests and preferred share dividends.

Comparable Earnings, Comparable EBITDA, Comparable EBIT, Comparable Interest Expense, Comparable Interest Income and Other, and Comparable Income Taxes comprise Net Income Attributable to Common Shares, EBITDA, EBIT, Interest Expense, Interest Income and Other, and Income Taxes Expense, respectively, adjusted for specific items that are significant but are not reflective of the Company's underlying operations in the period. Specific items are subjective, however, management uses its judgement and informed decision-making when identifying items to be excluded in calculating these non-GAAP measures, some of which may recur. Specific items may include but are not limited to certain fair value adjustments relating to risk management activities, income tax refunds and adjustments, gains or losses on sales of assets, legal and bankruptcy settlements, and write-downs of assets and investments.

The Company engages in risk management activities to reduce its exposure to certain financial and commodity price risks by utilizing instruments such as derivatives. The risk management activities which TransCanada excludes from Comparable Earnings provide effective economic hedges but do not meet the specific criteria for hedge accounting treatment and, therefore, changes in their fair values are recorded in Net Income each period. The unrealized gains or losses from changes in the fair value of these derivative contracts and natural gas inventory in storage are not considered to be representative of the underlying operations in the current period or the positive margin that will be realized upon settlement. As a result, these amounts have been excluded in the determination of Comparable Earnings.

The tables below present a reconciliation of these non-GAAP measures to Net Income Attributable to Common Shares. Comparable Earnings per Share is calculated by dividing Comparable Earnings by the weighted average number of common shares outstanding for the period.

Funds Generated from Operations comprise Net Cash Provided by Operations before changes in operating working capital and allows management to better measure consolidated operating cash flow, excluding fluctuations from working capital balances which may not necessarily be reflective of underlying operations in the same period. A reconciliation of Funds Generated from Operations to Net Cash Provided by Operations is presented in the Funds Generated from Operations table in the Liquidity and Capital Resources section in this MD&A.

Reconciliation of Non-GAAP Measures

For the three months ended September 30 Natural (unaudited) Gas Oil (millions of Pipelines Pipelines Energy Corporate Total dollars) 2011 2010 2011 2010 2011 2010 2011 2010 2011 2010 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Comparable EBITDA 721 714 156 - 399 311 (18) (18) 1,258 1,007 Depreciation and amortization (247) (232) (38) - (101) (94) (3) - (389) (326) ------------------------------------------------------------ Comparable EBIT 474 482 118 - 298 217 (21) (18) 869 681 ----------------------------------------------- ----------------------------------------------- Other Income Statement Items Comparable interest expense (242) (159) Interest expense of joint ventures (13) (13) Comparable interest income and other (5) 27 Comparable income taxes (147) (119) Net income attributable to non-controlling interests (32) (29) Preferred share dividends (13) (14) ------------- Comparable Earnings 417 374 Specific item (net of tax): Risk management activities(1) (33) 3 ------------- Net Income Attributable to Common Shares 384 377 ------------- ------------- For the three months ended September 30 (unaudited)(millions of dollars except per share amounts) 2011 2010 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Comparable Interest Expense (242) (159) Specific item: Risk management activities(1) 2 - ------------------ Interest Expense (240) (159) ------------------ ------------------ Comparable Interest Income and Other (5) 27 Specific item: Risk management activities(1) (39) - ------------------ Interest Income and Other (44) 27 ------------------ ------------------ Comparable Income Taxes (147) (119) Specific item: Income taxes attributable to risk management activities(1) 14 (1) ------------------ Income Taxes Expense (133) (120) ------------------ ------------------ Comparable Earnings per Share $ 0.59 $ 0.54 Specific items (net of tax): Risk management activities (0.04) - ------------------ Net Income per Share $ 0.55 $ 0.54 ------------------ ------------------ (1) For the three months ended September 30 (unaudited)(millions of dollars) 2011 2010 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Risk Management Activities Gains/(Losses): U.S. Power derivatives (3) (3) Canadian Power derivatives (3) - Natural Gas Storage proprietary inventory and derivatives (4) 7 Interest rate derivatives 2 - Foreign exchange derivatives (39) - Income taxes attributable to risk management activities 14 (1) ------------------ Risk Management Activities (33) 3 ------------------ ------------------ For the nine months ended September 30 (unaudited) Natural Gas Oil (millions of Pipelines Pipelines Energy Corporate Total dollars) 2011 2010 2011 2010 2011 2010 2011 2010 2011 2010 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Comparable EBITDA 2,228 2,178 408 - 1,043 824 (57) (66) 3,622 2,936 Depreciation and amortization (735) (736) (95) - (298) (274) (10) - (1,138) (1,010) -------------------------------------------------------------- Comparable EBIT 1,493 1,442 313 - 745 550 (67) (66) 2,484 1,926 ----------------------------------------------- ----------------------------------------------- Other Income Statement Items Comparable interest expense (688) (528) Interest expense of joint ventures (40) (44) Comparable interest income and other 52 33 Comparable income taxes (472) (297) Net income attributable to non-controlling interests (96) (82) Preferred share dividends (41) (31) --------------- Comparable Earnings 1,199 977 Specific item (net of tax): Risk management activities(1) (47) (19) --------------- Net Income Attributable to Common Shares 1,152 958 --------------- --------------- For the nine months ended September 30 (unaudited)(millions of dollars except per share amounts) 2011 2010 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Comparable Interest Expense (688) (528) Specific item: Risk management activities(1) 2 - ------------------ Interest Expense (686) (528) ------------------ ------------------ Comparable Interest Income and Other 52 33 Specific item: Risk management activities(1) (40) - ------------------ Interest Income and Other 12 33 ------------------ ------------------ Comparable Income Taxes (472) (297) Specific item: Income taxes attributable to risk management activities(1) 22 11 ------------------ Income Taxes Expense (450) (286) ------------------ ------------------ Comparable Earnings per Share $ 1.71 $ 1.42 Specific items (net of tax): Risk management activities (0.07) (0.03) ------------------ Net Income per Share $ 1.64 $ 1.39 ------------------ ------------------ (1) For the nine months ended September 30 (unaudited)(millions of dollars) 2011 2010 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Risk Management Activities Gains/(Losses): U.S. Power derivatives (15) (22) Canadian Power derivatives (3) - Natural Gas Storage proprietary inventory and derivatives (13) (8) Interest rate derivatives 2 - Foreign exchange derivatives (40) - Income taxes attributable to risk management activities 22 11 ---------------- Risk Management Activities (47) (19) ---------------- ---------------- Consolidated Results of Operations

Third Quarter Results

Comparable Earnings in third quarter 2011 were $417 million or $0.59 per share compared to $374 million or $0.54 per share for the same period in 2010. Comparable Earnings in third quarter 2011 excluded net unrealized after-tax losses of $33 million ($47 million pre-tax) (2010 - gains of $3 million after tax ($4 million pre-tax)) resulting from changes in the fair value of certain risk management activities.

Comparable Earnings increased $43 million or $0.05 per share in third quarter 2011 compared to the same period in 2010 and reflected the following:

-- decreased Natural Gas Pipelines Comparable EBIT primarily due to lower earnings from the Alberta System as a result of the nine-month impact of the 2010 Alberta System Settlement recorded in third quarter 2010 and the negative impact of a weaker U.S. dollar on U.S. operations, partially offset by incremental earnings from Bison and Guadalajara which were placed in service in January 2011 and June 2011, respectively; -- Oil Pipelines Comparable EBIT as the Company commenced recording earnings from Keystone in February 2011; -- increased Energy Comparable EBIT primarily due to higher realized power prices in Western Power and incremental earnings from the start-up of Halton Hills in September 2010 and Coolidge in May 2011, partially offset by lower volumes and prices in U.S. Power and lower Natural Gas Storage revenues; -- increased Comparable Interest Expense primarily due to decreased capitalized interest upon placing Keystone, Halton Hills and Coolidge into service, partially offset by the positive impact of a weaker U.S. dollar on U.S. dollar-denominated interest expense; -- decreased Comparable Interest Income and Other, which included realized losses in 2011 compared to gains in 2010 on derivatives used to manage the Company's exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income; and -- increased Comparable Income Taxes primarily due to higher pre-tax earnings in 2011 compared to 2010. TransCanada's Net Income Attributable to Controlling Interests in third quarter 2011 was $397 million and Net Income Attributable to Common Shares was $384 million or $0.55 per share compared to $391 million and $377 million or $0.54 per share, respectively, in third quarter 2010.

Nine Month Results

Comparable Earnings in the first nine months of 2011 were $1,199 million or $1.71 per share compared to $977 million or $1.42 per share for the same period in 2010. Comparable Earnings for the first nine months of 2011 excluded net unrealized after-tax losses of $47 million ($69 million pre-tax) (2010 - after-tax losses of $19 million ($30 million pre-tax)) resulting from changes in the fair value of certain risk management activities.

Comparable Earnings increased $222 million or $0.29 per share in the first nine months of 2011 compared to the same period in 2010 and reflected the following:

-- increased EBIT from Natural Gas Pipelines primarily due to incremental earnings from Bison and Guadalajara, which were placed in service in January 2011 and June 2011, respectively, lower general and administrative expenses, and higher earnings from the Canadian Mainline, partially offset by the negative impact of a weaker U.S. dollar; -- Oil Pipelines Comparable EBIT as the Company commenced recording earnings from Keystone in February 2011; -- increased EBIT from Energy primarily due to higher overall realized power prices in Western Power, incremental earnings from the start-up of Halton Hills in September 2010, Coolidge in May 2011 and phase two of Kibby Wind in October 2010, and higher volumes and lower operating expenses due to reduced outage days and higher realized prices at Bruce A, partially offset by lower realized prices and reduced volumes at Bruce B, and decreased third-party and proprietary storage revenues for Natural Gas Storage; -- increased Comparable Interest Expense primarily due to decreased capitalized interest upon placing Keystone and Halton Hills into service, partially offset by the positive impact of a weaker U.S. dollar on U.S. dollar-denominated interest expense; -- increased Comparable Interest Income and Other due to higher realized gains in 2011 compared to 2010 on derivatives used to manage the Company's exposure to foreign exchange rate fluctuations on U.S. dollar- denominated income; -- increased Comparable Income Taxes primarily due to higher pre-tax earnings in 2011 compared to 2010 and higher positive income tax adjustments in 2010; and -- increased Preferred Share Dividends due to new preferred share issues in 2010. TransCanada's Net Income Attributable to Controlling Interests in the first nine months of 2011 was $1,193 million and Net Income Attributable to Common Shares was $1,152 million or $1.64 per share compared to $989 million and $958 million or $1.39 per share, respectively, for the same period in 2010.

Further discussion of the financial results for the three and nine months ended September 30, 2011 is included in the Natural Gas Pipelines, Oil Pipelines, Energy and Other Income Statement Items sections in this MD&A.

U.S. Dollar-Denominated Balances

On a consolidated basis, the impact of changes in the value of the U.S. dollar on U.S. operations is partially offset by other U.S. dollar-denominated items as set out in the following table. The resultant pre-tax net exposure is managed using derivatives, further reducing the Company's exposure to changes in Canadian-U.S. foreign exchange rates. The average U.S. dollar to Canadian dollar exchange rate for the three and nine months ended September 30, 2011 was 0.98 and 0.98, respectively (2010 - 1.04 and 1.04, respectively).

Summary of Significant U.S. Dollar-Denominated Amounts

Three months ended Nine months ended (unaudited) September 30 September 30 (millions of U.S. dollars, pre-tax) 2011 2010 2011 2010 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- U.S. Natural Gas Pipelines Comparable EBIT(1) 173 149 597 522 U.S. Oil Pipelines Comparable EBIT(1) 78 - 210 - U.S. Power Comparable EBIT(1) 63 83 160 164 Interest on U.S. dollar-denominated long-term debt (187) (175) (549) (497) Capitalized interest on U.S. capital expenditures 21 78 93 211 U.S. non-controlling interests and other (48) (39) (143) (120) ---------------------------------------- 100 96 368 280 ---------------------------------------- ---------------------------------------- (1) Refer to the Non-GAAP Measures section in this MD&A for further discussion of Comparable EBIT. Natural Gas Pipelines

Natural Gas Pipelines' Comparable EBIT was $474 million and $1,493 million in the three and nine months ended September 30, 2011, respectively, compared to $482 million and $1,442 million, respectively, for the same periods in 2010.

Natural Gas Pipelines Results

Three months ended Nine months ended (unaudited) September 30 September 30 (millions of dollars) 2011 2010 2011 2010 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Canadian Natural Gas Pipelines Canadian Mainline 264 257 796 785 Alberta System 191 197 557 548 Foothills 31 34 96 102 Other (TQM, Ventures LP) 13 12 38 39 ---------------------------------------- Canadian Natural Gas Pipelines Comparable EBITDA(1) 499 500 1,487 1,474 Depreciation and amortization (181) (167) (542) (535) ---------------------------------------- Canadian Natural Gas Pipelines Comparable EBIT(1) 318 333 945 939 ---------------------------------------- U.S. Natural Gas Pipelines (in U.S. dollars) ANR 58 64 239 238 GTN(2) 29 42 105 125 Great Lakes(3) 26 26 81 83 PipeLines LP(4)(5) 26 26 76 73 Iroquois 15 16 50 51 Bison(2)(6) 8 - 35 - Portland(5)(7) 2 1 15 12 International (Tamazunchale, Guadalajara, TransGas, Gas Pacifico/INNERGY)(8) 27 10 52 34 General, administrative and support costs(9) (2) (16) (6) (25) Non-controlling interests(5) 52 42 148 124 ---------------------------------------- U.S. Natural Gas Pipelines Comparable EBITDA(1) 241 211 795 715 Depreciation and amortization (68) (62) (198) (193) ---------------------------------------- U.S. Natural Gas Pipelines Comparable EBIT(1) 173 149 597 522 Foreign exchange (3) 8 (12) 22 ---------------------------------------- U.S. Natural Gas Pipelines Comparable EBIT(1) (in Canadian dollars) 170 157 585 544 ---------------------------------------- Natural Gas Pipelines Business Development Comparable EBITDA(1) (14) (8) (37) (41) ---------------------------------------- Natural Gas Pipelines Comparable EBIT(1) 474 482 1,493 1,442 ---------------------------------------- ---------------------------------------- Summary: Natural Gas Pipelines Comparable EBITDA(1) 721 714 2,228 2,178 Depreciation and amortization (247) (232) (735) (736) ---------------------------------------- Natural Gas Pipelines Comparable EBIT(1) 474 482 1,493 1,442 ---------------------------------------- ---------------------------------------- (1) Refer to the Non-GAAP Measures section in this MD&A for further discussion of Comparable EBITDA and Comparable EBIT. (2) Results reflect TransCanada's direct ownership interest of 75 per cent effective May 3, 2011 and 100 per cent prior to that date. (3) Represents TransCanada's 53.6 per cent direct ownership interest. (4) Effective May 3, 2011, TransCanada's ownership interest in PipeLines LP decreased from 38.2 per cent to 33.3 per cent. As a result, PipeLines LP's results include TransCanada's decreased ownership in PipeLines LP and TransCanada's effective ownership through PipeLines LP of 8.3 per cent of each of GTN and Bison since May 3, 2011. (5) Non-Controlling Interests reflects Comparable EBITDA for the portions of PipeLines LP and Portland not owned by TransCanada. (6) Includes Bison effective January 14, 2011. (7) Represents TransCanada's 61.7 per cent ownership interest. (8) Includes Guadalajara's operations since June 15, 2011. (9) Represents General, Administrative and Support Costs associated with certain of TransCanada's pipelines. Net Income for Wholly Owned Canadian Natural Gas Pipelines

Three months ended Nine months ended (unaudited) September 30 September 30 (millions of dollars) 2011 2010 2011 2010 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Canadian Mainline 61 66 186 196 Alberta System 51 70 149 145 Foothills 6 7 18 20 ---------------------------------------- ---------------------------------------- Canadian Natural Gas Pipelines

Canadian Mainline's net income for the three and nine months ended September 30, 2011 decreased $5 million and $10 million, respectively, compared to the same periods in 2010 primarily due to a lower rate of return on common equity (ROE), as determined by the National Energy Board (NEB), of 8.08 per cent in 2011 compared to 8.52 per cent in 2010, as well as a lower average investment base. The impact of the lower ROE and average investment base was partially offset by higher incentive earnings in 2011.

The Alberta System's net income was $51 million and $149 million for the three and nine months ended September 30, 2011 compared to $70 million and $145 million, respectively, for the same periods in 2010. The decrease in net income in third quarter 2011 compared to 2010 was primarily due to the regulatory approval and recognition in September 2010 of the Alberta System Settlement, which included a 9.70 per cent ROE on deemed common equity of 40 per cent, effective January 1, 2010. The increase in net income for the first nine months of 2011 compared to 2010 was primarily due to higher incentive earnings.

Canadian Mainline's Comparable EBITDA for the three and nine months ended September 30, 2011 of $264 million and $796 million, respectively, increased $7 million and $11 million, respectively, compared to the same periods in 2010. The Alberta System's Comparable EBITDA was $191 million and $557 million for the three and nine months ended September 30, 2011 compared to $197 million and $548 million, respectively, for the same periods in 2010. EBITDA from the Canadian Mainline and the Alberta System includes net income variances discussed above as well as flow-through items which do not affect net income.

U.S. Natural Gas Pipelines

ANR's Comparable EBITDA for the three and nine months ended September 30, 2011 was US$58 million and US$239 million, respectively, compared to US$64 million and US$238 million, respectively, for the same periods in 2010. The decrease in third quarter 2011 was primarily due to higher operating, maintenance and administration (OM&A) costs. For the nine months ended September 30, 2011, the increase was primarily due to higher transportation and storage revenues, a settlement with a counterparty and increased incidental commodity sales partially offset by higher OM&A costs.

GTN's Comparable EBITDA for the three and nine months ended September 30, 2011 was US$29 million and US$105 million, respectively, compared to US$42 million and US$125 million, respectively, for the same periods in 2010. The decreases were primarily due to TransCanada's sale of a 25 per cent interest in GTN to PipeLines LP in May 2011.

The Bison pipeline was placed in service on January 14, 2011. TransCanada's portion of Comparable EBITDA was US$8 million and US$35 million for the three and nine months ended September 30, 2011, respectively. EBITDA reflects TransCanada's 75 per cent interest in Bison subsequent to the sale of a 25 per cent interest in Bison to PipeLines LP in May 2011 and 100 per cent prior to that date.

Comparable EBITDA for the remainder of the U.S. Natural Gas Pipelines was US$146 million and US$416 million for the three and nine months ended September 30, 2011, respectively, compared to US$105 million and US$352 million, respectively, for the same periods in 2010.

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