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RNS Number:4162L TransCanada Pipelines Ld 01 November 2006 6-K 0000099070 xxxxxxx 10/31/2006 NYSE EDGAR Advantage Service Team (800) 688 - 1933 SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 6-K REPORT OF FOREIGN PRIVATE ISSUER PURSUANT TO RULE 13a-16 OR 15d-16 OF THE SECURITIES EXCHANGE ACT OF 1934 For the month of November 2006 COMMISSION FILE No. 1-8887 TransCanada PipeLines Limited (Translation of Registrant's Name into English) 450 - 1 Street S.W., Calgary, Alberta, T2P 5H1, Canada (Address of Principal Executive Offices) Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F Form 20-F o Form 40-F x Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): o Indicated by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7): o Indicate by check mark whether the registrant by furnishing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934. Yes o No x -------------------------------------------------------------------------------- I The documents listed below in this Section and filed as Exhibits 13.1 to 13.3 and 99.1 to this Form 6-K are hereby filed with the Securities and Exchange Commission for the purpose of being and hereby are incorporated by reference into Registration Statement on Form F-9 (Reg. No. 333-121265) under the Securities Act of 1933, as amended. 13.1 Management's Discussion and Analysis of Financial Condition and Results of Operations of the registrant as at and for the period ended September 30, 2006. 13.2 Consolidated comparative interim unaudited financial statements of the registrant for the period ended September 30, 2006 (included in the registrant's Third Quarter 2006 Quarterly Report). 13.3 U.S. GAAP reconciliation of the consolidated comparative interim unaudited financial statements of the registrant contained in the registrant's Third Quarter 2006 Quarterly Report. 99.1 Schedule of earnings coverage calculations at September 30, 2006. 2 -------------------------------------------------------------------------------- SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. TRANSCANADA PIPELINES LIMITED By: /s/ Gregory A. Lohnes Gregory A. Lohnes Executive Vice-President and Chief Financial Officer By: /s/ G. Glenn Menuz G. Glenn Menuz Vice-President and Controller November 1, 2006 3 -------------------------------------------------------------------------------- EXHIBIT INDEX 13.1 Management's Discussion and Analysis of Financial Condition and Results of Operations of the registrant as at and for the period ended September 30, 2006. 13.2 Consolidated comparative interim unaudited financial statements of the registrant for the period ended September 30, 2006 (included in the registrant's Third Quarter 2006 Quarterly Report). 13.3 U.S. GAAP reconciliation of the consolidated comparative interim unaudited financial statements of the registrant contained in the registrant's Third Quarter 2006 Quarterly Report. 31.1 Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 31.2 Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 32.1 Certification of Chief Executive Officer regarding Periodic Report containing Financial Statements. 32.2 Certification of Chief Financial Officer regarding Periodic Report containing Financial Statements. 99.1 Schedule of earnings coverage calculations at September 30, 2006. 4 -------------------------------------------------------------------------------- Exhibit 13.1 TRANSCANADA PIPELINES LIMITED - THIRD QUARTER 2006 Quarterly Report Management's Discussion and Analysis Management's discussion and analysis (MD&A) dated October 30, 2006 should be read in conjunction with the accompanying unaudited consolidated financial statements of TransCanada PipeLines Limited (TCPL or the company) for the three and nine months ended September 30, 2006. It should also be read in conjunction with the audited consolidated financial statements and the MD&A contained in TCPL's 2005 Report for the year ended December 31, 2005. Additional information relating to TCPL, including the company's Annual Information Form and continuous disclosure documents, is available on SEDAR at www.sedar.com under TCPL. Amounts are stated in Canadian dollars unless otherwise indicated. Capitalized and abbreviated terms that are used but not otherwise defined herein have the meanings provided in the MD&A contained in TCPL's 2005 Report. Forward-Looking Information Certain information in this MD&A includes forward-looking statements. All forward-looking statements are based on TCPL's beliefs and assumptions based on information available at the time the assumptions were made. Forward-looking statements relate to, among other things, anticipated financial performance, business prospects, strategies, regulatory developments, new services, market forces, commitments and technological developments. By its nature, such forward-looking information is subject to various risks and uncertainties, including those material risks discussed in the MD&A contained in TCPL's 2005 Report under "Gas Transmission - Business Risks" and "Power - Business Risks", which could cause TCPL's actual results and experience to differ materially from the anticipated results or other expectations expressed. The material assumptions in making these forward-looking statements are disclosed in this MD& A under the heading "Outlook" and in the MD&A contained in the company's 2005 Report under the headings "TCPL Overview", "TCPL's Strategy", "Gas Transmission - Opportunities and Developments", "Gas Transmission - Outlook", "Power - Opportunities and Developments" and "Power - Outlook". 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 as otherwise stated. TCPL 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. -------------------------------------------------------------------------------- 2 Non-GAAP Measures The company uses the measures "funds generated from operations" and "operating income" in its MD&A. These measures do not have any standardized meaning in generally accepted accounting principles (GAAP) and are therefore considered to be non-GAAP measures. These measures may not be comparable to similar measures presented by other entities. These measures have been used to provide readers with additional information on the company's liquidity and its ability to generate funds to finance its operations. Funds generated from operations is comprised of net cash provided by operations before changes in operating working capital. Operating income is used in the Energy segment and is comprised of revenues plus equity income less operating expenses as shown on the consolidated income statement. Refer to the Energy section in this MD&A for a reconciliation of operating income to net earnings. Results of Operations Effective June 1, 2006, TCPL revised the composition and names of its reportable business segments to Pipelines and Energy. Pipelines is principally comprised of the company's pipelines in Canada, the United States and Mexico. Energy includes the company's power operations, natural gas storage and liquefied natural gas (LNG) businesses in Canada and the U.S. The financial reporting of these segments was aligned to reflect the internal organizational structure of the company. The segmented information in this MD&A has been retroactively restated to reflect the changes in reportable segments. These changes had no impact on consolidated net income. -------------------------------------------------------------------------------- 3 Consolidated Segment Results-at-a-Glance (unaudited) Three months ended September Nine months ended September 30 30 (millions of dollars except per share amounts) 2006 2005 2006 2005 Pipelines Excluding gains 130 149 421 475 Gain on sale of Northern Border Partners, L.P. - - 13 - interest Gain on sale of PipeLines LP units - - - 49 130 149 434 524 Energy Excluding gains 123 98 320 171 Gains related to Power LP - 193 - 193 123 291 320 364 Corporate 40 (12) 27 (29) Net Income Applicable to Common Shares Continuing operations (1) 293 428 781 859 Discontinued operations - - 28 - 293 428 809 859 (1)Net Income Applicable to Common Shares from Continuing Operations comprised of: Excluding gains 293 235 768 617 Gains related to Northern Border Partners, L.P. - 193 13 242 interest, PipeLines LP units and Power LP 293 428 781 859 -------------------------------------------------------------------------------- 4 TCPL's net income applicable to common shares and net income applicable to common shares from continuing operations (net earnings) for third quarter 2006 were $293 million compared to $428 million for third quarter 2005. The 2006 net earnings were lower than 2005 by $135 million primarily due to after-tax gains of $193 million from the sale of the company's interest in Power LP to EPCOR Utilities Inc. (EPCOR) in third quarter 2005. Excluding these gains, the company reported a decrease in Corporate's net expenses and an increase in Energy's net earnings, partially offset by a decrease in Pipelines' net earnings. The $52 million decrease in Corporate's net expenses in third quarter 2006 compared to third quarter 2005 was primarily due to an income tax benefit of approximately $50 million on the resolution of certain income tax matters with taxation authorities and changes in estimates during the quarter. Excluding the gains related to the sale of the Power LP interest in third quarter 2005, Energy's net earnings for third quarter 2006 increased $25 million compared to third quarter 2005 primarily due to higher operating income from Eastern and Western Power Operations and Natural Gas Storage, partially offset by lower operating income from Bruce Power. Pipelines' net earnings for third quarter 2006 decreased $19 million primarily due to lower net earnings from the Canadian Mainline and Alberta System as a result of lower rates of return on common equity (ROE) and lower average investment bases. Net earnings from TCPL's Other Pipelines for third quarter 2006 decreased $6 million compared to third quarter 2005 primarily due to the impact of a weaker U.S. dollar and higher project development and support costs, partially offset by increased net earnings from Portland. TCPL's net income applicable to common shares for the nine months ended September 30, 2006 was $809 million which included net income from discontinued operations of $28 million reflecting bankruptcy settlements with Mirant Corporation and certain of its subsidiaries (Mirant) received in first quarter 2006 related to TCPL's Gas Marketing business divested in 2001. Net income applicable to common shares for the nine months ended September 30, 2005 was $859 million. TCPL's net earnings for the nine months ended September 30, 2006 were $781 million compared to $859 million for the same period in 2005. The decrease of $78 million was primarily due to gains recognized on the sales of PipeLines LP units and the company's interest in Power LP in 2005. Excluding the $49 million after-tax gain on the sale of PipeLines LP units in 2005 and the $13 million after-tax gain on the sale of TCPL's general partner interest in Northern Border Partners, L.P. in 2006, Pipelines' net earnings for the nine months ended September 30, 2006 decreased $54 million compared to the same period in 2005. This decrease was primarily due to lower net earnings from the Canadian Mainline and Alberta System as a result of lower ROE and lower average investment bases in 2006 compared to 2005. In addition, the 2005 net earnings included a positive adjustment of $13 million related to 2004, resulting from the -------------------------------------------------------------------------------- 5 April 2005 National Energy Board (NEB) decision on Canadian Mainline's 2004 Tolls and Tariff Application (Phase II), As well, TCPL's Other Pipelines experienced lower net earnings in 2006, compared to 2005. These decreases were partially offset by higher net earnings from GTN, which included an $18 million ($29 million pre-tax) bankruptcy settlement with Mirant, a former shipper on the Gas Transmission Northwest System. Excluding the $193 million after-tax gains related to the sale of the Power LP interest in 2005, Energy's net earnings for the nine months ended September 30, 2006 increased $149 million compared to the same period in 2005, primarily due to higher operating income from each of its existing businesses as well as a $23 million favourable impact on future income taxes arising from reductions in Canadian federal and provincial income tax rates enacted in second quarter 2006. These increases were partially offset by the loss of operating income associated with the sale in third quarter 2005 of the Power LP investment. The decrease of $56 million in Corporate's net expenses for the nine months ended September 30, 2006 compared to the same period in 2005 was primarily due to the income tax benefit of approximately $50 million in third quarter 2006, as well as a $10 million favourable impact on future income taxes in second quarter 2006 arising from reductions in Canadian federal and provincial income tax rates. Results from each business segment for the three and nine months ended September 30, 2006 are discussed further in the "Pipelines", "Energy" and "Corporate" sections of this MD&A. Funds generated from operations of $661 million and $1,716 million for the three and nine months ended September 30, 2006 increased $157 million and $295 million, respectively, when compared to the same periods in 2005. Pipelines The Pipelines business generated net earnings of $130 million and $434 million for the three and nine months ended September 30, 2006, respectively, compared to $149 million and $524 million for the same periods in 2005. -------------------------------------------------------------------------------- 6 Pipelines Results-at-a-Glance (unaudited) Three months ended September Nine months ended September 30 30 (millions of dollars) 2006 2005 2006 2005 Wholly-Owned Pipelines Canadian Mainline 59 67 179 216 Alberta System 35 38 102 112 GTN 12 14 57 53 Foothills System 5 5 16 16 BC System 2 2 5 5 113 126 359 402 Other Pipelines Great Lakes 10 11 33 36 Iroquois 4 7 11 14 Portland 6 1 10 7 PipeLines LP (1) 2 3 7 Ventures LP 3 3 9 9 TQM 2 2 5 5 TransGas 3 2 8 8 Gas Pacifico/INNERGY 1 2 5 2 Northern Development (1) (1) (3) (3) General, administrative, support costs and other (10) (6) (19) (12) 17 23 62 73 Gain on sale of Northern Border Partners, L.P. - - 13 - interest Gain on sale of PipeLines LP units - - - 49 17 23 75 122 Net Earnings 130 149 434 524 Wholly-Owned Pipelines Canadian Mainline's third quarter 2006 net earnings decreased $8 million compared to third quarter 2005 primarily due to a lower ROE, as determined by the NEB, of 8.88 per cent in 2006 compared to 9.46 per cent in 2005, and a lower average investment base. Net earnings for the nine months ended September 30, 2006 decreased $37 million compared to the corresponding period in 2005. This decrease was due to a combination of a lower ROE and a lower average investment base in 2006, compared to 2005. In addition, the 2005 net earnings included a positive adjustment of $13 million related to 2004, as a result of the NEB's decision in April 2005 on Canadian Mainline's 2004 Tolls and Tariff Application (Phase II). This NEB decision included an increase in the deemed common equity ratio from 33 per cent to 36 per cent for 2004 which was also effective for 2005 under the 2005 tolls settlement with shippers. The Alberta System's net earnings of $35 million and $102 million for the three and nine months ended September 30, 2006 decreased $3 million and $10 million, respectively, compared to the same periods in 2005. The decreases were primarily due to a lower investment base and a lower ROE in 2006. Net earnings in 2006 reflect an ROE of 8.93 per cent on a deemed common equity of 35 per cent compared to an ROE of 9.50 per cent on a deemed common equity of 35 per cent in 2005. -------------------------------------------------------------------------------- 7 GTN's net earnings for the three months ended September 30, 2006 were $12 million, a $2 million decrease from the same period in 2005. This decrease was primarily due to lower transportation revenues in 2006. GTN's net earnings for the nine months ended September 30, 2006 were $57 million, a $4 million increase over the same period in 2005. This increase was primarily due to an $18 million bankruptcy settlement ($29 million pre-tax) in first quarter 2006 with Mirant, a former shipper on the Gas Transmission Northwest System. Partially offsetting this increase were lower transportation revenues, the negative impact of a weaker U.S. dollar and a provision for non-payment of contract transportation revenue from a subsidiary of Calpine Corporation that has filed for bankruptcy protection. Operating Statistics Gas Transmission Nine months ended Canadian Alberta Northwest September 30 Mainline(1) System(2) System(3) Foothills System BC System (unaudited) 2006 2005 2006 2005 2006 2005 2006 2005 2006 2005 Average investment base ($ millions) 7,450 7,839 4,293 4,478 n/a n/a 649 683 207 218 Delivery volumes (Bcf) Total 2,209 2,181 3,033 2,918 592 581 795 788 256 236 Average per day 8.1 8.0 11.1 10.7 2.2 2.1 2.9 2.9 0.9 0.9 -------------------- (1) Canadian Mainline deliveries originating at the Alberta border and in Saskatchewan for the nine months ended September 30, 2006 were 1,694 Bcf (2005 - 1,605 Bcf); average per day was 6.2 Bcf (2005 - 5.9 Bcf). (2) Field receipt volumes for the Alberta System for the nine months ended September 30, 2006 were 3,133 Bcf (2005 - 3,010 Bcf); average per day was 11.5 Bcf (2005 - 11.0 Bcf). (3) The Gas Transmission Northwest System operates under a fixed rate model approved by the United States Federal Energy Regulatory Commission (FERC) and, as a result, the system's current results are not dependent on average investment base. Other Pipelines TCPL's proportionate share of net earnings from Other Pipelines was $17 million for the three months ended September 30, 2006 compared to $23 million for the same period in 2005. Increased net earnings from Portland, primarily due to a bankruptcy settlement received in third quarter 2006, were more than offset by the impact of higher project development and support costs in 2006, lower net earnings from Iroquois reflecting customer bankruptcy settlements received in third quarter 2005 and lower net earnings from PipeLines LP. Net earnings for the nine months ended September 30, 2006 were $75 million compared to $122 million for the corresponding period in 2005. Excluding the $13 million gain on the sale of the Northern Border Partners, L.P. interest in 2006, and the $49 million gain on the sale of PipeLines LP units in 2005, year-to-date net earnings were $11 million lower compared to the same period in 2005. Increased net earnings from Portland due to the bankruptcy settlement received in third quarter 2006 -------------------------------------------------------------------------------- 8 were partially offset by provisions recorded in second and third quarter 2006 for non-payment of contract transportation revenue from a subsidiary of Calpine Corporation that has filed for bankruptcy protection. This increase was more than offset by bankruptcy settlements received by Iroquois in third quarter 2005, a weaker U.S. dollar, reduced ownership in PipeLines LP and higher support costs. In addition, Gas Pacifico/INNERGY generated higher earnings in 2006 as a result of natural gas curtailments that negatively affected 2005 net earnings. As at September 30, 2006, TCPL had advanced $111 million to the Aboriginal Pipeline Group with respect to the Mackenzie Gas Pipeline Project and had capitalized $21 million related to the Keystone pipeline. Energy Energy Results-at-a-Glance (unaudited) Three months ended September 30 Nine months ended September 30 (millions of dollars) 2006 2005 2006 2005 Bruce Power 72 99 176 142 Western Power Operations 84 32 188 90 Eastern Power Operations 40 25 132 69 Natural Gas Storage 24 4 63 15 Power LP Investment - 12 - 29 General, administrative and support costs (35) (30) (100) (93) Operating income 185 142 459 252 Financial charges (5) - (17) (7) Interest income and other 2 2 5 5 Income taxes (59) (46) (127) (79) 123 98 320 171 Gains related to Power LP - 193 - 193 Net Earnings 123 291 320 364 Energy's net earnings were $123 million in third quarter 2006, compared to $291 million in third quarter 2005. In third quarter 2005, TCPL recognized gains of $193 million on the sale of the Power LP interest. Excluding the gains of $193 million in 2005, Energy's net earnings of $123 million in third quarter 2006 increased $25 million compared to $98 million in third quarter 2005 due to higher operating income from Western and Eastern Power Operations and Natural Gas Storage. Partially offsetting these increases were lower operating income from Bruce Power and the loss of income associated with the sale of the Power LP interest in third quarter 2005. Bruce Power's contribution to operating income decreased $27 million in third quarter 2006 compared to third quarter 2005, primarily due to lower overall realized prices, partially offset by higher generation volumes. Western Power Operations' operating income was $52 million higher in third quarter 2006 compared to third quarter 2005 primarily due to incremental earnings from the December 31, 2005 acquisition of the 756 megawatt (MW) Sheerness power purchase arrangement (PPA) and improved -------------------------------------------------------------------------------- 9 margins from higher overall realized power prices and higher market heat rates on uncontracted volumes of power sold. Eastern Power Operations' operating income was $15 million higher in third quarter 2006 compared to third quarter 2005 primarily due to higher overall margins on higher power sales volumes and increased generation from the TC Hydro facilities resulting from higher water flows. Natural Gas Storage operating income increased $20 million in third quarter 2006 compared to third quarter 2005 primarily due to higher contributions from CrossAlta as a result of increased storage capacity and higher natural gas storage spreads. Excluding the gains of $193 million on the sale of the Power LP interest in 2005, Energy's net earnings for the nine months ended September 30, 2006 of $320 million increased $149 million compared to $171 million for the same period in 2005. The increase was due to higher contributions from each of its existing businesses and the $23 million decrease in future income taxes resulting from reductions in Canadian federal and provincial corporate income tax rates enacted in second quarter 2006. Partially offsetting these increases was the loss of operating income associated with the sale of the Power LP interest in third quarter 2005 and reduced earnings due to a weaker U.S. dollar. Bruce Power Effective October 31, 2005, TCPL increased its interest in the Bruce A units through the formation of the Bruce A partnership. Bruce A subleases its facilities from Bruce B. TCPL commenced proportionately consolidating its investments in Bruce A and Bruce B effective October 31, 2005. The following Bruce Power financial results reflect the operations of the full six-unit facility for both periods. -------------------------------------------------------------------------------- 10 Bruce Power Results-at-a-Glance(1) Three months ended September Nine months ended September 30 30 (unaudited) 2006 2005 2006 2005 Bruce Power (100 per cent basis) (millions of dollars) Revenues Power 478 635 1,396 1,431 Other (2) 15 7 43 22 493 642 1,439 1,453 Operating expenses Operations and maintenance (210) (207) (656) (640) Fuel (26) (21) (68) (58) Supplemental rent (42) (41) (127) (123) Depreciation and amortization (34) (48) (99) (145) (312) (317) (950) (966) Revenues, net of operating expenses 181 325 489 487 Financial charges under equity accounting - (18) - (52) 181 307 489 435 TCPL's proportionate share 69 97 170 137 Adjustments 3 2 6 5 TCPL'S operating income from Bruce Power (3) 72 99 176 142 Bruce Power - Other Information Plant availability Bruce A 86% 76% Bruce B 92% 94% Combined Bruce Power 90% 88% 88% 80% Sales volumes (GWh) (4) Bruce A - 100 per cent 2,850 7,440 Bruce B - 100 per cent 6,540 19,790 Combined Bruce Power - 100 per cent 9,390 9,130 27,230 24,648 TCPL' s proportionate share 3,448 2,882 9,848 7,786 Results per MWh (5) Bruce A revenues $ 59 $ 58 Bruce B revenues $ 48 $ 49 Combined Bruce Power revenues $ 51 $ 70 $ 51 $ 58 Fuel $ 3 $ 2 $ 2 $ 2 Total operating expenses(6) $ 32 $ 35 $ 34 $ 39 Percentage of output sold to spot market 33% 60% 37% 53% -------------------- (1) All information in the table includes adjustments to eliminate the effects of inter-partnership transactions between Bruce A and Bruce B. (2) Includes fuel cost recoveries for Bruce A of $9 million and $19 million, respectively, for the three and nine months ended September 30, 2006. (3) TCPL's consolidated equity income includes $99 million and $142 million, respectively, for the three and nine months ended September 30, 2005 representing TCPL's 31.6 per cent share of Bruce Power earnings for the period. (4) Gigawatt hours. (5) Megawatt hours. (6) Net of fuel cost recoveries. -------------------------------------------------------------------------------- 11 TCPL's operating income of $72 million from its combined investment in Bruce Power decreased $27 million in third quarter 2006 compared to third quarter 2005, primarily due to the negative impact of lower realized prices, partially offset by the positive impact of higher generation volumes. TCPL's share of Bruce Power's generation for third quarter 2006 increased 566 GWh to 3,448 GWh compared to third quarter 2005 generation of 2,882 GWh as a result of fewer planned maintenance outage days in third quarter 2006 compared to third quarter 2005 and an increased ownership interest in the Bruce A facilities. Bruce Power prices achieved during third quarter 2006 (excluding other revenues) were $51 per MWh, compared to $70 per MWh in third quarter 2005. Bruce Power's operating expenses (net of fuel cost recoveries) in third quarter 2006 decreased to $32 per MWh from $35 per MWh in third quarter 2005 primarily due to increased output in third quarter 2006. Approximately 22 reactor days of planned maintenance outages as well as approximately 20 reactor days of unplanned outages occurred on the six operating units in third quarter 2006. In third quarter 2005, Bruce Power experienced 32 reactor days of planned maintenance outages and 21 reactor days of unplanned outages. The Bruce Power units ran at a combined average availability of 90 per cent in third quarter 2006, compared to an 88 per cent average availability during third quarter 2005. TCPL's operating income from its combined investment in Bruce Power for the nine months ended September 30, 2006 was $176 million compared to $142 million for the same period in 2005. The increase of $34 million was primarily due to higher sales volumes resulting from increased plant availability and an increased ownership interest in the Bruce A facilities. Combined Bruce Power prices achieved for the nine months ended September 30, 2006 (excluding other revenues) were $51 per MWh compared to $58 per MWh for the same period in 2005. Bruce Power's combined operating expenses (net of fuel cost recoveries) decreased to $34 per MWh for the nine months ended September 30, 2006 from $39 per MWh in 2005 primarily due to increased output in 2006. The Bruce units ran at a combined average availability of 88 per cent in the nine months ended September 30, 2006 compared to 80 per cent in the same period of 2005. The overall plant availability percentage in 2006 is still expected to be in the low 90s for the four Bruce B units and in the low 80s for the two operating Bruce A units. A planned one month maintenance outage on Bruce A Unit 3 during first quarter 2006 and a planned two month maintenance outage on Bruce A Unit 4 during second quarter 2006 were completed. The planned maintenance outage for 2006 for Bruce B Unit 8 began in September 2006 and is expected to last approximately two months. Income from Bruce B is directly impacted by the fluctuations in wholesale spot market prices for electricity. Income from both Bruce A and Bruce B units is impacted by overall plant availability, which in turn is impacted by scheduled and unscheduled maintenance. As a result of a contract with the Ontario Power Authority (OPA), in first quarter 2006 all of the output from Bruce A was sold at a -------------------------------------------------------------------------------- 12 fixed price of $57.37 per MWh (before recovery of fuel costs from the OPA) and sales from the Bruce B Units 5 to 8 were subject to a floor price of $45 per MWh. Both of these reference prices are adjusted annually on April 1 for inflation and other potential adjustments in accordance with the terms of the contract with OPA. Effective April 1, 2006, the Bruce A price is $58.63 per MWh and the Bruce B floor price is $45.99 per MWh. Payments received pursuant to the Bruce B floor price mechanism may be subject to refund dependent on spot prices over the term of the contract. Bruce B net earnings included no amounts received under this floor mechanism to date. To further reduce its exposure to spot market prices, Bruce B has entered into fixed price sales contracts to sell forward approximately 3,300 GWh of output for the remainder of 2006 and 6,700 GWh of output for 2007. The capital cost of Bruce A's four unit, seven year restart and refurbishment project is expected to total approximately $4.25 billion with TCPL's share being approximately $2.125 billion. As at September 30, 2006, Bruce A had incurred $806 million with respect to the restart and refurbishment project. Western Power Operations Western Power Operations Results-at-a-Glance (unaudited) Three months ended September Nine months ended September 30 30 (millions of dollars) 2006 2005 2006 2005 Revenues Power 311 165 807 480 Other (1) 32 29 134 108 343 194 941 588 Cost of sales Power (194) (105) (534) (313) Other (1) (27) (17) (103) (67) (221) (122) (637) (380) Other costs and expenses (32) (34) (100) (102) Depreciation (6) (6) (16) (16) Operating income 84 32 188 90 -------------------- (1) Other includes Cancarb Thermax and natural gas. Western Power Operations Sales Volumes (unaudited) Three months ended September 30 Nine months ended September 30 (GWh) 2006 2005 2006 2005 Supply Generation 599 544 1,622 1,691 Purchased Sundance A & B and Sheerness PPAs 3,283 1,593 9,520 5,137 Other purchases 455 658 1,460 2,003 4,337 2,795 12,602 8,831 Contracted vs. Spot Contracted 2,818 2,423 7,976 7,570 Spot 1,519 372 4,626 1,261 4,337 2,795 12,602 8,831 -------------------------------------------------------------------------------- 13 Western Power Operations' operating income of $84 million and $188 million for the three and nine months ended September 30, 2006 increased $52 million and $98 million, respectively, compared to the same periods in 2005. These increases were primarily due to incremental earnings from the December 31, 2005 acquisition of the 756 MW Sheerness PPA and increased margins from a combination of higher overall realized power prices and higher market heat rates on uncontracted volumes of power sold. The market heat rate is determined by dividing the average price of power per MWh by the average price of natural gas per gigajoule (GJ) for a given period. Market heat rates in third quarter 2006 increased by approximately 141 per cent as a result of an approximate 42 per cent ($27.95 per MWh) increase in spot market power prices, while average spot market natural gas prices in Alberta decreased by approximately 39 per cent ($3.45 per GJ) compared to the same quarter in 2005. A significant portion of power sales volumes were sold by the company into the spot market in third quarter 2006, compared to 2005, due to the acquisition of the Sheerness PPA on December 31, 2005. TCPL manages the sale of its supply volumes on a portfolio basis. Depending on market conditions, TCPL will commit a portion of this supply to long-term sales arrangements with the remaining volumes subject to spot market price volatility. This approach to portfolio management assists in minimizing costs in situations where TCPL would otherwise have to purchase electricity in the open market to fulfill its contractual sales obligations. Power revenues and cost of sales increased in third quarter 2006 compared to third quarter 2005 primarily due to the acquisition of the Sheerness PPA, effective December 31, 2005, and higher overall realized power prices in third quarter 2006. Generation volumes of 599 GWh in third quarter 2006 increased 55 GWh compared to third quarter 2005 primarily due to the return to service of the Bear Creek facility in August 2006 and planned maintenance outages at the Carseland facility in 2005. The company's purchased power volumes and percentage of power volumes sold in the Alberta spot market increased in third quarter 2006 compared to 2005 due to the acquisition of the Sheerness PPA. A significant portion of the Sheerness PPA purchased volumes were not sold under contract and were subject to spot market prices. As a result, approximately 35 per cent of power sales volumes were sold into the spot market in third quarter 2006 compared to 13 per cent in third quarter 2005. To reduce its exposure to spot market prices on uncontracted volumes, as at September 30, 2006, Western Power Operations had fixed price power sales contracts to sell approximately 3,200 GWh for the remainder of 2006 and approximately 10,300 GWh for 2007. -------------------------------------------------------------------------------- 14 Eastern Power Operations Eastern Power Operations Results-at-a-Glance (unaudited) Three months ended September Nine months ended September 30 30 (millions of dollars) 2006 2005 2006 2005 Revenue Power 192 136 527 380 Other (1) 49 111 224 254 241 247 751 634 Cost of sales Power (94) (70) (284) (183) Other (1) (47) (98) (196) (237) (141) (168) (480) (420) Other costs and expenses (53) (46) (118) (127) Depreciation (7) (8) (21) (18) Operating income 40 25 132 69 -------------------- (1) Other includes natural gas. Eastern Power Operations Sales Volumes (unaudited) Three months ended September Nine months ended September 30 30 (GWh) 2006 2005 2006 2005 Supply Generation 1,039 600 2,693 2,006 Purchased 934 833 2,331 2,138 1,973 1,433 5,024 4,144 Contracted vs. Spot Contracted 1,829 1,348 4,715 3,765 Spot 144 85 309 379 1,973 1,433 5,024 4,144 Eastern Power Operations' operating income was $15 million higher in third quarter 2006 compared to third quarter 2005 primarily due to higher overall margins on higher sales volumes and increased generation from the TC Hydro facilities resulting from higher water flows. The 550 MW Becancour cogeneration plant was placed in service in late third quarter 2006 and therefore its contribution to operating income was not significant. Operating income for the nine months ended September 30, 2006 was $132 million or $63 million higher than the $69 million earned in the same period of 2005. The increase was primarily due to incremental income from the April 1, 2005 acquisition of the TC Hydro generation assets, a $10 million ($16 million pre-tax) first quarter 2005 one-time restructuring payment from OSP to its natural gas fuel suppliers, margins earned in first quarter 2006 on transportation related to unutilized OSP natural gas fuel, higher overall margins on higher power sales volumes and profits earned on natural gas purchased and resold under the OSP gas supply contracts. Partially offsetting these increases was the negative impact of a weaker U.S. dollar in 2006 compared to 2005. Generation volumes in third quarter 2006 increased 439 GWh to 1,039 GWh compared to third quarter 2005 due to increased dispatch -------------------------------------------------------------------------------- 15 of the OSP facility, increased output from the TC Hydro generation assets resulting from higher water flows and the placing in service of the Becancour facility. Power revenues of $192 million increased $56 million in third quarter 2006 compared to third quarter 2005 due to increased sales volumes and higher realized prices. Power cost of sales of $94 million was higher in third quarter 2006 compared to third quarter 2005 due to the impact of increased purchased volumes and higher prices. Purchased power volumes of 934 GWh were higher in third quarter 2006 to supply increased sales volumes. Third quarter 2006 other revenue and other cost of sales of $49 million and $47 million, respectively, decreased year-over-year primarily as a result of a reduction in the quantity of natural gas being resold under the OSP natural gas sales contracts and lower gas prices. Other costs and expenses in third quarter 2006 of $53 million, which includes fuel gas consumed in generation, increased from the prior year primarily as a result of the placing in service of the Becancour facility. In third quarter 2006, approximately seven per cent of power sales volumes were sold into the spot market compared to approximately six per cent in third quarter 2005. Eastern Power Operations is focused on selling the majority of its power under contract to wholesale, commercial and industrial customers while managing a portfolio of power supplies sourced from its own generation and wholesale power purchases. To reduce its exposure to spot market prices, as at September 30, 2006, Eastern Power Operations had entered into fixed price power sales contracts to sell approximately 2,500 GWh for the remainder of 2006 and approximately 9,600 GWh for 2007, although certain contracted volumes are dependent on customer usage levels. -------------------------------------------------------------------------------- 16 Power Sales Volumes and Plant Availability Power Sales Volumes (unaudited) Three months ended September Nine months ended September 30 30 (GWh) 2006 2005 2006 2005 Bruce Power (1) 3,448 2,882 9,848 7,786 Western Power Operations (2) 4,337 2,795 12,602 8,831 Eastern Power Operations (3) 1,973 1,433 5,024 4,144 Power LP Investment (4) - 445 - 1,865 Total 9,758 7,555 27,474 22,626 -------------------- (1) Sales volumes reflect TCPL's proportionate share of Bruce Power output. (2) The Sheerness PPA volumes are included in Western Power Operations effective December 31, 2005. (3) TC Hydro is included in Eastern Power Operations effective April 1, 2005. Becancour is included in Eastern Power Operations effective September 17, 2006. (4) TCPL operated and managed Power LP until August 31, 2005. The volumes in the table represent 100 per cent of Power LP's sales volumes up to August 31, 2005. Weighted Average Plant Availability (1) Three months ended September Nine months ended September 30 30 (unaudited) 2006 2005 2006 2005 Bruce Power 90% 88% 88% 80% Western Power Operations 94% 89% 86% 86% Eastern Power Operations (2) 98% 84% 97% 81% Power LP Invest ment (3) 96% 93% All plants, excluding Bruce Power 97% 88% 94% 85% All plants 93% 89% 90% 81% -------------------- (1) Plant availability represents the percentage of time in the period that the plant is available to generate power, even if the plant is not operating, reduced by planned and unplanned outages. (2) TC Hydro is included in Eastern Power Operations effective April 1, 2005. Becancour is included in Eastern Power Operations effective September 17, 2006. (3) Power LP is included up to August 31, 2005. Natural Gas Storage Natural Gas Storage operating income of $24 million and $63 million for the three and nine months ended September 30, 2006, respectively, increased $20 million and $48 million, respectively, compared to the same periods in 2005. The increases were primarily due to higher contributions from CrossAlta as a result of increased capacity and higher natural gas storage spreads, and income from other contracted third party natural gas storage capacity in Alberta. -------------------------------------------------------------------------------- 17 General, Administrative and Support Costs General, administrative and support costs of $35 million and $100 million for the three and nine months ended September 30, 2006, respectively, increased $5 million and $7 million compared to the same periods in 2005. The increases were primarily due to higher business development costs. As at September 30, 2006, TCPL had capitalized $26 million related to the Broadwater LNG project. Corporate Net earnings from Corporate for the three and nine months ended September 30, 2006 were $40 million and $27 million, respectively, compared to net expenses of $12 million and $29 million for the same periods in 2005. The $52 million decrease in net expenses for third quarter 2006, compared to the same period in 2005, was primarily due to an income tax benefit of approximately $50 million on the resolution of certain income tax matters with taxation authorities and changes in estimates during the quarter. The $56 million decrease in net expenses for the nine months ended September 30, 2006, compared to the same period in 2005, was primarily due to the $50 million income tax benefit in third quarter 2006, as well as a $10 million favourable impact on future income taxes arising from reductions in Canadian federal and provincial corporate income tax rates enacted in second quarter 2006. In addition, net earnings were positively impacted by increased interest income and other and the favourable impact of a weaker U.S. dollar. Partially offsetting these decreases in net expenses were income tax refunds and positive income tax adjustments recorded in the nine months ended September 30, 2005. Liquidity and Capital Resources Funds Generated from Operations Funds generated from operations were $661 million and $1,716 million for the three and nine months ended September 30, 2006, respectively, compared to $504 million and $1,421 million for the same periods in 2005. TCPL expects that its ability to generate adequate amounts of cash in the short and long term, when needed, and to maintain financial capacity and flexibility to provide for planned growth remains substantially unchanged since December 31, 2005. Investing Activities In the three and nine months ended September 30, 2006, capital expenditures totalled $372 million (2005 - $166 million) and $1,002 million (2005 - $409 million), respectively, and related primarily to the restart and refurbishment of Bruce A Units 1 and 2, construction of new power plants, the Tamazunchale pipeline and the Edson natural gas storage facilities as well as maintenance and other capacity capital -------------------------------------------------------------------------------- 18 expenditures in the Pipelines business. Acquisitions for the nine months ended September 30, 2006 were $358 million (2005 - $632 million). In second quarter 2006, PipeLines LP acquired an additional 20 per cent general partnership interest in Northern Border. In 2005, TCPL acquired TC Hydro generation assets and an additional 3.52 per cent interest in Iroquois. In the three and nine months ended September 30, 2006, disposition of assets, net of current income tax, generated nil (2005 - $444 million) and $23 million (2005 - $546 million), respectively. The disposition in 2006 related to the sale of TCPL's 17.5 per cent general partner interest in Northern Border Partners, L.P. The dispositions in 2005 related to the sale of TCPL's ownership interest in Power LP and PipeLines LP units. Financing Activities TCPL retired $4 million and $352 million of long-term debt in the three and nine months ended September 30, 2006, respectively. TCPL issued $1,250 million of long-term debt in the nine months ended September 30, 2006. For the three months ended September 30, 2006, notes payable increased $4 million while, for the nine months ended September 30, 2006, notes payable decreased $449 million. In October 2006, the company issued $400 million of 4.65 per cent medium-term notes, due October 2016. The proceeds were used to reduce the company's notes payable. Cash and short-term investments for the three and nine months ended September 30, 2006 increased $18 million and $118 million, respectively. Dividends On October 30, 2006, TCPL's Board of Directors declared a dividend for the quarter ending December 31, 2006 in an aggregate amount equal to the aggregate quarterly dividend to be paid on January 31, 2007 by TransCanada Corporation on the issued and outstanding common shares as at the close of business on December 29, 2006. The board also declared regular dividends on TCPL's preferred shares. Contractual Obligations Energy's future capital expenditure obligations at September 30, 2006 increased compared to December 31, 2005, primarily as a result of TCPL's commitment with OPA to construct the Portland Energy Centre (PEC), as discussed in the Other Recent Developments section of this MD&A. Other than the PEC commitment, there have been no material changes to TCPL's contractual obligations from December 31, 2005 to September 30, 2006, including payments due for the next five years and thereafter. For further information on these contractual obligations, refer to the MD&A in TCPL's 2005 Report. -------------------------------------------------------------------------------- 19 Financial and Other Instruments The following represents the material changes to the company's financial instruments since December 31, 2005. Energy Price Risk Management The company executes power, natural gas and heat rate derivatives for overall management of its asset portfolio. Heat rate contracts are contracts for the sale or purchase of power that are priced based on a natural gas index. The fair value and notional volumes of contracts for differences and the swap, future, option and heat rate contracts are shown in the tables below. Power September 30, 2006 (unaudited) December 31, 2005 Asset/(Liability) Accounting Fair Fair (millions of dollars) Treatment Value Value Power - swaps and contracts for differences (maturing 2006 to 2011) Hedge (89) (130) (maturing 2006 to 2010) Non-hedge (6) 13 Gas - swaps and futures (maturing 2006 to 2016) Hedge (58) 17 (maturing 2006 to 2008) Non-hedge 26 (11) Notional Volumes September 30, 2006 Accounting Power (GWh) Gas (Bcf) (unaudited) Treatment Purchases Sales Purchases Sales Power - swaps and contracts for differences (maturing 2006 to 2011) Hedge 4,946 11,189 - - (maturing 2006 to 2010) Non-hedge 1,465 917 - - Gas - swaps and futures (maturing 2006 to 2016) Hedge - - 81 60 (maturing 2006 to 2008) Non-hedge - - 15 20 Heat rate contracts (maturing 2006) Non-hedge - 12 - - Notional Volumes Accounting Power (GWh) Gas (Bcf) December 31, 2005 Treatment Purchases Sales Purchases Sales Power - swaps and contracts for differences Hedge 2,556 7,780 - - Non-hedge 1,332 456 - - Gas - swaps and futures Hedge - - 91 69 Non-hedge - - 15 18 -------------------------------------------------------------------------------- 20 Certain of the company's joint ventures use power derivatives to manage energy price risk exposures. The company's proportionate share of the fair value of these outstanding power sales derivatives at September 30, 2006 was $55 million (December 31, 2005 - $(38) million) and relates to contracts which cover the period 2006 to 2010. The company's proportionate share of the notional sales volumes associated with this exposure at September 30, 2006 was 4,500 GWh (December 31, 2005 - 2,058 GWh). Risk Management TCPL's market, financial and counterparty risks remain substantially unchanged since December 31, 2005. For further information on risks, refer to the MD&A in TCPL's 2005 Report. Controls and Procedures As of September 30, 2006, TCPL's management, together with TCPL's President and Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the design and operation of the company's disclosure controls and procedures. Based on this evaluation, the President and Chief Executive Officer and the Chief Financial Officer of TCPL have concluded and reaffirmed that the disclosure controls and procedures are effective. There were no changes in TCPL's internal control over financial reporting during the most recent fiscal quarter that have materially affected or are reasonably likely to materially affect TCPL's internal control over financial reporting. Critical Accounting Policy TCPL's critical accounting policy, which remains unchanged since December 31, 2005, is the use of regulatory accounting for its regulated operations. For further information on this critical accounting policy, refer to the MD&A in TCPL's 2005 Report. Critical Accounting Estimates Since a determination of many assets, liabilities, revenues and expenses is dependent upon future events, the preparation of the company's consolidated financial statements requires the use of estimates and assumptions which have been made using careful judgment. TCPL's critical accounting estimate from December 31, 2005 continues to be depreciation expense. For further information on this critical accounting estimate, refer to the MD&A in TCPL's 2005 Report. Outlook In 2006, TCPL expects higher net income than originally anticipated due to the income tax benefit of approximately $50 million on the resolution of certain income tax matters with taxation authorities and changes in estimates during the quarter, the $33 million favourable impact of Canadian federal and provincial corporate income tax rate reductions, improved Energy results to date and net income from discontinued operations as a result of bankruptcy settlements received from Mirant. -------------------------------------------------------------------------------- 21 Excluding these impacts, the company's outlook is relatively unchanged since December 31, 2005. For further information on outlook, refer to the MD&A in TCPL's 2005 Report. In 2006, TCPL will continue to direct its resources towards long-term growth opportunities that will strengthen its financial performance and create long-term value for shareholders. The company's net income and cash flow combined with a strong balance sheet continue to provide the financial flexibility for TCPL to make disciplined investments in its core businesses of Pipelines and Energy. Credit ratings on senior unsecured debt assigned by Dominion Bond Rating Service Limited (DBRS), Moody's and Standard & Poor's remain at A, A2 and A-, respectively. DBRS and Moody's both maintain a 'stable' outlook on their ratings and Standard & Poor's maintains a 'negative' outlook on its rating. Other Recent Developments Pipelines Wholly-Owned Pipelines Gas Transmission Northwest System In June 2006, the Gas Transmission Northwest System filed a rate case with the FERC. The comprehensive filing requests a number of tariff changes including an increase in rates for transportation services. The current rates are based on the last rate case filed in 1994. The proposed rates include an ROE of 14.5 per cent, a common equity ratio of 62.99 per cent and a depreciation rate for the transmission plant of 2.76 per cent. GTN anticipates receiving a procedural order from the FERC in first quarter 2007, and this order will establish a timeline for GTN's rate case proceedings. North Baja Pipeline Expansion On February 7, 2006, TCPL's North Baja Pipeline filed an application with the FERC to expand and modify its existing system to facilitate the importation of more than 2.7 billion cubic feet per day (Bcf /d) of regasified LNG from Mexico into the California and Arizona markets. Specifically, North Baja proposes to modify its existing system to accommodate bi-directional natural gas flow, construct a new meter station and a 36 inch pipeline interconnect with Southern California Gas Company (SoCal Gas), construct approximately 74 kilometres of lateral facilities to serve electric generation facilities, and loop its entire approximate 129 kilometres existing system with a combination of 42 inch and 48 inch diameter pipeline. On October 6, 2006, the FERC -------------------------------------------------------------------------------- 22 issued a preliminary determination approving all aspects of North Baja's proposal other than those related to environmental issues, which will be the subject of a future order. Tamazunchale In September 2006, TCPL entered the commissioning phase of construction of its Tamazunchale pipeline in east-central Mexico. The 130 kilometre pipeline is expected to begin commercial operations in December 2006 and will initially transport 170 million cubic feet per day (mmcf/d) of natural gas from the PEMEX gas pipeline system near Naranjos, Veracruz, Mexico to an electricity generation station near Tamazunchale, San Luis Potosi, Mexico. Under the current contract with the Comision Federal de Electricidad, the capacity of the Tamazunchale pipeline will be expanded beginning in 2009 to approximately 430 mmcf/d to meet the needs of two additional proposed power plants near Tamazunchale. Other Pipelines In September 2006, Northern Border reached a settlement with its participant customers regarding its pending rate case before the FERC. The settlement, which establishes maximum long-term rates and charges for transportation on the Northern Border system, and is supported by the FERC trial staff, was certified by the administrative law judge presiding over the case and forwarded to the FERC for approval. The approval process is expected to be completed by late 2006. -------------------------------------------------------------------------------- 23 Northern Development Mackenzie Gas Pipeline Project public hearings are expected to conclude in April 2007. The hearings are held by a Joint Review Panel, which focuses on environmental and socio-economic impacts, and the NEB, which is reviewing all other matters including pipeline engineering, safety, need and economic feasibility. Concurrently, the project proponents are re-assessing the capital cost estimate and construction schedule for the project, in light of overall industry cost escalations and labour shortages. Keystone Pipeline In April 2006, TCPL filed an application with the U.S. Department of State for a Presidential Permit authorizing the construction, operation and maintenance of the Keystone pipeline. In September 2006, the Department of State issued a formal notice of the application as well as a Notice of Intent to prepare an Environmental Impact Statement for the project. In June 2006, TCPL Keystone Pipeline LP (Keystone LP) filed a petition with the Illinois Commerce Commission for a certificate authorizing the pipeline and granting authority to exercise eminent domain. The matter is expected to go to hearing in mid-November 2006. In June 2006, TCPL and Keystone LP filed an application with the NEB seeking approval to transfer a portion of the Canadian Mainline to the Keystone pipeline. As part of the transfer application, TCPL is also seeking approval to reduce the Canadian Mainline's rate base by the net book value (NBV) of the transferred facilities and Keystone LP is seeking approval to add the NBV of the facilities to the Keystone pipeline rate base. The transfer application is the first of two major regulatory applications required to obtain approvals necessary to construct the Canadian portion of the Keystone pipeline. An oral public hearing on the application commenced on October 23, 2006. TCPL filed its Preliminary Information Package for required new facilities with the NEB in July 2006. TCPL expects to file an application with the NEB for a certificate of public convenience and necessity to construct the required new facilities later this year once environmental assessment work is completed. The project will also require regulatory approvals from various U.S. agencies. Energy Bruce Power The Bruce A restart and refurbishment project reached another key milestone in third quarter 2006 with the delivery of the first three of 16 steam generators that will be installed in Units 1 and 2 as part of the restart project. The restart of Units 1 and 2 is expected to return another 1,500 MW of generating capacity to Ontario with the first unit expected to restart in late 2009. Bruce Power also plans to replace the eight steam generators in each of Units 3 and 4. Based on results -------------------------------------------------------------------------------- 24 from recent inspections, it is expected that the steam generators in Unit 4 can continue to operate until 2010 and then be replaced. The refurbishment of Unit 3 is expected to begin in late 2009. In August 2006, Bruce Power filed an application with the Canadian Nuclear Safety Commission to prepare the Bruce site for potential future construction of new reactors at the facility. Cartier Wind Construction continues on the 109.5 MW Baie des Sables wind farm and remains on schedule for completion by December 2006. Construction continues on the 100.5 MW Anse a Valleau wind farm, the second of the six wind farms that comprise the Cartier Wind project in the Gaspe region of Quebec. The Anse a Valleau wind farm is expected to deliver energy to the Hydro-Quebec grid by December 2007. TCPL has a 62 per cent interest in the Cartier Wind project which was awarded six projects by Hydro-Quebec Distribution in October 2004 representing a total of 739.5 MW. Portlands Energy Centre In third quarter 2006, Portlands Energy Centre L.P. (Portlands Energy) signed a 20 year Accelerated Clean Energy Supply (ACES) contract with OPA for a 550 MW high-efficiency, combined-cycle natural gas generation plant to be constructed in downtown Toronto. Portlands Energy is a limited partnership between Ontario Power Generation and TCPL with both parties having a 50 per cent interest. The capital cost of PEC is estimated to be approximately $730 million. PEC is expected to be operational in simple-cycle mode, delivering 340 MW of electricity to the City of Toronto to meet peak summer demand beginning June 1, 2008 with full completion expected in second quarter 2009. Becancour In September 2006, construction was completed on the 550 MW Becancour cogeneration plant. The plant, near Trois-Rivieres, Quebec, was placed in service in late third quarter 2006 and began fulfilling its obligations to supply electricity to Hydro-Quebec Distribution under a long-term contract. Cacouna The Canadian Environmental Assessment Agency and the Bureau des Audiences Publiques sur l'Environnement (BAPE) joint review panel on the proposed Cacouna Energy project requested an extension to consider additional documents and refinements to this proposed project. Cacouna Energy anticipates receiving government approvals in early 2007. Cacouna Energy is a partnership between TCPL and Petro-Canada. The proposed terminal would be capable of receiving, storing, and re-gasifying imported LNG -------------------------------------------------------------------------------- 25 with an average throughput capacity of approximately 500 mmcf/d of natural gas. Broadwater The U.S. Coast Guard released its Waterways Suitability Report on the Broadwater Energy project on September 22, 2006. The report determined that the proposed LNG facility in the New York State waters of Long Island Sound can be operated safely and securely and has provided a series of mitigation measures. This report represents another key milestone in the ongoing regulatory review of the Broadwater Energy project. Broadwater Energy is a partnership between TCPL and Shell U.S. Gas & Power. The Broadwater terminal would be capable of receiving, storing, and re-gasifying imported LNG with an average send-out capacity of approximately one Bcf/d of natural gas. Edson Construction of the Edson natural gas storage facility in Alberta was substantially complete at the end of third quarter 2006 and commissioning will take place in fourth quarter 2006. Storage capacity is expected to be available later this year. The Edson facility is expected to have a working natural gas capacity of approximately 60 petajoules and will connect to the Alberta System. Share Information As at September 30, 2006, TCPL had 483,344,109 issued and outstanding common shares. In addition, there were 4,000,000 Series U and 4,000,000 Series Y Cumulative First Preferred shares issued and outstanding as at September 30, 2006. -------------------------------------------------------------------------------- 26 Selected Quarterly Consolidated Financial Data(1) (unaudited) 2006 2005 2004 (millions of dollars except per share Third Second First Fourth Third Second First Fourth amounts) Revenues 1,850 1,685 1,894 1,771 1,494 1,449 1,410 1,480 Net Income Continuing operations 293 244 244 350 428 199 232 184 Discontinued operations - - 28 - - - - - 293 244 272 350 428 199 232 184 Share Statistics Net income per share - Basic Continuing operations $ 0.60 $ 0.51 $ 0.50 $ 0.72 $ 0.89 $ 0.41 $ 0.48 $ 0.38 Discontinued operations - - 0.06 - - - - - $ 0.60 $ 0.51 $ 0.56 $ 0.72 $ 0.89 $ 0.41 $ 0.48 $ 0.38 -------------------- (1) The selected quarterly consolidated financial data has been prepared in accordance with Canadian GAAP. Certain comparative figures have been reclassified to conform with the current year's presentation. For a discussion on the factors affecting the comparability of the financial data, including discontinued operations, refer to Note 1, Note 2 and Note 23 of TCPL's 2005 audited consolidated financial statements. Factors Impacting Quarterly Financial Information In the Pipelines business, which consists primarily of the company's investments in regulated pipelines, annual revenues and net earnings fluctuate over the long term based on regulators' decisions and negotiated settlements with shippers. Generally, quarter over quarter revenues and net earnings during any particular fiscal year remain relatively stable with fluctuations arising as a result of adjustments being recorded due to regulatory decisions and negotiated settlements with shippers and due to items outside of the normal course of operations. In the Energy business, which primarily builds, owns and operates electrical power generation plants, sells electricity and invests in natural gas storage facilities, quarter over quarter revenues and net earnings are affected by seasonal weather conditions, customer demand, market prices, planned and unplanned plant outages as well as items outside of the normal course of operations. Significant items which impacted the last eight quarters' net earnings are as follows. * In fourth quarter 2004, TCPL completed the acquisition of GTN and recorded $14 million of net earnings from the November 1, 2004 acquisition date. Energy recorded a $16 million pre-tax positive impact of a restructuring transaction related to power purchase contracts between OSP and Boston Edison in Eastern Power Operations. * First quarter 2005 net earnings included a $49 million after-tax gain related to the sale of PipeLines LP units. Energy's earnings included a $10 million after-tax cost for the restructuring of natural gas supply contracts by OSP. In addition, Bruce Power's equity income was lower than previous quarters due to the impact of planned maintenance outages and the increase in operating costs as a result of moving to a six-unit operation. -------------------------------------------------------------------------------- 27 * Second quarter 2005 net earnings included $21 million ($13 million related to 2004 and $8 million related to the six months ended June 30, 2005) with respect to the NEB's decision on Canadian Mainline's 2004 Tolls and Tariff Application (Phase II). On April 1, 2005, TCPL completed the acquisition of TC Hydro generation assets from USGen New England, Inc. Bruce Power's equity income was lower than previous quarters due to the continuing impact of planned maintenance outages and an unplanned maintenance outage on Unit 6 relating to a transformer fire. * Third quarter 2005 net earnings included after-tax gains of $193 million related to the sale of the company's ownership interest in Power LP. In addition, Bruce Power's equity income increased from prior quarters due to higher realized power prices and slightly higher generation volumes. * Fourth quarter 2005 net earnings included a $115 million after-tax gain on sale of Paiton Energy. In addition, Bruce A was formed and Bruce Power's results were proportionately consolidated effective October 31, 2005. * First quarter 2006 net earnings included an $18 million after-tax bankruptcy claim settlement received by the Gas Transmission Northwest System. In addition, Energy's net earnings included contributions from the December 31, 2005 acquisition of the 756 MW Sheerness PPA. * Second quarter 2006 net earnings included a $33 million favourable impact on future income taxes ($23 million in Energy and $10 million in Corporate) arising from reductions in Canadian federal and provincial corporate income tax rates. Pipelines earnings included a $13 million after-tax gain related to the sale of the company's 17.5 per cent general partner interest in Northern Border Partners, L.P. * Third quarter 2006 net earnings included an income tax benefit of approximately $50 million on the resolution of certain income tax matters with taxation authorities and changes in estimates during the quarter. -------------------------------------------------------------------------------- Exhibit 13.2 Consolidated Income (unaudited) Three months ended September Nine months ended September 30 30 (millions of dollars) 2006 2005 2006 2005 Revenues 1,850 1,494 5,429 4,353 Operating Expenses Cost of sales 382 319 1,224 834 Other costs and expenses 593 438 1,696 1,279 Depreciation 264 247 787 752 1,239 1,004 3,707 2,865 Other Expenses/(Income) Financial charges 204 210 614 626 Financial charges of joint ventures 22 16 67 49 Equity income (4) (120) (28) (196) Interest income and other (42) (22) (106) (50) Gain on sale of Northern Border Partners, L.P. 10 - (13) - interest Gains related to the Power LP - (245) - (245) Gain on sale of PipeLines LP units - - - (82) 190 (161 ) 534 102 Income from Continuing Operations before Income 421 651 1,188 1,386 Taxes and Non-Controlling Interests Income Taxes Current 30 189 277 429 Future 75 12 71 38 105 201 348 467 Non-Controlling Interests Non-controlling interest in PipeLines LP 11 15 32 36 Other 6 1 10 7 17 16 42 43 Net Income from Continuing Operations 299 434 798 876 Net Income from Discontinued Operations - - 28 - Net Income 299 434 826 876 Preferred Share Dividends 6 6 17 17 Net Income Applicable to Common Shares 293 428 809 859 Net Income Applicable to Common Shares Continuing operations 293 428 781 859 Discontinued operations - - 28 - 293 428 809 859 See accompanying notes to the consolidated financial statements. -------------------------------------------------------------------------------- 2 Consolidated Cash Flows (unaudited) Three months ended September Nine months ended September 30 30 (millions of dollars) 2006 2005 2006 2005 Cash Generated From Operations Net income 299 434 826 876 Depreciation 264 247 787 752 Gain on sale of Northern Border Partners, L.P. - - (11) - interest, net of current income tax Gains related to Power LP, net of current - (166) - (166) income tax Gain on sale of PipeLines LP units, net of - - - (31) current income tax Equity income in excess of distributions (1) (53) (8) (70) received Future income taxes 75 12 71 38 Non-controlling interests 17 16 42 43 Funding of employee future benefits (in excess (2) 12 (17) (5) of) lower than expense Other 9 2 26 (16) Funds generated from operations 661 504 1,716 1,421 (Increase)/decrease in operating working (43) 90 (136) (173) capital Net cash provided by operations 618 594 1,580 1,248 Investing Activities Capital expenditures (372) (166) (1,002) (409) Acquisitions, net of cash acquired - - (358) (632) Disposition of assets, net of current income - 444 23 546 tax Deferred amounts and other (47) 36 (62) 88 Net cash (used in)/provided by investing (419) 314 (1,399) (407) activities Financing Activities Dividends on common shares (162) (154) (478) (454) Advances from parent 3 - 14 (75) Distributions paid to non-controlling (10) (14) (30) (41) interests Notes payable issued/(repaid), net 4 (696) (449) (163) Long-term debt issued - - 1,250 799 Reduction of long-term debt (4) (9) (352) (962) Long-term debt of joint ventures issued 14 4 38 9 Reduction of long-term debt of joint ventures (27) (7) (48) (23) Common shares issued - - - 80 Net cash used in financing activities (182) (876) (55) (830) Effect of Foreign Exchange Rate Changes on 1 (12) (8) 10 Cash and Short-Term Investments Increase in Cash and Short-Term Investments 18 20 118 21 Cash and Short-Term Investments Beginning of period 312 191 212 190 Cash and Short-Term Investments End of period 330 211 330 211 Supplementary Cash Flow Information Income taxes paid 86 102 454 408 Interest paid 195 221 629 676 See accompanying notes to the consolidated financial statements. -------------------------------------------------------------------------------- 3 Consolidated Balance Sheet September 30, December 31, 2006 2005 (millions of dollars) (unaudited) ASSETS Current Assets Cash and short-term investments 330 212 Accounts receivable 762 796 Inventories 277 281 Other 265 277 1,634 1,566 Long-Term Investments 77 400 Plant, Property and Equipment 20,846 20,038 Other Assets 2,218 2,109 24,775 24,113 LIABILITIES AND SHAREHOLDERS' EQUITY Current Liabilities Notes payable 513 962 Accounts payable 1,330 1,536 Accrued interest 265 222 Current portion of long-term debt 415 393 Current portion of long-term debt of joint ventures 124 41 2,647 3,154 Deferred Amounts 1,109 1,196 Future Income Taxes 773 703 Long-Term Debt 10,306 9,640 Long-Term Debt of Joint Ventures 1,157 937 Preferred Securities 513 536 16,505 16,166 Non-Controlling Interests Non-controlling interest in PipeLines LP 298 318 Other 83 76 381 394 Shareholders' Equity Preferred shares 389 389 Common shares 4,712 4,712 Contributed surplus 276 275 Retained earnings 2,607 2,267 Foreign exchange adjustment (95) (90) 7,889 7,553 24,775 24,113 See accompanying notes to the consolidated financial statements. -------------------------------------------------------------------------------- 4 Consolidated Retained Earnings (unaudited) Nine months ended September 30 (millions of dollars) 2006 2005 Balance at beginning of period 2,267 1,653 Net income 826 876 Preferred share dividends (17) (17) Common share dividends (469) (445) 2,607 2,067 See accompanying notes to the consolidated financial statements. -------------------------------------------------------------------------------- 5 Notes to Consolidated Financial Statements (Unaudited) 1. Significant Accounting Policies The consolidated financial statements of TransCanada PipeLines Limited (TCPL or the company) have been prepared in accordance with Canadian generally accepted accounting principles (GAAP). The accounting policies applied are consistent with those outlined in TCPL's audited consolidated financial statements for the year ended December 31, 2005. These consolidated financial statements reflect all normal recurring adjustments that are, in the opinion of management, necessary to present fairly the financial position and results of operations for the respective periods. These consolidated financial statements do not include all disclosures required in the annual financial statements and should be read in conjunction with the 2005 audited consolidated financial statements included in TCPL's 2005 Report. Amounts are stated in Canadian dollars unless otherwise indicated. Certain comparative figures have been reclassified to conform with the current period's presentation. Since a determination of many assets, liabilities, revenues and expenses is dependent upon future events, the preparation of these consolidated financial statements requires the use of estimates and assumptions. In the opinion of Management, these consolidated financial statements have been properly prepared within reasonable limits of materiality and within the framework of the company's significant accounting policies. 2. Segmented Information Effective June 1, 2006, TCPL revised the composition and names of its reportable business segments to Pipelines and Energy. Pipelines is principally comprised of the company's pipelines in Canada, the United States and Mexico. Energy includes the company's power operations, natural gas storage and liquefied natural gas (LNG) businesses in Canada and the U.S. The financial reporting of these segments was aligned to reflect the internal organizational structure of the company. The segmented information has been retroactively restated to reflect the changes in reportable segments. These changes had no impact on consolidated net income. -------------------------------------------------------------------------------- 6 The impacts on segment net income of each of Pipelines and Energy in each quarter of 2005 and first quarter 2006 are as follows. 2005 2006 (unaudited - millions of dollars) First Second Third Fourth Total First Pipelines Net Income - previously reported as Gas 211 165 148 160 684 168 Transmission Reclassifications: Natural gas storage (4) (1) (2) (9) (16) (13) Costs related to LNG 2 2 3 4 11 2 Net Income - revised 209 166 149 155 679 157 Energy Net Income - previously reported as Power 30 42 292 197 561 89 Reclassifications: Natural gas storage 4 1 2 9 16 13 Costs related to LNG (2) (2) (3) (4) (11) (2) Net Income - revised 32 41 291 202 566 100 Three months ended September 30 (unaudited - Pipelines Energy Corporate Total millions of dollars) 2006 2005 2006 2005 2006 2005 2006 2005 Revenues 1,010 993 840 501 - - 1,850 1,494 Cost of sales - - (382) (319) - - (382) (319) Other costs and expenses (351) (310) (240) (127) (2) (1) (593) (438) Depreciation (231) (235) (33) (12) - - (264) (247) 428 448 185 43 (2) (1) 611 490 Financial charges, preferred dividends and (197) (198) - - (30) (34 ) (227) (232) non-controlling interests Financial charges of joint ventures (17) (16) (5) - - - (22) (16) Equity income 4 21 - 99 - - 4 120 Interest income and other 25 8 2 2 5 12 32 22 Gains related to Power LP - - - 245 - - - 245 Income taxes (113) (114) (59) (98) 67 11 (105) (201) Continuing Operations 130 149 123 291 40 (12) 293 428 Discontinued Operations - - Net Income Applicable to Common Shares 293 428 -------------------------------------------------------------------------------- 7 Nine months ended September 30 Pipelines Energy Corporate Total (unaudited - millions of dollars) 2006 2005 2006 2005 2006 2005 2006 2005 Revenues 2,956 2,981 2,473 1,372 - - 5,429 4,353 Cost of sales - - (1,224) (834) - - (1,224) (834) Other costs and expenses (994) (899) (695) (376) (7) (4) (1,696) (1,279) Depreciation (692) (700) (95) (52) - - (787) (752) 1,270 1,382 459 110 (7) (4) 1,722 1,488 Financial charges, preferred dividends and (573) (588) - (2) (100) (96) (673) (686) non-controlling interests Financial charges of joint ventures (50) (44) (17) (5) - - (67) (49) Equity income 28 54 - 142 - - 28 196 Interest income and other 59 21 5 5 32 24 96 50 Gain on sale of Northern Border Partners, 23 - - - - - 23 - L.P. interest Gain on sale of PipeLines LP units - 82 - - - - - 82 Gains related to Power LP - - - 245 - - - 245 Income taxes (323) (383) (127) (131) 102 47 (348) (467) Continuing Operations 434 524 320 364 27 (29 ) 781 859 Discontinued Operations 28 - Net Income Applicable to Common Shares 809 859 Total Assets September 30, December 31, 2006 2005 (millions of dollars) (unaudited) Pipelines 17,966 17,872 Energy 5,715 5,303 Corporate 1,094 938 24,775 24,113 3. Risk Management and Financial Instruments The following represents the material changes to the company's financial instruments since December 31, 2005. Energy Price Risk Management The company executes power, natural gas and heat rate derivatives for overall management of its asset portfolio. Heat rate contracts are contracts for the sale or purchase of power that are priced based on a natural gas index. The fair value and notional volumes of contracts for differences and the swap, option and heat rate contracts are shown in the tables below. -------------------------------------------------------------------------------- 8 Power September 30, 2006 Asset/(Liability) (millions of dollars) (unaudited) December 31, 2005 Accounting Fair Fair Treatment Value Value Power - swaps and contracts for differences (maturing 2006 to 2011) Hedge (89) (130) (maturing 2006 to 2010) Non-hedge (6) 13 Gas - swaps and futures (maturing 2006 to 2016) Hedge (58) 17 (maturing 2006 to 2008) Non-hedge 26 (11) Notional Volumes September 30, 2006 (unaudited) Power (GWh) Gas (Bcf) Accounting Purchases Sales Purchases Sales Treatment Power - swaps and contracts for differences (maturing 2006 to 2011) Hedge 4,946 11,189 - - (maturing 2006 to 2010) Non-hedge 1,465 917 - - Gas - swaps and futures (maturing 2006 to 2016) Hedge - - 81 60 (maturing 2006 to 2008) Non-hedge - - 15 20 Heat rate contracts (maturing 2006) Non-hedge - 12 - - Notional Volumes December 31, 2005 Power (GWh) Gas (Bcf) Accounting Purchases Sales Purchases Sales Treatment Power - swaps and contracts for differences Hedge 2,566 7,780 - - Non-hedge 1,332 456 - - Gas - swaps and futures Hedge - - 91 69 Non-hedge - - 15 18 Certain of the company's joint ventures use power derivatives to manage energy price risk exposures. The company's proportionate share of the fair value of these outstanding power sales derivatives at September 30, 2006 was $55 million (December 31, 2005 - $(38) million) and relates to contracts which cover the period 2006 to 2010. The company's proportionate share of the notional sales volumes associated with this exposure at September 30, 2006 was 4,500 GWh (December 31, 2005 - 2,058 GWh). -------------------------------------------------------------------------------- 9 4. Long-Term Debt In January 2006, the company issued $300 million of 4.3 per cent medium-term notes due 2011; in March 2006, the company issued US$500 million of 5.85 per cent senior unsecured notes due 2036; and in October 2006, the company issued $400 million of 4.65 per cent medium-term notes due October 2016. In April 2006, TC PipeLines, LP (PipeLines LP) borrowed US$307 million under its unsecured credit facility to finance the cash portion of the purchase price of its acquisition of an additional 20 per cent interest in Northern Border Pipeline Company (Northern Border). The credit facility has a term of two years and all amounts outstanding will be due and payable on March 31, 2008. Borrowings under the credit facility will bear interest based, at PipeLines LP's election, on the London interbank offered rate or the base rate plus, in either case, an applicable margin. 5. Discontinued Operations TCPL's net income for the nine months ended September 30, 2006 includes $28 million of net income from discontinued operations, reflecting settlements received in first quarter 2006 from bankruptcy claims related to TCPL's Gas Marketing business divested in 2001. 6. Acquisitions and Dispositions In April 2006, PipeLines LP closed its acquisition of an additional 20 per cent general partnership interest in Northern Border for US$307 million bringing its total general partnership interest to 50 per cent. As part of the transaction, PipeLines LP indirectly assumed approximately US$120 million of debt of Northern Border. Of the total purchase price, US$114 million was allocated to goodwill and the remainder was allocated primarily to plant, property and equipment. Northern Border became a jointly controlled entity and TCPL commenced proportionately consolidating its investment in Northern Border on a prospective basis as of April 2006. As part of the transaction, and effective early second quarter 2007, a subsidiary of TCPL will become the operator of Northern Border which is currently operated by a subsidiary of ONEOK Inc. (ONEOK). Concurrent with this transaction, TCPL closed the sale of its 17.5 per cent general partner interest in Northern Border Partners, L.P. to a subsidiary of ONEOK, for net proceeds of approximately US$30 million, resulting in an after-tax gain of $13 million. The net gain was recorded in the Pipelines segment and the company recorded a $10 million income tax charge, including $12 million of current income tax expense, on this transaction. 7. Income Taxes In second quarter 2006, TCPL recorded a $37 million future income tax benefit ($23 million in Energy and $14 million in Corporate) as a result of reductions in Canadian federal and provincial corporate income tax -------------------------------------------------------------------------------- 10 rates enacted in second quarter 2006. In third quarter 2006, TCPL recorded a net income tax benefit of approximately $75 million on the resolution of certain income tax matters with taxation authorities and changes in estimates during the quarter. 8. Employee Future Benefits The net benefit plan expense for the company's defined benefit pension plans and other post-employment benefit plans for the three months and nine months ended September 30, respectively, is as follows. Three months ended September 30 Pension Benefit Other Benefit Plans Plans (unaudited - millions of dollars) 2006 2005 2006 2005 Current service cost 10 7 1 - Interest cost 16 16 2 1 Expected return on plan assets (18) (16) (1) - Amortization of transitional obligation related to regulated business - - 1 1 Amortization of net actuarial loss 6 5 1 - Amortization of past service costs 1 1 - - Net benefit cost recognized 15 13 4 2 Nine months ended September 30 Pension Benefit Other Benefit Plans Plans (unaudited - millions of dollars) 2006 2005 2006 2005 Current service cost 28 22 2 1 Interest cost 49 48 6 4 Expected return on plan assets (53) (48) (2) - Amortization of transitional obligation related to regulated business - - 2 2 Amortization of net actuarial loss 20 13 2 1 Amortization of past service costs 3 2 1 - Net benefit cost recognized 47 37 11 8 TCPL welcomes questions from shareholders and potential investors. Please telephone: Investor Relations, at 1-800-361-6522 (Canada and U.S. Mainland) or direct dial David Moneta/Myles Dougan at (403) 920-7911. The investor fax line is (403) 920-2457. Media Relations: Jennifer Varey at (403) 920-7859 Visit TCPL's Internet site at: http://www.transcanada.com -------------------------------------------------------------------------------- Exhibit 13.3 TRANSCANADA PIPELINES LIMITED RECONCILIATION TO UNITED STATES GAAP The unaudited consolidated financial statements of TransCanada PipeLines Limited (TCPL or the Company) for the three and nine months ended September 30, 2006 have been prepared in accordance with Canadian generally accepted accounting principles (GAAP), which in some respects differ from U.S. GAAP. The effects of these differences on the Company's consolidated financial statements for the three and nine months ended September 30, 2006 are provided in the following U.S. GAAP condensed consolidated financial statements which should be read in conjunction with TCPL's audited consolidated financial statements for the year ended December 31, 2005 and unaudited consolidated financial statements for the three and nine months ended September 30, 2006 prepared in accordance with Canadian GAAP. Condensed Statement of Consolidated Income and Comprehensive Income in Accordance with U.S. GAAP(1) Three months ended Nine months ended September 30 September 30 (millions of dollars) 2006 2005 2006 2005 Revenues 1,492 1,306 4,307 3,870 Cost of sales 321 228 953 637 Other costs and expenses 477 442 1,349 1,270 Depreciation 223 235 668 693 1,021 905 2,970 2,600 471 401 1,337 1,270 Other (income)/expenses Equity income(1) (134) (173) (352) (340) Other expenses(2) 191 (33) 542 300 Income taxes 109 191 348 455 166 (15) 538 415 Net income from continuing operations - U.S. GAAP 305 416 799 855 Net income from discontinued operations - U.S. GAAP - - 28 - Net Income in Accordance with U.S. GAAP 305 416 827 855 Adjustments affecting comprehensive income under U.S. GAAP Foreign currency translation adjustment, net of tax - (37) (6) (27) Unrealized (loss)/gain on derivatives, net of tax(3) (2) (59) 32 (98) Comprehensive Income in Accordance with U.S. GAAP 303 320 853 730 Reconciliation of Income from Continuing Operations Three months ended Nine months ended September 30 September 30 (millions of dollars) 2006 2005 2006 2005 Net Income from Continuing Operations in Accordance with Canadian GAAP 298 434 797 876 U.S. GAAP adjustments Unrealized gain/(loss) on energy contracts(3) 11 (28) - (37) Tax impact of unrealized gain/(loss) on energy contracts (4) 10 - 13 Equity investment gain(4)(5) - - 1 3 Tax impact of equity investment gain - - - (1) Unrealized gain on foreign exchange and interest rate derivatives(3) - - 1 1 Tax impact of unrealized gain on foreign exchange and interest rate - - - - derivatives Net income from Continuing Operations in Accordance with U.S. GAAP 305 416 799 855 -------------------------------------------------------------------------------- 2 Condensed Statement of Consolidated Cash Flows in Accordance with U.S. GAAP(1) Three months ended Nine months ended September 30 September 30 (millions of dollars) 2006 2005 2006 2005 Cash Generated from Operations(6) Net cash provided by operating activities 554 503 1,517 1,039 Investing Activities Net cash (used in) provided by investing activities (388) 402 (1,333) (226) Financing Activities Net cash (used in) financing activities (160) (874) (45) (815) Effect of Foreign Exchange Rate Changes on Cash and Short-Term 1 (10) (6) 12 Investments Increase in Cash and Short-Term Investments 7 21 133 10 Cash and Short-Term Investments Beginning of period 209 115 83 126 Cash and Short-Term Investments End of period 216 136 216 136 Condensed Consolidated Balance Sheet in Accordance with U.S. GAAP(1) September December 30, 31, (millions of dollars) 2006 2005 Current assets(7) 1,148 1,058 Long-term investments(1)(4)(5) 2,793 2,168 Plant, property and equipment 17,163 17,348 Regulatory asset(8) 2,101 2,601 Other assets(4) 1,958 2,028 25,163 25,203 Current liabilities(9) 2,277 2,797 Deferred amounts(3)(5) 1,204 1,298 Long-term debt(3) 10,331 9,675 Deferred income taxes(8) 2,685 3,102 Preferred securities 513 536 Non-controlling interests 381 394 Shareholders' equity 7,772 7,401 25,163 25,203 Statement of Other Comprehensive Income in Accordance with U.S. GAAP (millions of dollars) Cumulative Minimum Cash Flow Total Translation Pension Hedges Account Liability (SFAS No. (SFAS No. 133) 87) Balance at December 31, 2005 (89) (77) (58) (224) Unrealized gain on derivatives, net of tax of $12(3) - - 32 32 Foreign currency translation adjustment, net of tax of (6) - - (6) $35 Balance at September 30, 2006 (95) (77) (26) (198) Balance at December 31, 2004 (71) (26) (4) (101) Unrealized loss on derivatives, net of tax of $52(3) - - (98) (98) Foreign currency translation adjustment, net of tax of (27) - - (27) $19 Balance at September 30, 2005 (98) (26) (102) (226) -------------------------------------------------------------------------------- 3 -------------------- (1) In accordance with U.S. GAAP, the Condensed Statement of Consolidated Income, Statement of Consolidated Cash Flows and Consolidated Balance Sheet of TCPL are prepared using the equity method of accounting for joint ventures. (2) Other expenses included an allowance for funds used during construction of $6 million for the nine months ended September 30, 2006 (September 30, 2005 - $2 million). (3) All foreign exchange and interest rate derivatives are recorded in the Company's consolidated financial statements at fair value under Canadian GAAP. Under the provisions of Statement of Financial Accounting Standards (SFAS) No. 133 "Accounting for Derivatives and Hedging Activities", all derivatives are recognized as assets and liabilities on the balance sheet and measured at fair value. For derivatives designated as fair value hedges, changes in the fair value are recognized in earnings together with an equal or lesser amount of changes in the fair value of the hedged item attributable to the hedged risk. For derivatives designated as cash flow hedges, changes in the fair value of the derivative that are effective in offsetting the hedged risk are recognized in other comprehensive income until the hedged item is recognized in earnings. Any ineffective portion of the change in fair value is also recognized in earnings each period. Substantially all of the amounts recorded in the nine months ended September 30, 2006 and 2005 as differences between U.S. and Canadian GAAP, for income from continuing operations, relate to the differences in accounting treatment with respect to the hedged item and, for comprehensive income, relate to cash flow hedges. Substantially all of the amounts recorded in the nine months ended September 30, 2006 and 2005 as differences between U.S. and Canadian GAAP in respect of energy contracts relate to gains and losses on derivative energy contracts for periods before they were documented as hedges for purposes of U.S. GAAP and to differences in accounting with respect to physical energy contracts. (4) Under Canadian GAAP, pre-operating costs incurred during the commissioning phase of a new project are deferred until commercial production levels are achieved. After such time, those costs are amortized over the estimated life of the project. Under U.S. GAAP, such costs are expensed as incurred. Certain prior year start-up costs incurred by Bruce Power L.P. (Bruce B), an equity investment, were required to be expensed under U.S. GAAP. Under both Canadian GAAP and U.S. GAAP, interest is capitalized on expenditures relating to construction of development projects actively being prepared for their intended use. In Bruce B, under U.S. GAAP, the carrying value of development projects against which interest is capitalized is lower due to the expensing of pre-operating costs. (5) Financial Interpretation (FIN) 45 requires the recognition of a liability for the fair value of certain guarantees that require payments contingent on specified types of future events. The measurement standards of FIN 45 are applicable to guarantees entered into after January 1, 2003. For U.S. GAAP purposes, the fair value of guarantees recorded as a liability at September 30, 2006 was $17 million (December 31, 2005 - $17 million) and relates to the Company's equity interest in Bruce B and Bruce Power A L.P. The net income impact with respect to the guarantees for the nine months ended September 30, 2006 was $1 million (September 30, 2005 - nil). (6) In accordance with U.S. GAAP, all current taxes are included in cash generated from operations. (7) Current assets at September 30, 2006 include derivative contracts of $30 million (December 31, 2005 - $49 million) and hedging deferrals of $72 million (December 31, 2005 - $93 million). (8) Under U.S. GAAP, the Company is required to record a deferred income tax liability for its cost-of-service regulated businesses. As these deferred income taxes are recoverable through future revenues, a corresponding regulatory asset is recorded for U.S. GAAP purposes. A reduction in Canadian federal and provincial corporate income tax rates enacted in the second quarter 2006 resulted -------------------------------------------------------------------------------- 4 in a decrease of $406 million in the deferred income tax liability and corresponding regulatory asset. (9) Current liabilities at September 30, 2006 include dividends payable of $162 million (December 31, 2005 - $154 million) and current taxes payable of $103 million (December 31, 2005 - $251 million). Other In May 2005, the Financial Accounting Standards Board (FASB) issued SFAS No. 154 "Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and SFAS No. 3" which is effective for fiscal years beginning after December 15, 2005. SFAS No. 154 changes the requirements for the accounting for and reporting of a change in accounting principle and error correction. It establishes, unless impracticable, retrospective application as the required method for reporting a change in accounting principle in the absence of explicit transition requirements specific to the newly adopted accounting principle. Adopting the provisions under SFAS No. 154, as of January 1, 2006, had no impact on the U.S. GAAP financial statements of the Company. In February 2006, FASB issued SFAS No. 155 "Accounting for Certain Hybrid Financial Instruments - an amendment of SFAS No. 133 and 140" which is effective for fiscal years beginning after September 15, 2006. Earlier adoption is permitted as of the beginning of an entity's fiscal year, provided the entity has not yet issued financial statements, including interim statements for any interim period, for that fiscal year. SFAS No. 155 permits fair value remeasurement of any hybrid instrument that contains an embedded derivative that otherwise would require bifurcation. Adopting the provisions under SFAS No. 155, as of January 1, 2007, is not expected to have an impact on the U.S. GAAP financial statements of the Company. In March 2006, FASB issued SFAS No. 156 "Accounting for Servicing of Financial Assets - an amendment of FASB Statement No. 140" which is effective for fiscal years beginning after September 15, 2006. Earlier adoption is permitted as of the beginning of an entity's fiscal year, provided the entity has not yet issued financial statements, including interim statements for any interim period, for that fiscal year. SFAS No. 156 requires recognition of a servicing asset or liability when an entity enters into arrangements to service financial instruments in certain situations. Such servicing assets or servicing liabilities are required to be initially measured at fair value, if practicable. SFAS No. 156 also allows an entity to subsequently measure its servicing assets or servicing liabilities using either an amortization method or a fair value method. Adopting the provisions under SFAS No. 156, as of January 1, 2007, is not expected to have an impact on the U.S. GAAP financial statements of the Company. In July 2006, FASB issued FIN 48 "Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109" which is effective for fiscal years beginning after December 15, 2006. This Interpretation provides guidance for the financial statement recognition, measurement, presentation and disclosure of uncertain tax positions taken or expected to be taken in income tax returns. TransCanada is in the process of assessing the impact, if any, of the application of FIN 48 on its US GAAP financial statements. In September 2006, FASB issued SFAS No. 157 "Fair Value Measurements" which is effective for fiscal years beginning after November 15, 2007. This statement defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. TransCanada is in the process of assessing the impact of the application of SFAS No. 157 on its U.S. GAAP financial statements. In September 2006, FASB issued SFAS No. 158 "Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans - an amendment of FASB Statements No. 87, 88, 106 and 132(R)", which is effective for fiscal years ending after December 15, 2006. This statement requires an employer to recognize the overfunded or underfunded status of a defined benefit postretirement plan (other than a multiemployer plan) as an asset or liability on its balance sheet and to recognize changes in the funded status in the year in which the changes occur through comprehensive income. The plan assets and benefit obligations will be measured as of the balance sheet date. TransCanada is in the process of assessing the impact of the application of SFAS No. 158 on its U.S. GAAP financial statements. -------------------------------------------------------------------------------- 5 In September 2006, the SEC staff issued SAB Topic 1N, "Financial Statements - Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements" (SAB No. 108), which addresses how to quantify the effect of an error on the financial statements. SAB No. 108 is effective for fiscal years ending December 31, 2006. TransCanada does not expect SAB No. 108 to have an impact on its U.S. GAAP financial statements. Summarized Financial Information of Long-Term Investments The following summarized financial information of long-term investments includes those investments that are accounted for by the equity method under U.S. GAAP (including those that are accounted for by the proportionate consolidation method under Canadian GAAP). Three months ended Nine months ended September 30 September 30 (millions of dollars) 2006 2005 2006 2005 Income Revenues 364 379 1,068 993 Other costs and expenses (162) (146) (512) (455) Depreciation (43) (44) (130) (128) Financial charges and other (25) (19) (74) (73) Proportionate share of income before income taxes of long-term 134 170 352 337 investments (millions of dollars) September 30, December 31, 2006 2005 Balance Sheet Current assets 446 456 Plant, property and equipment 3,812 3,365 Other assets (net) 202 - Current liabilities (347) (319) Deferred amounts (net) - (2) Non-recourse debt (1,293) (1,307) Deferred income taxes (27) (25) Proportionate share of net assets of long-term investments 2,793 2,168 -------------------------------------------------------------------------------- Exhibit 31.1 Certifications I, Harold N. Kvisle, certify that: 1. I have reviewed this quarterly report on Form 6-K of TransCanada PipeLines Limited; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15 (e)) for the registrant and have: (a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (c) disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Dated November 1, 2006 /s/ Harold N. Kvisle Harold N. Kvisle President and Chief Executive Officer -------------------------------------------------------------------------------- Exhibit 31.2 Certifications I, Gregory A. Lohnes, certify that: 1. I have reviewed this quarterly report on Form 6-K of TransCanada PipeLines Limited; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15 (e)) for the registrant and have: (a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (c) disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Dated November 1, 2006 / s / Gregory A. Lohnes Gregory A. Lohnes Executive Vice-President and Chief Financial Officer -------------------------------------------------------------------------------- Exhibit 32.1 TRANSCANADA PIPELINES LIMITED 450 - 1st Street S.W. Calgary, Alberta, Canada T2P 5H1 CERTIFICATION OF CHIEF EXECUTIVE OFFICER REGARDING PERIODIC REPORT CONTAINING FINANCIAL STATEMENTS I, Harold N. Kvisle, the Chief Executive Officer of TransCanada PipeLines Limited (the "Company"), in compliance with 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, hereby certify, in connection with the Company's Quarterly Report as filed on Form 6-K for the period ended September 30, 2006 with the Securities and Exchange Commission (the "Report"), that: 1. the Report fully complies with the requirements of Section 13 (a) or 15(d) of the Securities Exchange Act of 1934; and 2. the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. /s/ Harold N. Kvisle Harold N. Kvisle Chief Executive Officer November 1, 2006 -------------------------------------------------------------------------------- Exhibit 32.2 TRANSCANADA PIPELINES LIMITED 450 - 1st Street S.W. Calgary, Alberta, Canada T2P 5H1 CERTIFICATION OF CHIEF FINANCIAL OFFICER REGARDING PERIODIC REPORT CONTAINING FINANCIAL STATEMENTS I, Gregory A. Lohnes, the Chief Financial Officer of TransCanada PipeLines Limited (the "Company"), in compliance with 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, hereby certify, in connection with the Company's Quarterly Report as filed on Form 6-K for the period ended September 30, 2006 with the Securities and Exchange Commission (the "Report"), that: 1. the Report fully complies with the requirements of Section 13 (a) or 15(d) of the Securities Exchange Act of 1934; and 2. the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. / s / Gregory A. Lohnes Gregory A. Lohnes Chief Financial Officer November 1, 2006 -------------------------------------------------------------------------------- Exhibit 99.1 TransCanada PipeLines Limited EARNINGS COVERAGE SEPTEMBER 30, 2006 The following financial ratios have been calculated on a consolidated basis for the respective 12 month period ended September 30, 2006 and are based on unaudited financial information. The financial ratios have been calculated based on financial information prepared in accordance with Canadian generally accepted accounting principles. The following ratios have been prepared based on net income: September 30, 2006 Earnings coverage on long-term debt 2.91 times Earnings coverage on long-term debt and First 2.81 times Preferred Shares -------------------------------------------------------------------------------- This information is provided by RNS The company news service from the London Stock Exchange END QRTFGMGMMMDGVZZ
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