RH-1-2008 Response to CAPP Item 1 March 28, 2008 Page 1 of 6

CAPP 1

Reference: TQM Application.

Preamble: The application does not include summary cost of service tables nor detailed return, rate base or other cost of service information. Request:

(a) Please provide summary tables for each year 2006, 2007, and 2008 showing the line-by-line breakdown of the cost of service. Please also provide summary tables with the cost of service for 2007 and 2008 at the current formula ROE and 30% equity.

(b) Please provide tables for each year 2006, 2007 and 2008 showing the detail of the return calculations, both debt and equity. Please also provide for each of 2007 and 2008 the return at the current formula ROE and 30% equity.

(c) Please provide tables for each year 2006, 2007 and 2008 showing the detail of the rate base calculations including gas plant in service, depreciation, and rate base.

(d) Please provide for each year 1995 to 2007 the average rate base. Please provide the equivalent data for the TCPL Mainline.

(e) Please project the TQM rate base to 2020 at the current depreciation rate both with and without expansions to accommodate the proposed LNG terminals at Gros Cacouna and Rabasca.

(f) What is the current composite depreciation rate and what are the pipe and compression depreciation rates for TQM? What were the composite, pipe, and compression rates in 1994? If they have changed since 1994, what were the changes? For the depreciation rates in use from 1994 to the present time, what were or are the economic lives or life assumed for depreciation purposes and, if they have changed, please explain.

Page 2 of 6

CAPP 1

Response:

(a) Please refer to the table below:

11% ROE on Formula ROE on TQM Pipeline 40% Equity 30% Equity Actual Test Test Test Test Cost of Service Year Year Year Year Year ($000) 2006 2007 2008 2007 (*) 2008

Operating expenses 13,649 13,950 16,753 13,950 16,753 NEB cost recovery 604 651 670 651 670 Depreciation & 22,791 23,920 24,050 23,920 24,050 amortization Municipal & other 4,194 4,100 3,891 4,100 3,891 taxes Income taxes 6,958 11,768 11,568 7,413 7,720 Flow-through 1,030 664 2,315 664 2,315 deferred costs Return on rate base 31,457 38,137 36,644 32,041 31,027 Storage revenue (281) (290) (274) (290) (274) Transmission cost 80,402 92,900 95,617 82,449 86,152 of service

ROE 8.88% 11.00% 11.00% 8.46% 8.71% Equity % 30% 40% 40% 30% 30% Note (*): Forecast as reflected in TQM’s Partial Settlement Application, Appendix 1, Page 8 of 19.

Page 3 of 6

CAPP 1

(b) Please refer to the table below:

11% ROE on Formula ROE on TQM Pipeline 40% Equity 30% Equity Actual Test Test Test Test Rate of Return Year Year Year Year Year Calculation 2006 2007 2008 2007 (*) 2008

Average Rate Base 459,893 472,580 452,962 472,580 452,962 ($000)

Capital Structure (%) Debt - Funded 59.80% 58.19% 60.71% 58.19% 60.71% Debt – Unfunded 10.20% 1.81% (0.71)% 11.81% 9.29% (Prefunded) Total Debt 70.00% 60.00% 60.00% 70.00% 70.00%

Equity 30.00%40.00% 40.00% 30.00% 30.00%

Capital Cost (%) Debt - Funded 6.14% 6.14% 6.14% 6.14% 6.14% Debt – Unfunded 4.50% 5.69% 6.14% 5.69% 5.50% (Prefunded) Equity 8.88% 11.00% 11.00% 8.46% 8.71%

Return (%) Debt - Funded 3.67% 3.57% 3.73% 3.57% 3.73% Debt – Unfunded 0.46% 0.10% (0.04)% 0.67% 0.51% (Prefunded) Total Debt 4.13% 3.67% 3.69% 4.24% 4.24%

Equity 2.66% 4.40% 4.40% 2.54% 2.61% Total Rate of Return 6.79% 8.07% 8.09% 6.78% 6.85% Note (*): Forecast as reflected in TQM’s Partial Settlement Application, Appendix 1, Page 8 of 19.

Page 4 of 6

CAPP 1

(c) Please refer to the table below:

TQM Pipeline Actual Test Test Average Rate Base ($000) Year Year Year 2006 2007 (*) 2008

Utility Investment Gas Plant in Service 833,457 868,270 872,073 Accumulated Depreciation (374,677) (398,019) (422,005) Net Plant 458,780 470,251 450,068

Working Capital Cash 1,1371,303 1,487 Materials & Supplies 1,587 1,443 1,442 Transmission Linepack 1,163 1,163 1,163 Prepayments & Deposits 1,216 1,041 1,056 Pension Asset - 1,324 1,670 Total Working Capital 5,103 6,275 6,818

Other Rate Base Items Tax Benefits on Sponsors Dev. Costs (5,553) (5,118) (4,683) Unamortized Debt Discount 1,563 1,172 759 Total Other Items (3,990) (3,946) (3,924)

Average Rate Base 459,893 472,580 452,962 Note (*): Forecast as reflected in TQM’s Partial Settlement Application, Appendix 1, Page 8 of 19.

Page 5 of 6

CAPP 1

(d) Please refer to the table below:

Average Rate Base ($ Millions) Year TQM Mainline 1995 299 6,671 1996 307 6,918 1997 308 7,434 1998 299 8,193 1999 473 9,072 2000 544 9,405 2001 525 9,156 2002 504 8,873 2003 484 8,556 2004 463 8,186 2005 471 7,796 2006 460 7,417 2007 472 7,263

(e) Please refer to the table below:

TQM Pipeline Cacouna Rabaska Average Rate Base No Expansion Expansion

($000) Expansion In-Service In-Service 2013 2015 Year

2008 452,962 452,962 452,962 2009 435,840 435,840 435,840 2010 413,688 413,688 413,688 2011 391,661 391,661 391,661 2012 369,585 369,585 369,585 2013 347,452 723,782 347,452 2014 325,252 1,067,041 325,252 2015 302,986 1,023,983 424,209 2016 280,653 980,858 519,371 2017 258,254 937,668 490,295 2018 235,788 894,411 461,152 2019 213,255 851,087 431,943 2020 190,656 807,698 402,668

Page 6 of 6

CAPP 1

(f) The 2007 composite depreciation rate is 2.76%. The pipe rate is 2.75% and the compression equipment rate is 3.02%.

In 1994 the composite depreciation rate was 2.82%. The pipe rate was 2.75% and there was no compression on the system at that time. In 1998 the compressor equipment rate of 3.02% was approved by the NEB.

The last depreciation study was filed in 1988 at which time the estimated remaining life was 31.50 years. There has been no subsequent depreciation study.

RH-1-2008 Response to CAPP Item 2 March 28, 2008 Page 1 of 3

CAPP 2

Reference: TQM Application

Preamble: TQM has only a few employees. Appendix 2 and other elements of the application are very similar to TCPL’s cost of capital applications. Appendix 3 is evidence directly by TCPL. It also appears that Gaz Métro and TCPL are sources of information in other of the appendicies. CAPP wishes to understand where TCPL and Gaz Métro witnesses are being provided and where TCPL and Gaz Métro are providing information through TQM or TQM’s expert witnesses.

Request:

(a) Please confirm that a TCPL witness will speak to Appendix 3. Please also identify the witness or witnesses who will speak to Appendix 3.

(b) Will a TCPL witness or witnesses speak to any aspect of the application other than Appendix 3? If so, will this be a different witness(es) from that who will speak to Appendix 3? Please identify any such witnesses and, for each witness, the area or evidence that they will address.

(c) Will witnesses from Gaz Métro speak to any aspect of the application? Please identify any such witnesses and, for each witness, the area or evidence that they will address.

(d) Will a witness or witnesses from TQM appear as a witness? Please identify any such witness(es) and, for each witness, the area or evidence that they will address.

(e) Please confirm that TCPL and Gaz Métro have provided information to the expert witnesses whose evidence is found beginning at Appendix 4. If not confirmed, please explain who was the informant on the many points of detail contained in the experts’ evidence that have the appearance on their face of coming from either TCPL or Gaz Métro.

(f) In RH-2-94 TQM adopted evidence on the specifics of its business risks presented by Dr. Morin (as distinct from simply accepting Dr. Morin’s cost of capital recommendation). In other words, Dr. Morin in effect spoke for the company on the details of its business risk. In that regard see RH-2-94 TQM response to Filing Requirements #12, #13, #15 and Dr. Morin’s evidence at p.3 and p.12ff. Dr.

Page 2 of 3

CAPP 2

Morin is not a witness in this case. Who of the witnesses to be presented by TQM in the present case will be prepared to discuss the company’s views on its business risks as they were said to be in 1994?

Response:

(a) Appendix 3 is identified as evidence of TCPL for TQM (Written Evidence of TransCanada PipeLines Limited for TransQuébec & Maritimes Pipelines Inc: TQM Throughput Study). Witnesses presented by TQM will therefore include a TCPL employee or employees who will speak to the TQM Throughput Study. While the TQM witness list has not yet been finalized, the present expectation is that the witnesses who will speak to the TQM Throughput Study will include Gregory J. W. Zwick and Al Jamal of TCPL, each of whom has previously testified in respect of throughput studies prepared by TCPL. TQM expects to file the list of witness responsibilities and panel structure after the second round of information request responses have been filed.

(b) In 2002, TQM had 65 employees. As part of a cost saving and efficiency arrangement (TQM Pipeline Multi-Year Agreement - Years 2003 to 2006 O&M Cost Saving Initiative, filed with the NEB on November 26, 2002), TQM determined that it would contract for operating, maintenance, administrative and related services as well as management supervision from TCPL, and reduced its employee count to four. Operating services provided by TCPL to TQM include the preparation and filing of all regulatory applications for the operation, maintenance and tolls or rates of the TQM Pipeline. TCPL has therefore prepared all TCPL toll applications since 2003.

The present Application has been prepared by TCPL with input from TQM and Gaz Métro. Consequently, employees of TCPL will appear as witnesses for TQM to speak to all aspects of the Application. The witness list has yet to be finalized. In accordance with past practice in TransCanada Mainline cost of capital cases, TQM will file curricula vitae witness evidence and a listing of witness panels and responsibilities after all information requests to TQM have been answered and witness responsibilities can be identified.

(c) Yes. The identities and areas of responsibility of the Gaz Métro witnesses will be provided once all information requests to TQM have been answered.

(d) Yes. Bernard Otis, Acting General Manager of TQM, bears overall responsibility for the TQM Application and will appear as a witness. His qualifications will be provided in the witness information filing.

(e) Confirmed.

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CAPP 2

(f) The 1994 TQM evidence and position on business risk have been analyzed in detail by TQM, TCPL, Gaz Métro and Dr. Carpenter in the course of the preparation of the TQM Application, so various witnesses will be in a position to respond to the relative risks of 1994 and 2008. There are no employees of TQM in management positions who were with TQM in 1994.

RH-1-2008 Response to CAPP Item 3 March 28, 2008 Page 1 of 1

CAPP 3

Reference: Appendix 1, TQM Evidence, p. 1 A1.

Preamble: TQM’s request is said to be equivalent to a 6.7% ATWACC adjusted for actual cost of debt.

Request:

(a) Please show the calculation by which the 6.7% is derived from the unadjusted ATWACC.

(b) If not shown in (a), what are the market cost of debt in the adjusted ATWACC and the actual cost of TQM debt?

Response:

(a) The calculation is:

Cost Element Cost Weight Product Equity 11.0% 0.4 4.4% P-T Debt (Market) 5.55% Tax Rate 31.9% A-T Debt 3.8% 0.6 2.3% ATWACC 6.7%

(b) The ATWACC is based on the market cost of debt, shown in part (a). As shown in the response to CAPP 1(b), TQM’s embedded cost of debt would be 6.14 percent in 2008 with 40% equity. The overall return at that rate is:

Cost Element Cost Weight Product Equity 11.0% 40.0% 4.4% P-T Debt (Actual) 6.14% Tax Rate 31.9% A-T Debt 4.2% 60.0% 2.5% Overall Return 6.9%

RH-1-2008 Response to CAPP Item 4 March 28, 2008 Page 1 of 2

CAPP 4

Reference: Appendix 1, TQM Evidence, p. 7 A5.

Preamble: TQM refers in the alternative to capital structures of 60% and 57.5% equity for 2007 and 2008 if the ROE formula is not changed.

Request:

(a) Does TQM have any regulatory precedent for the alternative approach proposed? In RH-2-2004 TCPL made a similar proposal as an alternative and in oral examination was unable to offer any regulatory precedent (1T695-708). Please provide any precedents.

(b) Does TQM’s alternative require the NEB to set a new capital structure each year after 2008? Would this involve frequent, for example, annual, cost of capital hearings?

(c) Is it TQM’s position that the NEB should stop using an ROE formula and should instead revert to frequent, for example, annual, cost of capital hearings? Explain.

Response:

(a) There is regulatory precedent that accepts the legal principle that it is the total return on capital that must be fair. The total return concept was endorsed by the NEB in the RH-1-70 Decision (pages 6-5 through 6-9 and 7-5 through 7-9) and in the RH-2-2004 Phase II Decision (Chapter 2 and 9). As noted by in the RH-2- 2004 Phase II Decision (pages 19-20), the NEB is not constrained in the methodology to be utilized to determine a fair return. As discussed by TCPL witnesses in the RH-2-2004 Phase II proceeding (1T695-721), the two variables in the determination of a fair return on equity are the rate of return on equity and the equity component of the capital structure. In a regulatory model where the equity component of the capital structure is deemed by the regulator at a level that reflects the business risk of the utility, it would be expected that the rate of return would become the variable to reach a fair total return on equity. The regulator, however, is not constrained to a model where deemed equity reflects business risk and could choose to vary the equity level to reach a fair overall return on equity. TQM is not aware of any Canadian regulator having chosen to do so.

Page 2 of 2

CAPP 4

(b) No. TQM is not making any proposal for the determination of its fair return beyond 2009.

(c) No. It is TQM’s primary position that the NEB should not utilize the RH-2-94 Formula to determine the fair return on capital for TQM for 2008 and 2009. It is TQM’s alternative position that if the NEB retains the RH-2-94 Formula for the rate of return on equity, then a fair total return on equity for TQM can only be achieved through increases in the deemed equity component of the capital structure. TQM is not opposed to the use of a formula rate of return on equity provided that such rate, combined with the deemed equity component of the capital structure, results in a total return on equity that meets the fair return standard. It is not TQM’s position that the NEB should hold annual cost of capital hearings.

RH-1-2008 Response to CAPP Item 5 March 28, 2008 Page 1 of 2

CAPP 5

Reference: Appendix 1, TQM Evidence, p.8 A8.

Preamble: TQM refers to three outstanding debt instruments with a weighted average cost of 6.14% totaling $275 million and to short-term arrangements.

Request:

(a) Please provide the details of each of the three outstanding debt instruments including cost, date issued, term, redemption features, and other key terms.

(b) Please provide the details of the short-term loan arrangement including total loan capacity available, date put in place, and other key terms.

(c) Please provide the details of all other credit facilities available to TQM including the total credit capacity, cost, date put in place, and other key terms.

(d) If any of the instruments or credit facilities include terms or conditions related to maintaining any specified minimum level of equity in the capital structure, interest coverage, or other metrics, please identify the particulars if not already provided above.

(e) Please explain the nature of any guarantee of the debt of TQM including whether or not TransCanada or Gaz Métro are guarantors of any TQM debt.

(f) Is TQM of the view that its present long term, short term, and other credit facilities are not on reasonable terms and conditions? If so, please provide a full explanation of any aspect that TQM considers to be unreasonable with supporting quantifiable information that would support that view.

Response:

(a) Please refer to Attachment CAPP 5(a).

(b) TQM has a credit agreement in place with National Bank and Caisse Centrale DesJardins. It is a $85.5 million revolving term facility dated September 22, 2005 and maturing on September 22, 2011 (via amending agreement dated August 20, 2007). Interest is charged on outstanding balances at a rate of Bas + 40bp. The current outstanding balance under the facility is approximately $56.5 million.

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CAPP 5

TQM is required to maintain on a consolidated basis a debt to equity ratio of not more than 3:1.

(c) TQM has a demand credit facility with National Bank. This is a $5,000,000 demand line dated September 11, 2007 and maturing on June 30, 2008. Interest is charged at the bank’s Prime rate. Covenants are as described in (b).

(d) Please refer to the responses to CAPP 5(b) and (c).

(e) Outstanding debt (please refer to the response to CAPP 5(a) and (b)) was issued in the name of Trans Québec & Maritimes Pipeline Inc. and guaranteed by TQM Pipeline and Company, Limited Partnership. There are no other guarantees.

(f) No.

Attachment CAPP 5(a) Page 1 of 1

TQM Pipeline Outstanding Debt

Issue Settlement Maturity Amount Year Description Date Date Coupon (C$ MM's) Redemption Feature Key Feature 1999 Series H 16-Aug-1999 24-Aug-2009 6.500% 100.0 Govt of Canada + 0.21%

2000 Series I 17-Jul-2000 22-Sep-2010 7.053% 100.0 Govt of Canada + 0.30%

2005 Series J 22-Sep-2005 22-Sep-2010 3.906% 75.0 Govt of Canada + 0.10% Private Placement

5.99% * 275.0

* does not include amortization of debt discount. Doing so would result in an effective average debt rate of 6.14% RH-1-2008 Response to CAPP Item 6 March 28, 2008 Page 1 of 4

CAPP 6

Reference: Appendix 1, TQM Evidence, p. 17-18, A19, A20.

Preamble: The evidence refers to investments by TQM’s owners and the owners’ competition for capital in global markets.

TCPL provided evidence in RH-2-2004 of its non-Canadian ownership Percentage since 1990 (CAPP IR #7).

Request:

Please provide the non-Canadian percentage ownership of each of TransCanada and Gaz Métro for each year since 1990. Please comment on the reasons why, for each entity, foreign ownership is increasing or decreasing.

Response:

TransCanada

TransCanada’s common stock is widely held and it is actively traded on both the Toronto and New York stock exchanges. Its transfer agent, Computershare Trust Company of Canada, estimates that at February 29, 2008, TransCanada’s 34,075 registered shareholders held approximately 14.1 million shares. The remaining 527.4 million shares were held by a large number of beneficial shareholders (shares held by broker in the name of the brokerage house). Therefore, TransCanada is unable to comment on the reasons why foreign ownership is increasing or decreasing.

The following table provides an estimate of annual foreign holdings of the company’s common stock for each year from 1994 to 2008. The data provided by Computershare Trust Company of Canada is based on the address of record and may not be indicative of the actual geographic location of a shareholder.

Foreign Holdings of TransCanada Stock

At December 31 (except 2008 is at February 29)

1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 Canada 70% 79% 84% 88% 93% 87% 87% 87% 87% 88% 88% 88% 88% 89% 89% U.S. & Other 30% 21% 16% 12% 7% 13% 13% 13% 13% 12% 12% 12% 12% 11% 11% Total 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100%

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CAPP 6

TransCanada does not have a schedule of foreign holdings of the company’s common stock for the years 1990 to 1993.

Gaz Métro

Gaz Métro Limited Partnership (“GMLP”) units are actually owned 71% by Gaz Métro inc. and 29% by the public. The units of GMLP are only traded on the Toronto Stock Exchange.

As per GMLP's transfer agent report, CIBC Mellon, at December 15, 2007, GMLP's 278 registered unit holders (excluding one large holder) held 306,313 units. The remaining 31.7 million units held by the public were held by a large number of beneficial unit holders (units held by brokers in the name of the brokerage house). Therefore, Gaz Métro cannot obtain the information.

For unit holders that are registered with GMLP, the only information available to GMLP is the address of record for these unit holders. While some of these addresses may be located outside of Canada, they are not necessarily indicative of the “resident status” of the unit holders. Investment by "non-residents" of Canada is generally not promoted due to the tax features of the units and the Partnership Agreement. Under the terms of GMLP's Partnership Agreement, partners who are not residents of Canada can be required by the Partnership to sell their units to Canadian residents for purposes of the Income Tax Act (Canada).

The 71% ownership by Gaz Métro inc. is 100% owned by Noverco Inc. The only foreign owner of Noverco is Gaz de France. The investment by Gaz de France in Noverco was made on February 1st, 1994 and was of 24%. It has been reduced to 18% on February 6, 1997 and has remained at this level since.

In providing the foregoing shareholder data, TQM is mindful that in the past such information has been used as evidence that notwithstanding the globalization of Canada’s financial markets, Canadian market data should be the only relevant benchmark in establishing the cost of capital for Canadian pipelines. In particular, TransCanada’s non- Canadian ownership levels were used for that purpose in the RH-4-2001 proceeding.

In TQM’s view, it would inappropriate to use non-Canadian ownership level data from either of its shareholders as any basis for concluding that investment opportunities and expected returns on capital in other jurisdictions should be excluded when considering whether returns generated under the 94 Formula meet the fair return standard. TQM bases its view on the following:

Page 3 of 4

CAPP 6

• Aggregate equity capital market investment flows of Canadian and non-Canadian investors are more important than investment flows of non-Canadians with respect to a single company. As Mr. Engen points out in the response to CAPP 141, over the past 10 years aggregate Canadian investor purchases and sales of foreign stocks exceeded $10.1 trillion and stood at $1.7 trillion for 2007 alone. During the same period aggregate non-Canadian purchases and sales of Canadian stocks were some $6.5 trillion and were $1.5 trillion in 2007.

• Non-Canadian investor interest in Canadian energy infrastructure assets is not limited to investing in shares of a publicly traded company. Non-Canadian investors have been direct buyers and sellers of significant Canadian energy infrastructure assets. For example:

– Westcoast was acquired by Duke (now Spectra) for US$8.4 billion in 2001.

– Terasen was acquired by Kinder Morgan for US$5.6 billion in 2005. While the Corridor Pipeline and Terasen Gas were subsequently sold to Canadian entities (InterPipeline and Fortis), key Canadian energy infrastructure assets, including the Trans Mountain Pipeline System, remain under U.S. ownership.

– TransAlta’s power distribution system was acquired by UtiliCorp for US$707 million in 2000 and prior to that, UtiliCorp purchased West Kootenay Power. Since that time, both assets have been acquired by Fortis.

– TransAlta’s power transmission system was sold to AltaLink for $841 million. At the time of the acquisition, 25% of AltaLink was owned by non-Canadian investors (Macquarie - 15%; Transelect - 10%). Since that time, ownership has consolidated to two owners, including one non-Canadian, Macquarie, which owns 23.08% of AltaLink.

– Various other smaller, energy infrastructure assets have also been acquired by U.S. entities.

• Most of Canada’s energy infrastructure companies, including TransCanada, Fortis, Enbridge, TransAlta and Canadian Utilities are actively building and/or acquiring energy infrastructure outside Canada, primarily in the U.S. In several cases, non-Canadian growth and/or acquisition related capital expenditure programs are very large. Using capital generated internally and from outside sources, such entities compare expected returns on capital from non-Canadian investments with those which can be obtained from Canadian-based investments.

Page 4 of 4

CAPP 6

• TransCanada (and other Canadian energy infrastructure companies) relies on much more than just equity capital to build and maintain its businesses. It also relies on the debt capital, bank debt and hybrid equity capital markets. Specifically:

– As outlined in the table below, TransCanada has issued significant amounts of debt into the U.S. since 1994. Overall, $6.9 billion or 56.7% of all of TransCanada debt has been issued in the U.S. since 1994.

TransCanada PipeLines Limited Debt Issuance 1994 - 2007 ($C millions) Total Debt Debt Percentage Year Issued Issued in U.S. Issued in U.S.

1994 250 - 0.0% 1995 443 - 0.0% 1996 1,394 794 57.0% 1997 1,128 419 37.1% 1998 3,093 1,622 52.4% 1999 1,003 823 82.0% 2000 - - 2001 - - 2002 - - 2003 902 452 50.1% 2004 982 782 79.6% 2005 766 466 60.9% 2006 1,283 583 45.4% 2007 988 988 100.0%

Totals 12,232 6,930 56.7%

– TransCanada’s 13-bank banking group includes 7 non-Canadian banks which hold 54% of TransCanada’s $2.0 billion credit facility.

– TransCanada recently completed a US$1.0 billion offering of hybrid equity (junior subordinated notes) in the U.S. capital market. Such a market did not and does not exist in Canada for TransCanada.

RH-1-2008 Response to CAPP Item 7 March 28, 2008 Page 1 of 2

CAPP 7

Reference: Appendix 1, TQM Evidence

Preamble: The evidence speaks of the fair return. In RH-4-2001 on February 27, 2002 MR. Girling for TCPL said he personally had been aware for the previous four or five years that the NEB allowed return was no longer a fair return and that the awareness by the company that investors were of this view dated from January 1999 (1T1015 – 1041).

Request:

(a) Is this still TCPL’s view?

(b) When does Gaz Metro say that NEB allowed returns ceased to be a fair return?

(c) When does TQM say that NEB allowed returns ceased to be a fair return?

(d) Has there been any year since 1994 that TCPL, Gaz Metro, or TQM would say the NEB formula has produced a fair return?

Response:

(a) The preamble to Question 7 is not entirely accurate in its description of the evidence of Mr. Girling in the RH-4-2001 proceeding (1T1006-1064). In fact, Mr. Girling spoke of an evolutionary process leading to his realization that the returns being earned by the TCPL Mainline were not equivalent to the returns being earned on other investments, including U.S. pipes (see, e.g. 1T1008-1020). He personally reached the conclusion that the Mainline return was unfair four or five years before his February 2002 appearance in RH-4-2001 (1T1015-1020), and his personal understanding of shareholders’ concerns about returns dated from approximately January 1999 (1T1041--though that was not a specific date-- 1T1047) when he began having discussions with shareholders in his position as Chief Financial Officer (1T1036-1048). See response to (d) below.

(b) It is TQM's understanding that Gaz Métro’s allowed rate of return is set through a formula similar to the formula applied to TQM for its allowed rate of return and that Gaz Métro has had increasing concerns with regard to the fairness of its own allowed rate of return on rate base since 1999. Since the results of the application of its formula was not satisfactory to Gaz Métro, it then concentrated its efforts in

Page 2 of 2

CAPP 7

the negotiation with its customary interveners and sought approval from the Régie of incentive mechanisms that would allow for improved overall returns. Although the productivity gains which have occurred since 2001 did indeed result in improvements, Gaz Métro ultimately came to the realization that the issue would have to be raised again before the Régie and therefore filed an application to review the formula in 2007.

(c) Please refer to the response to (d) below.

(d) No. In the RH-2-94 proceeding, TransCanada requested approval of a rate of return of 13 percent on deemed equity of 30 percent. TQM sought a rate of return of 13 percent on 35 percent deemed equity (RH-2-94 Decision, pages 3 and 7). The NEB decision was 12.25 percent return on 30 percent equity for both, together with the implementation of a formula that has had the effect of reducing returns since. The gap between the allowed cost of capital and what TQM views as a fair return is greater today than it was in 1994.

RH-1-2008 Response to CAPP Item 8 March 28, 2008 Page 1 of 2

CAPP 8

Reference: Appendix 1, TQM Evidence.

Preamble: The evidence speaks about capital attraction, including on reasonable terms and conditions, as well as about TQM’s owners’ competition for capital.

Request:

(a) Has TQM, in fact, at any time since 1994 either been unable to attract capital or attracted capital on terms and conditions that TQM considered unreasonable? If so, please provide the particulars including the terms and conditions that TQM considered unreasonable.

(b) Please provide a list of all issues of debt and equity since 1994 by TQM, identifying the amount of capital raised in each issue together with the major terms and conditions of each that affect the reasonableness of the terms and conditions.

(c) Please provide a comparison of the cost of debt raised by TQM since 1994 with the cost of debt raised by “A” rated utilities, by “BBB” rated utilities, and utilities with split A/BBB ratings. Identify the rating for each entity and year.

(d) What were TQM’s capital requirements for each year 1995 to 2006? What are TQM’s forecast capital requirements for 2007 and 2008? What are TQM’s forecast capital requirements for each year 2009 to 2013?

(e) Did TQM see itself as a declining rate base pipeline in 1994?

(f) Does TQM view the growth in rate base that has in fact occurred after 1994 to be a good or bad thing for the company and its investors? Explain.

Response:

(a) No.

(b) Please refer to Attachment CAPP 8(b).

Page 2 of 2

CAPP 8

(c) Please refer to Attachment 1, CAPP 8(c) which outlines the cost of debt raised by TQM since 1994.

Please refer to Attachment 2, CAPP 8(c) which outlines historic debt costs for certain “A”, “BBB” and split rated (“A/BBB”) utilities. This data has been provided by Bank of Montreal.

(d) Capital Expenditures ($000s CAD):

1995 $18,374 2002 $2,773

1996 $17,115 2003 $1,026

1997 $20,881 2004 $1,967

1998 $227,207 2005 $6,132

1999 $38,800 2006 $34,123

2000 $3,512 2007 $3,002

2001 $8,150 2008 $8,323 *

2009-13 $2,000 / year *

* forecast

(e) The 1994 business environment faced by TQM was uncertain, so TQM could not have seen itself as either expanding or declining. TQM agrees with the Board when it stated in the RH-2-2004 Phase II Decision (pages 46-47) “…the Board is of the view that the business risk of the remaining assets does not decline simply because the rate base is becoming smaller.”

(f) A regulated pipeline company invests on the expectation that it will earn a fair return and recover its capital. In hindsight, TQM does not feel that it has achieved a fair return on some of the investments listed above. Attachment CAPP 8(b) Page 1 of 1 TQM Pipeline Capital Raised

Amount EQUITY CONTRIBUTIONS Year (C$ MM's)

1994 $34.0 1995 $9.6 1997 $3.8 1998 $57.0

DEBT ISSUED Issue Settlement Maturity Amount Year Description Date Date Coupon (C$ MM's)

1995 First Mortgage Bonds "E" 5-Oct-1995 22-Sep-1998 7.630% $10.0 First Mortgage Bonds "F" 5-Oct-1995 22-Sep-2000 7.970% $35.0 First Mortgage Bonds "G" 5-Oct-1995 22-Sep-2005 8.510% $85.0 $130.0

1999 Series H 16-Aug-1999 24-Aug-2009 6.500% $100.0

2000 Series I 17-Jul-2000 22-Sep-2010 7.053% $100.0

2005 Series J 22-Sep-2005 22-Sep-2010 3.906% $75.0 Revolving term loan 22-Sep-2005 22-Sep-2010 BA's + 40bps $85.5 Attachment 1 CAPP 8(c) Page 1 of 1

DEBT ISSUED Issue Pricing Settlement Maturity Amount Year Description Date Date Date Coupon (C$ MM's) Corp Spread GoC Reference Bond

1995 First Mortgage Bonds "E" 15-Sep-1995 5-Oct-1995 22-Sep-1998 7.630% 10.0 0.37% 8% 8/11/98 First Mortgage Bonds "F" 15-Sep-1995 5-Oct-1995 22-Sep-2000 7.970% 35.0 0.42% 7.5% 9/1/00 First Mortgage Bonds "G" 15-Sep-1995 5-Oct-1995 22-Sep-2005 8.510% 85.0 0.61% 8.75% 12/1/05 130.0

1999 Series H 27-Jul-1999 16-Aug-1999 24-Aug-2009 6.500% 100.0 0.84% 5.5% 6/1/09

2000 Series I 6-Jul-2000 17-Jul-2000 22-Sep-2010 7.053% 100.0 1.20% 5.5% 6/1/09

2005 Series J 19-Sep-2005 22-Sep-2005 22-Sep-2010 3.906% 75.0 0.41% 4% 9/1/10 Revolving term loan 19-Sep-2005 22-Sep-2005 22-Sep-2010 BA's + 40bps 85.5 Attachment 2 CAPP 8(c) Page 1 of 4

Composite

A Hydro One A A(H) Aa3 CU Incorporated OPCO A A(H) CU Limited HOLDCO A A Alta Link A- A A3 Borealis A- A Toronto Hydro A- A

Split Rated Fortis Alberta A(L) Baa1 EDFIN A- A(L) Epcor Utilities BBB+ A(L) N.S. Pwr. (Emera +20 to 30) BBB A(L) Trans Alta Utilities BBB A(L) Fortis Inc. A- BBB(H)

BBB Fortis BC BBB(H) Baa2 Brookfield Power BBB BBB(H) Trans Alta Corp. BBB BBB Baa2 Attachment 2 CAPP 8(c) Page 2 of 4

Historical 5yr Corporate Spreads

220 A Rated 200 Split Rated BBB Rated 180

160

140

120

100 Spread (bps) 80

60

40

20

0 Jan-00 Jan-01 Jan-02 Jan-03 Jan-04 Jan-05 Jan-06 Jan-07 Jan-08 Attachment 2 CAPP 8(c) Page 3 of 4

Historical 10yr Corporate Spreads

270 A Rated Split Rated 240 BBB Rated

210

180

150

120 Spread (bps)

90

60

30

0 Jan-00 Jan-01 Jan-02 Jan-03 Jan-04 Jan-05 Jan-06 Jan-07 Jan-08 Attachment 2 CAPP 8(c) Page 4 of 4

Historical 30yr Corporate Spreads

350 A Rated Split Rated BBB Rated 300

250

200

150 Spread (bps)

100

50

0 Jan-00 Jan-01 Jan-02 Jan-03 Jan-04 Jan-05 Jan-06 Jan-07 Jan-08 RH-1-2008 Response to CAPP Item 9 March 28, 2008 Page 1 of 2

CAPP 9

Reference: Appendix 1, TQM Evidence.

Preamble: The evidence refers to financial integrity and changed circumstances since the RH-2-94 Decision. Evidence on bond ratings has also been filed by TQM.

Request:

(a) For each year 1994 to 2006, as well as 2007 and 2008 both at the status quo return and the applied for return, please provide the interest coverage ratios as DBRS would calculate them, the FFO Interest coverage and the FFO to Total Debt as S&P would calculate them for TQM and please provide the supporting calculations in Excel worksheet format.

(b) For each year 1994 to 2007 and the 2008 estimate, please provide the interest coverage ratios as DBRS would calculate them and the FFO Interest coverage and FFO to Total Debt as S&P would calculate them for TransCanada consolidated as well as the TCPL Mainline and for Gaz Métro consolidated as well as the Quebec natural gas distribution business and please provide the supporting calculations in Excel worksheet format.

Response:

(a) Please refer to Attachments 1 & 2 to CAPP 9(a). TQM is also providing the attachment in electronic format capable of computer calculation to the Board and CAPP. The data will be provided in a CD format to other parties upon request by e-mail to TQM's counsel ([email protected]).

(b) Please refer to Attachment 1 & 2 to CAPP 9(b). TQM is also providing the attachment in electronic format capable of computer calculation to the Board and CAPP. The data will be provided in a CD format to other parties upon request by e-mail to TQM's counsel ([email protected]).

Ratios published by S&P for Gaz Métro’s activities are calculated using its general partner’s consolidated financial statements since 2002 (Gaz Métro, Inc instead of Gaz Métro Limited Partnership). The results are not significantly different but both sets of calculations are provided.

Page 2 of 2

CAPP 9

Note that Gaz Métro does not produce separate financial statements for the Québec natural gas distribution activity.

Attachment 1 CAPP 9(a) Page 1 of 1

Forecast Forecast (based on Applied Returns) (status quo) 2008 * 2007 * 2008 * 2007 * 2006 * 2005 * 2004 2003 2002 2001 2000 1999 1998 1997 1996 1995 1994

TQM EBIT / Interest (times) 3.0 3.1 2.2 2.2 2.1 2.3 2.2 2.3 2.3 2.2 2.0 1.7 1.6 1.9 1.9 1.9 1.6

FFO / Interest (times) 3.5 3.6 2.9 2.9 2.8 2.7 2.3 2.5 2.6 2.4 2.0 2.8

EBITA / Interest (times) 2.5 2.7 2.6 2.5 2.1

FFO / Debt (%) 15.7 15.9 11.2 11.2 11.0 11.5 8.8 10.1 10.2 10.0 8.3 14.6 8.6 8.5 11.5 10.9 11.2

Source: - EBIT / Interest from DBRS reports (unless otherwise inidcated) - FFO / Interest & FFO / Debt from S&P reports for period 1999-2004 (unless otherwise inidcated) - EBITA / Interest and FFO / Debt from CBRS reports for period 1994-1998 (unless otherwise inidcated) * Internal calcuation (see Attachment 2) TQM Credit Metrics (internal calculations) Attachment 2 CAPP 9(a) Page 1 of 1 Current Forecast Budget ACTUALS (based on Applied Returns) (status quo) 2008 2007 2008 2007 ** 2006 2005 (In thousands of dollars)

EBIT $52,190 $54,164 $43,394 $44,087 42,772 50,458

ADJUSTED DEBT Long Term Debt 275,000 275,000 275,000 275,000 275,000 275,000 Current Portion of L/T Debt - - - - Notes Payable / Term Loan 3,328 10,081 53,673 55,500 65,700 57,000 Less Cash (200) (200) (200) (585) (1,052) (560) 278,128 284,881 328,473 329,915 339,648 331,440

FFO 43,880 * 45,469 * 36,967 * 36,904 * 38,628 38,397 Less AFUDC (Capitalized Interest) (84) (92) (107) (88) (1,139) (202) Adjusted FFO 43,796 45,377 36,860 36,816 37,489 38,195

INTEREST Financial Charges 17,378 17,615 19,511 19,758 19,601 21,798 Capitlized Interest 84 92 107 88 1,139 202 Adjusted Financial Charges 17,462 17,707 19,618 19,846 20,740 22,000

ADJUSTED TOTAL CAPITAL Total Debt Adjusted 278,128 284,881 328,473 329,915 339,648 331,440 Common Equity 185,567 190,031 141,958 142,829 147,182 142,951 Total Capital 463,695 474,912 470,431 472,744 486,830 474,391

Debt/Equity Ratio 0.60 0.60 0.70 0.70 0.70 0.70

* Preliminary LNG expenditures are a "deferred charge" which appears as reduction to operating activities of the cash flow statement. These amounts have been reclasified as a capital expenditure (investing activities of cash flow statement) for purposes of calculating these ratios. ** Actuals based on QSR reports

Current Forecast Budget ACTUALS (based on Applied Returns) (status quo) 2008 2007 2008 2007 2006 2005

EBIT / Interest 3.0 3.1 2.2 2.2 2.1 2.3

FFO / Interest 3.5 3.6 2.9 2.9 2.8 2.7

FFO / Debt 15.7% 15.9% 11.2% 11.2% 11.0% 11.5% Attachment 1 CAPP 9(b) Page 1 of 1

2007* 2006 2005 2004 2003 2002 2001 2000 1999 1998 1997 1996 1995 1994

TransCanada PipeLines Limited EBIT / Interest (times) 2.3 2.6 2.3 2.4 2.3 2.3 2.1 2.0 1.7 1.7 1.9 2.0 1.9 1.8

FFO / Interest (times) 3.2 2.9 2.8 2.8 2.8 2.6 2.6 2.2 1.8 2.0 2.3 2.4 2.3 2.4

FFO / Debt (%) 19.5 14.8 13.5 13.5 14.8 14.7 12.9 10.0 7.5 8.2 10.6 15.4 13.9 13.3

Source: - EBIT / Interest from DBRS reports (unless otherwise inidcated) - FFO / Interest & FFO / Debt from CBRS/S&P reports (unless otherwise inidcated) * Internal calcuation (see below) - no publically available data for 2008

* Internal Calculation 2007 2006

EBIT 2,660 FFO 2,603 Interest 1,176 Long Term Debt 13,875 12,847 EBIT/Interest 2.3 FFO/ Interest 3.2 FFO / Avg Debt 19.5%

TransCanada Mainline ** 2007 2006 2005 2004 2003 2002 2001 2000 1999 1998 1997 1996 1995 1994 EBIT 782 819 885 974 982 1014 963 964 920 909 874 923 861 780 FFO 665 642 676 704 719 656 634 611 588 543 505 483 475 425 Interest 355 364 380 416 445 463 484 501 516 482 452 447 439 420 Long Term Debt 4303 4786 4916 5152 4853 4947 5014 5572 5733 5536 4773 4331 4191 4045 EBIT/Interest 2.2 2.3 2.3 2.3 2.2 2.2 2.0 1.9 1.8 1.9 1.9 2.1 2.0 1.9 FFO/ Interest 2.9 2.8 2.8 2.7 2.6 2.4 2.3 2.2 2.1 2.1 2.1 2.1 2.1 2.0 FFO / Debt 15.5% 13.4% 13.7% 13.7% 14.8% 13.3% 12.6% 11.0% 10.3% 9.8% 10.6% 11.2% 11.3% 10.5%

** Internal calcuation (accounting) - no publically available data for 2008 Attachment 2 CAPP 9(b) Page 1 of 2

RATIOS CALCULATION - DBRS AND S & P GAZ MÉTRO LIMITED PARTNERSHIP CONSOLIDATED (Except for the ratios, the amounts are in millions of dollars)

EBITDA (Interest coverage) - DBRS

Fiscal year 30/09/1994 30/09/1995 30/09/1996 30/09/1997 30/09/1998 30/09/1999 30/09/2000 30/09/2001 30/09/2002 30/09/2003 30/09/2004 30/09/2005 30/09/2006 30/09/2007

Net income 123.6 135.0 145.8 138.7 140.7 135.8 143.7 141.2 154.6 153.3 160.4 154.4 147.2 122.8 Plus Amortization 78.4 82.0 87.6 92.4 100.8 106.8 120.8 127.1 135.2 131.9 128.6 133.1 137.7 155.4 Plus Interest expenses 86.4 93.5 95.7 86.3 80.1 90.5 92.8 101.3 89.4 90.0 89.7 91.3 94.7 107.7 Plus Taxes ------9.5 7.6 8.8 11.9 32.5 Ms Share of income - cies subject to significant influence ------(14.7) (12.4) (22.1) (15.5) EBITDA 288.4 310.5 329.2 317.3 321.6 333.1 357.3 369.6 379.2 384.7 371.6 375.3 369.5 403.0

Interest expenses 86.4 93.5 95.7 86.3 80.1 90.5 92.8 101.3 89.4 90.0 89.7 91.3 94.7 107.7

EBITDA (INTEREST COVERAGE) 3.34 3.32 3.44 3.68 4.02 3.68 3.85 3.65 4.24 4.28 4.14 4.11 3.90 3.74

Funds from operation (Interest coverage) - Standard & Poor's

Fiscal year 30/09/1994 30/09/1995 30/09/1996 30/09/1997 30/09/1998 30/09/1999 30/09/2000 30/09/2001 30/09/2002 30/09/2003 30/09/2004 30/09/2005 30/09/2006 30/09/2007

Cash Flows related to operations 225.6 253.3 298.4 246.3 231.8 246.5 190.0 323.0 298.8 298.9 340.9 319.4 309.4 396.5 Plus Post-retirement benefit obligations (Note 1) ------(1.1) (3.5) (2.0) 10.3 8.4 0.2 11.9 Ms Reclass. of working capital cash 27.1 (4.8) (22.7) 10.3 (1.9) (12.5) 75.8 (25.6) (12.6) 50.2 9.8 26.1 (12.1) (48.9) flow changes Funds from operations 252.8 248.5 275.7 256.6 229.9 234.1 265.9 296.3 282.7 347.2 361.0 353.9 297.5 359.6

Interest paid 86.4 93.5 95.7 86.3 88.4 89.0 92.2 92.0 86.9 87.5 82.3 90.2 90.3 104.4

Interest expenses 86.4 93.5 95.7 86.3 80.1 90.5 92.8 101.3 89.4 90.0 89.7 91.3 94.7 107.7

FFO (INTEREST COVERAGE) 3.9 3.7 3.9 4.0 4.0 3.6 3.9 3.8 4.1 4.8 4.9 4.9 4.1 4.3

Note 1 Post-retirement benefit obligations Actual return on plan assets ------21.9 19.7 18.9 34.6 31.9 26.4 46.5 Plus Employer contributions ------2.2 3.3 6.0 9.2 10.3 10.9 12.1 Ms Current service cost ------(9.0) (9.7) (8.7) (8.7) (9.0) (14.7) (14.3) Ms Interest cost ------(17.0) (18.6) (19.2) (19.4) (20.4) (22.3) (26.0) Total before taxes ------(1.8) (5.4) (3.0) 15.8 12.9 0.3 18.3 Taxes (35 %) ------(0.6) (1.9) (1.1) 5.5 4.5 0.1 6.4 Total ------(1.1) (3.5) (2.0) 10.3 8.4 0.2 11.9

Funds from operations (to total debt) - Standard & Poor's

Fiscal year 30/09/1994 30/09/1995 30/09/1996 30/09/1997 30/09/1998 30/09/1999 30/09/2000 30/09/2001 30/09/2002 30/09/2003 30/09/2004 30/09/2005 30/09/2006 30/09/2007

Funds from operations 252.8 248.5 275.7 256.6 229.9 234.1 265.9 296.3 282.7 347.2 361.0 353.9 297.5 359.6

Borrowings 45.5 38.4 21.0 45.8 45.0 45.8 33.2 38.4 29.9 30.8 28.5 29.8 37.1 40.8 Plus Short term portion 56.2 81.3 12.1 26.0 10.1 11.3 3.7 3.1 44.4 16.7 46.2 28.0 81.0 9.4 Plus Long term debt 739.0 767.5 841.9 819.8 1,034.8 1,082.4 1,189.8 1,267.2 1,196.8 1,271.9 1,162.7 1,353.7 1,314.9 1,644.2 Debt 840.7 887.2 875.0 891.6 1,089.8 1,139.5 1,226.7 1,308.8 1,271.0 1,319.4 1,237.5 1,411.6 1,433.0 1,694.4

Accrued benefit obligation ------284.4 296.7 296.6 313.4 419.8 396.8 514.5 Plan assets at fair value ------(268.1) (257.5) (254.6) (282.4) (310.6) (331.9) (426.5) ------16.3 39.2 42.0 30.9 109.2 64.8 88.0 Taxes ------(5.7) (13.7) (14.7) (10.8) (38.2) (22.7) (30.8) Plus Post-retirement benefit obligation ------10.6 25.5 27.3 20.1 71.0 42.1 57.2

Total debt 840.7 887.2 875.0 891.6 1,089.8 1,139.5 1,226.7 1,319.4 1,296.5 1,346.7 1,257.6 1,482.6 1,475.1 1,751.6

FFO (TO TOTAL DEBT) 30.1% 28.0% 31.5% 28.8% 21.1% 20.5% 21.7% 22.5% 21.8% 25.8% 28.7% 23.9% 20.2% 20.5%

Note Those ratios have been calculated in accordance with Standard & Poor's and DBRS formulas. They are based on the amounts available for the years 1994 to 2007. Attachment 2 CAPP 9(b) Page 2 of 2

CALCUL DE RATIOS DBRS - S & P GAZ MÉTRO INC. CONSOLIDATED (Except for the ratios, the amounts are in millions of dollars)

Funds from operation (Interest coverage) - Standard & Poor's

Fiscal year 30/09/2002 30/09/2003 30/09/2004 30/09/2005 30/09/2006 30/09/2007

Cash Flows related to operations 203.6 191.8 253.2 237.5 233.4 322.1 Plus Equity-like hybrids 73.5 71.2 69.2 68.2 61.9 62.5 Plus Post-retirement benefit oblig. (see SCGM) (3.5) (2.0) 10.3 8.4 0.2 11.9 Ms Reclass. of dividends (2.5) (2.7) (3.0) (3.3) (3.8) (4.0) Ms Reclass. of working capital cash (17.8) 66.5 11.8 23.8 (11.9) (49.7) flow changes Funds from operations 253.2 324.8 341.5 334.7 279.8 342.8

Interest paid 160.2 159.5 152.0 158.6 153.8 166.9

Interest 163.0 161.4 159.0 158.1 156.6 170.4 Ms Equity-like hybrids (73.5) (71.2) (69.2) (68.2) (61.9) (62.5) Interest expenses 89.6 90.2 89.9 89.8 94.7 107.9

FFO (TO INTEREST COVERAGE) 4.6 5.4 5.5 5.5 4.6 4.7

Funds from operations (to total debt) - Standard & Poor's

Fiscal year 30/09/2002 30/09/2003 30/09/2004 30/09/2005 30/09/2006 30/09/2007

Funds from operations 253.2 324.8 341.5 334.7 279.8 342.8

Borrowings 29.9 30.8 28.5 29.8 37.1 40.8 Plus Short term portion 44.4 16.7 46.2 28.0 81.0 9.4 Plus Long term debt 1,897.2 1,972.3 1,863.2 2,054.2 2,022.6 2,351.9 Ms Equity -like hybrids (707.8) (707.8) (707.8) (707.8) (707.8) (707.8) Plus Post-retirement benefit oblig.(See SCGM) 25.5 27.3 20.1 71.0 42.1 57.2 Total debt 1,289.1 1,339.3 1,250.2 1,475.2 1,475.1 1,751.6

FFO (TO TOTAL DEBT) 19.6% 24.3% 27.3% 22.7% 19.0% 19.6%

Note Those ratios have been calculated in accordance with Standard & Poor's and DBRS formulas. They are based on the amounts available for the years 1994 to 2007.

The S&P calculated ratios differ from the information they published for the 2003 to 2006 years. We received confirmation that they lately restated the numbers in their system but did not restate published reports for all these changes. RH-1-2008 Response to CAPP Item 10 March 28, 2008 Page 1 of 2

CAPP 10

Reference: Appendix 1, TQM Evidence.

Preamble: The evidence refers to financial integrity and changes in circumstances since the RH-2-94 Decision. Evidence on bond ratings has also been filed by TQM.

Request:

(a) Please indicate the bond rating history of TQM since its inception (DBRS, CBRS, S&P).

(b) Please provide all DBRS, CBRS, and S&P reports on TQM since the 1994 NEB cost of capital hearing as well as all bond rating actions, opinions, comments, or press releases.

(c) Please provide all bond rating actions, reports, opinions, comments, statements, or press releases regarding TransCanada and Gaz Métro since the 1994 NEB cost of capital hearing.

Response:

(a) TQM credit ratings available from 1994

DBRS S&P CBRS 1994 A (low) A (low) 1995 A (low) A (low) 1996 A (low) A (low) 1997 A (low) A (low) 1998 A (low) A (low) 1999 A (low) A (low) 2000 A (low) A (low) 2001 A (low) BBB+ 2002 A (low) BBB+ 2003 A (low) BBB+ 2004 A (low) BBB+ 2005 A (low) BBB+ 2006 A (low) BBB+ 2007 A (low) BBB+

Page 2 of 2

CAPP 10

(b) The requested materials are voluminous. A reading room is being established at the offices of TransCanada’s counsel, Stikeman Elliott LLP (Calgary), where the materials may be accessed by interested parties and the Board. Arrangements for viewing may be made by email to [email protected].

(c) The requested materials are voluminous. A reading room is being established at the offices of TransCanada’s counsel, Stikeman Elliott LLP (Calgary), where the materials may be accessed by interested parties and the Board. Arrangements for viewing may be made by email to [email protected].

RH-1-2008 Response to CAPP Item 11 March 28, 2008 Page 1 of 1

CAPP 11

Reference: Appendix 1, TQM Evidence.

Preamble: The evidence refers to TQM’s owners as investors and the investors in the owners as indirect investors in TQM.

Request:

Please provide the most recent annual reports for TransCanada and Gaz Métro.

Response:

Please refer to Attachments 1 and 2 to CAPP 11.

TransCanada Corporation 2007 Annual Report for growth andvaluecreation capturing opportunities Page CAPP Attachment 1 11 of 142 1 Attachment 1 CAPP 11 Page 2 of 142 our focus

Operating one of the most sophisticated pipeline systems in the world, TransCanada moves 15 billion cubic feet of natural gas per day (20 per cent of North American production), delivering to markets throughout Canada and the U.S. With the acquisition of ANR in early 2007, TransCanada’s network of wholly owned pipelines now extends more than 59,000-kilometres (36,500 miles) and taps into virtually all major gas supply basins in North America. TransCanada is also one of the continent’s largest providers of gas storage and related services with approximately 355 billion cubic feet of storage capacity. We’re focused on optimizing our pipeline network by connecting new supply, providing better access to markets and introducing competitive and innovative approaches to meeting customer needs.

More recently, TransCanada has made a significant entry into the oil pipeline business and created another platform for future growth. Our Keystone Oil Pipeline project is a cost-competitive way to link growing Canadian oil sands supply to refineries in the U.S. Midwest. This is a logical fit with our existing business competencies and an innovative way to maximize the use and value of our current pipeline assets.

TransCanada’s Energy business concentrates on power generation and marketing, and gas storage. A growing independent power producer, TransCanada owns, or has interests in, approximately 7,700 megawatts of power generation in Canada and the United States. Our diversified power portfolio includes nuclear, natural gas, coal, hydro and wind generation. We are also actively pursuing two greenfield LNG terminals, in Quebec and near New York City.

With more than 50 years experience in energy infrastructure development and operations, combined with excellent project management skills, in-depth market knowledge, financial strength and business acumen, TransCanada is well positioned to be a partner and developer of choice.

monthly close and volume TSX and NYSE 2000 – 2007

volume (millions) Monthly Close TSX (Cdn $) Monthly Close NYSE (US $) Average Daily Volume (TSX and NYSE) dollars 2.5 40

2.0 30

1.5

20 1.0

10 0.5

0.0 0 00 01 02 03 04 05 06 07 Attachment 1 CAPP 11 Page 3 of 142

4 4

3

8

9

6 5 7

2 9 1

1

Pipelines

Pipelines (Proposed)

Power Generation

Gas Storage Proposed LNG Terminals Attachment 1 CAPP 11 Page 4 of 142 project highlights

1. ANR: In early 2007 TransCanada closed its US $3.4 billion acquisition of ANR adding approximately 17,000 km (10,600 miles) of pipeline to TransCanada’s North American gas pipeline bring Bruce Power capacity to a total of 6,200 MW. The system. The ANR acquisition also added 235 Bcf of natural gas planned refurbishment of Units 3 & 4 combined with storage capacity to our portfolio. At the same time, TransCanada the refurbishment and restart of Units 1 & 2 represents and TC PipeLines, LP acquired a 50 per cent interest in Great an investment of more than $5.5 billion. TransCanada’s Lakes. TransCanada now owns 53.6 per cent of Great Lakes and share is expected to be more than $2.75 billion. TC PipeLines, LP owns the remaining 46.4 per cent. TransCanada owns a 48.7 per cent interest in Bruce A and a 31.6 per cent interest in Bruce B. 2. Keystone Pipeline: TransCanada reached several significant milestones on the US $5.2 billion, 3,456-km (2,148-mile) 6. Portlands Energy Centre: Construction oil pipeline project. The pipeline, currently beginning its continues on the Portlands Energy Centre project. This project includes the construction and operation construction phase, will be capable of delivering 590,000 of a 550 MW high-efficiency, combined-cycle barrels per day of crude oil from Hardisty, Alberta, to U.S. natural gas generation plant in Toronto. The capital Midwest markets at Wood River and Patoka, Illinois, and to cost of the Portlands Energy Centre project is Cushing, Oklahoma. Initial deliveries to Patoka and Wood River estimated to be approximately $730 million and is are expected to begin in late 2009. TransCanada owns a expected to be operational in simple-cycle mode 50 per cent interest in Keystone. beginning in June 2008. TransCanada owns 3. Alberta System: An application was filed with the Alberta 50 per cent of Portlands Energy Centre. Energy and Utilities Board (EUB) for the $983 million North 7. Halton Hills Generating Station: Site preparation Central Corridor pipeline, a 300-km natural gas pipeline and construction began on the Halton Hills Generating expansion of the Alberta System that will connect the northwest Station which includes the construction and operation and the northeast portions of the system. The project will provide of a 683 MW natural gas-fired power plant near the capacity to accommodate evolving supply and demand dynamics town of Halton Hills, Ontario. TransCanada expects within and outside of Alberta. to invest approximately $670 million in this project, 4. Northern Pipelines: TransCanada continues to work with which is anticipated to be in service in the third other stakeholders on northern pipeline initiatives including the quarter of 2010. Mackenzie Gas Pipeline project and the Alaska Pipeline project. 8. Cartier Wind: The second phase of the Cartier Wind

5. Bruce Power: A milestone in the Bruce A Units 1 and 2 project, the 101 MW Anse-à-Valleau wind farm, was placed into service in November 2007. Construction is refurbishment and restart project was completed when the underway on the third phase of the project, the sixteenth and final new steam generator was installed in early 110 MW Carleton wind farm. Capacity is expected to January 2008. Bruce A Units 1 and 2 are expected to produce total 740 MW when all six phases are complete in 2012. an additional 1,500 MW when completed in 2010 which will TransCanada has a 62 per cent interest in Cartier Wind.

9. LNG projects: TransCanada continues to pursue two proposed LNG terminals, Broadwater in Long Island Sound, New York and Cacouna, in Gros Cacouna, Québec. Attachment 1 CAPP 11 Page 5 of 142 TRANSCANADA CORPORATION 1

Year ended December 31 (millions of dollars) 2007 2006 2005 2004 2003 Income Net income Financial Continuing operations 1,223 1,051 1,209 980 801 Highlights Discontinued operations – 28 – 52 50 1,223 1,079 1,209 1,032 851 Cash Flow Funds generated from operations2,621 2,378 1,951 1,703 1,822 Decrease/(increase) in operating working capital215 (303) (49) 29 93 Net cash provided by operations2,836 2,075 1,902 1,732 1,915 Capital expenditures and acquisitions5,874 2,042 2,071 2,046 965

Balance Sheet Total assets30,330 25,909 24,113 22,422 20,887 Long-term debt12,377 10,887 9,640 9,749 9,516 Junior subordinated notes 975 –––– Common shareholders’ equity9,785 7,701 7,206 6,565 6,091

Common Share Statistics Year ended December 31 2007 2006 2005 2004 2003 Net income per share – Basic Continuing operations$2.31 $2.15 $2.49 $2.02 $1.66 Discontinued operations– 0.06 – 0.11 0.10 $2.31 $2.21 $2.49 $2.13 $1.76 Net income per share – Diluted Continuing operations$2.30 $2.14 $2.47 $2.01 $1.66 Discontinued operations– 0.06 – 0.11 0.10 $2.30 $2.20 $2.47 $2.12 $1.76 Dividends declared per share$1.36 $1.28 $1.22 $1.16 $1.08 Common shares outstanding (millions) Average for the year529.9 488.0 486.2 484.1 481.5 End of year539.8 489.0 487.2 484.9 483.2

Net Income Net Income per Funds Generated Capital Expenditures Dividends Declared Total Shareholder from Continuing Common Share from Operations and Acquisitions per Common Share Return Operations from Continuing (millions of dollars) (millions of dollars) (dollars) (per cent) (millions of dollars) Operations – Basic (see page 132) (dollars)

5,874 1.36 2,621 1.28 1,223 2.49 1.22 1,209 2,378 28 2.31 1.16 27 1,051 2.15 1.08 980 2.02 1,951 1,822 1,703 801 1.66

15

2,046 2,071 2,042 11

965 3

03 04 05 06 07 03 04 05 06 07 03 04 05 06 07 03 04 05 06 07 03 04 05 06 07 0327FEB200812164649 04 05 06 07 Attachment 1 CAPP 11 Page 6 of 142 2 CHAIRMAN’S MESSAGE

Good governance is a cornerstone of a company’s financial success. But it’s more than rules and compliance, it is active Board involvement in the strategic direction and decisions of the company. Chairman’s Message

2007 was another successful year for TransCanada. We remained focused on our goal of being the leading energy infrastructure company in North America. This past year saw continued growth and value creation for our shareholders, strong financial performance and key developments on many major projects in our businesses. As a result, and for the eighth year in a row, your Board of Directors has increased the dividend on common shares. Further, we approved a 2% discount on common shares issued under our dividend reinvestment and share purchase plan (DRP) which allows 16FEB200620495683 common and preferred shareholders to purchase additional common shares by reinvesting their cash dividend. Corporate governance remains a top priority for TransCanada and the Board of Directors plays an integral role in setting the tone for leadership, and ultimately oversees the strategic direction and decisions made. The diversity of views represented on our board and the independent mindedness of the directors are key attributes that we have worked hard to create. Our strategy of long-term economic growth is rooted in this sound governance as well as risk-based economic modeling. Together, they enhance our competitiveness, benefit our shareholders and other stakeholders, and encourage the sustainable development of the natural resources upon which our society depends for its quality of life. When companies succeed financially, they are able to make significant contributions to the societies in which they operate. TransCanada was named to the Dow Jones Sustainability World and North American Indexes and one of only three Canadian companies named to the Global 100 Most Sustainable Companies in the World. This recognition acknowledges TransCanada’s commitment to sound governance and responsible management of environmental and social risks. TransCanada also received the 2007 Governance Gavel Award for Excellence in Compensation Disclosure from the Canadian Coalition for Good Governance. These elements are at the heart of TransCanada’s values and success. I know I speak for all Board members when I thank management and employees for their efforts in 2007. Their hard work and dedication to TransCanada’s goals and objectives were critical to the company’s prosperity this year.

On behalf of the Board of Directors,

17FEB200612245997 S. Barry Jackson Attachment 1 CAPP 11 Page 7 of 142 LETTER TO SHAREHOLDERS 3

TransCanada is well-positioned for continued success. Our strong financial performance and the significant project milestones we achieved in our Pipelines and Energy businesses in 2007 have set the stage for continued Letter growth and value creation in 2008 and beyond. to Shareholders

Our strength is a result of solid contributions from our existing assets and growing cash flow and earnings from newly acquired and developed assets such as the ANR pipeline system and the Edson gas storage facility in Alberta. 2007 began on a successful note with the closure and integration of the ANR and Great Lakes acquisition. We also continued to achieve major milestones in many of our key projects including several regulatory approvals related to the Keystone Oil Pipeline project and the successful installation of the sixteenth and final new steam generator as part of 16FEB200620494599 the Bruce Power Unit 1 and 2 restart and refurbishment project. Our strategic focus remains clear. Our vision is to become the leading energy infrastructure company in North America. In pursuing our goal, we will strive to deliver strong financial performance and maximize our financial flexibility, to execute on our current portfolio of large, attractive projects and initiatives and to continue to work to create and cultivate a high-quality portfolio of future growth opportunities.

Delivering strong financial performance and maximizing financial flexibility In 2007, TransCanada’s net income and net income from continuing operations (net earnings) was $1.223 billion ($2.31 per share) compared to net income of $1.079 billion ($2.21 per share), and net earnings of $1.051 billion ($2.15 per share) in 2006. Net earnings increased seven per cent on a per share basis in 2007. Comparable earnings(1) increased to $1.107 billion or $2.09 per share in 2007, compared to $925 million or $1.90 per share for 2006. Comparable earnings grew by 10 per cent on a per share basis in 2007. Funds generated from operations(1) increased to $2.621 billion in 2007, an increase of $243 million or 10 per cent above 2006. This strong underlying cash flow enabled us to make significant capital investments in our Pipelines and Energy businesses. We invested approximately $5.9 billion in growth initiatives in 2007. Our continued strong financial performance once again enabled our Board of Directors to increase the quarterly dividend on the company’s common shares in January 2008 by six per cent to $0.36 per share, or $1.44 per share on an annualized basis. This is the eighth year in a row the Board has increased the dividend.

(1) Non-GAAP measure that does not have any standardized meaning prescribed by generally accepted accounting principles. For more information on non-GAAP measures see page 14 in the Management’s Discussion and Analysis of the 2007 Annual Report. Attachment 1 CAPP 11 Page 8 of 142 4 LETTER TO SHAREHOLDERS

TransCanada’s balance sheet remains strong and provides the financial flexibility to execute our portfolio of opportunities. In 2007, we raised $1.725 billion in common equity through a public offering to help fund the ANR acquisition. It was the largest fully-funded subscription receipts transaction in Canadian history. In addition, we initiated a 2% discount on common shares issued under our dividend reinvestment and share purchase plan which allows common and preferred shareholders to purchase additional common shares by reinvesting their cash dividend without incurring brokerage or administrative fees. TransCanada raised over $150 million in common equity through this plan and experienced a 30% participation rate in 2007. We also sold U.S. $1 billion of 30-year senior notes and issued U.S. $1 billion of junior subordinated notes, both at very competitive market rates reflective of our strong financial position and ‘A’ credit ratings. TransCanada’s financial performance in 2007 continued to build on our strong track record of delivering strong and sustainable financial returns to our shareholders. In the last eight years, TransCanada has invested approximately $18 billion in value-creating pipeline and energy growth opportunities. Comparable earnings per share increased at a compound average annual growth rate of 8.6 per cent from $1.08 per share in 1999 to $2.09 per share in 2007. Funds generated from operations, during the same period, grew at a compound average annual growth rate of 12.2 per cent from $1 billion to $2.6 billion. This strong financial performance has created significant returns and longer-term value for our shareholders. The compound average annual total shareholder return over the past eight years is approximately 21 per cent.

Execute on large and attractive projects and initiatives TransCanada is committed to maximizing and sustaining the long-term value of existing assets. In addition to our $30 billion of assets, we have a superior growth portfolio that will see us invest approximately $10 billion in a number of energy infrastructure projects throughout North America. The majority of these projects are under construction and will be completed over the next three years. In our Pipelines business we have committed approximately $5.3 billion of capital to projects that include the Alberta System’s North Central Corridor and the Keystone Oil Pipeline project. The Keystone Oil Pipeline project is an important initiative that will allow customers to move up to 590,000 barrels per day of growing Canadian oil sands production to U.S. markets and provide TransCanada with a platform to pursue other opportunities in the crude oil transmission business. In Energy, we continued to advance a number of growth opportunities which will see us invest more than $4.6 billion in a variety of projects. One of these projects is the Bruce A restart and refurbishment project, one of the largest infrastructure projects underway in North America today. When completed, Bruce Power will be capable of producing 6,200 MW of power. Other key projects include the Halton Hills Generating Station, the Portlands Energy Centre and Cartier Wind. As we look forward, we are excited about the significant opportunities available to TransCanada in the years ahead. Our approach is to select only the very best opportunities and move those initiatives forward. Attachment 1 CAPP 11 Page 9 of 142 LETTER TO SHAREHOLDERS 5

Continue to create and cultivate a high-quality portfolio of future growth opportunities At no other time in TransCanada’s history have we had such a large and attractive portfolio of projects and investment opportunities as we have today in both our Pipelines and Energy businesses. Over the long term, we will continue to cultivate a portfolio that gives the company the ability to reinvest its substantial discretionary cash flow into opportunities in natural gas and crude oil pipelines, power generation facilities, natural gas storage and LNG terminals. As we look ahead, we see TransCanada capitalizing on North America’s increased demand for cleaner and more efficient energy. We build and operate the energy infrastructure that North America needs. TransCanada’s success is a reflection of our exceptional team of motivated employees who bring skill, experience, energy and knowledge to the work that they do. Our employees truly are our competitive advantage and remain a key part of future accomplishments. As we meet the energy needs of North America, we will continue to deliver strong and sustainable financial returns to our shareholders. We will continue to maximize our financial strength and execution capability to enable us to capture large-scale, value- creating opportunities and create value for our customers and shareholders through the selection and superb execution of the very best of these opportunities. We created significant shareholder value in 2007 and we look forward to ever greater accomplishments in 2008 and beyond.

29DEC200514425814 Hal Kvisle President and Chief Executive Officer Attachment 1 CAPP 11 Page 10 of 142 6 MANAGEMENT’S DISCUSSION AND ANALYSIS

TABLE OF CONTENTS

TRANSCANADA OVERVIEW 8 TRANSCANADA’S STRATEGY 9 CONSOLIDATED FINANCIAL REVIEW Selected Three-Year Consolidated Financial Data 11 Highlights 12 Results of Operations 13 FORWARD-LOOKING INFORMATION 13 NON-GAAP MEASURES 14 OUTLOOK 14 SEGMENT RESULTS-AT-A-GLANCE 15 PIPELINES Highlights 18 Results-at-a-Glance 19 Financial Analysis 20 Opportunities and Developments 22 Business Risks 25 Outlook 27 Natural Gas Throughput Volumes 29 ENERGY Highlights 32 Results-at-a-Glance 32 Power Plants – Nominal Generating Capacity and Fuel Type 33 Financial Analysis 34 Opportunities and Developments 43 Business Risks 44 Outlook 45 CORPORATE Results-at-a-Glance 46 Financial Results 46 Outlook 47 DISCONTINUED OPERATIONS 47 LIQUIDITY AND CAPITAL RESOURCES Summarized Cash Flow 47 Highlights 47 CONTRACTUAL OBLIGATIONS Contractual Obligations 51 Principal Repayments 52 Interest Payments 53 Purchase Obligations 53 Attachment 1 CAPP 11 Page 11 of 142 MANAGEMENT’S DISCUSSION AND ANALYSIS 7

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS Financial Risks 55 Other Risks 61 CONTROLS AND PROCEDURES 63 SIGNIFICANT ACCOUNTING POLICIES AND CRITICAL ACCOUNTING ESTIMATES 64 ACCOUNTING CHANGES 64 SELECTED QUARTERLY CONSOLIDATED FINANCIAL DATA 69 FOURTH-QUARTER 2007 HIGHLIGHTS 71 SHARE INFORMATION 73 OTHER INFORMATION 73 GLOSSARY OF TERMS 74 Attachment 1 CAPP 11 Page 12 of 142 8 MANAGEMENT’S DISCUSSION AND ANALYSIS

The Management’s Discussion and Analysis (MD&A) dated February 25, 2008 should be read in conjunction with the audited Consolidated Financial Statements of TransCanada Corporation (TransCanada or the Company) and the notes thereto for the year ended December 31, 2007. This MD&A covers TransCanada’s financial position and operations as at and for the year ended December 31, 2007. Amounts are stated in Canadian dollars unless otherwise indicated. Abbreviations and acronyms used in this MD&A are identified in the Glossary of Terms in the Company’s 2007 Annual Report.

TRANSCANADA OVERVIEW With more than 50 years experience, TransCanada is a leader in the responsible development and reliable operation of North American energy infrastructure, including natural gas pipelines, power generation, natural gas storage facilities and projects related to oil pipelines and liquefied natural gas (LNG) facilities. TransCanada’s network of wholly owned natural gas pipelines extends more than 59,000 kilometres (km), tapping into virtually all major gas supply basins in North America. TransCanada is one of the continent’s largest providers of natural gas storage and related services with approximately 355 billion cubic feet (Bcf) of natural gas storage capacity. A growing independent power producer, TransCanada owns, or has interests in, approximately 7,700 megawatts (MW) of power generation in Canada and the United States (U.S.). In addition to having total assets in excess of $30 billion, TransCanada plans to invest approximately $10 billion in a number of energy infrastructure projects in North America, with the expectation that a majority of these projects will be completed by 2010. Over the longer-term, TransCanada has a significant portfolio of large-scale infrastructure opportunities that will continue to be pursued and developed. North America’s demand for natural gas, oil and electricity is expected to continue to grow. By 2020, it is expected that demand for natural gas will grow by 15 billion cubic feet per day (Bcf/d), demand for crude oil will increase by 3 million barrels per day (Bbl/d) and demand for power will grow by 155 gigawatts. Demand for natural gas in North America is expected to increase due primarily to a growing demand for electricity. The long lead times required to complete new coal and nuclear projects could slow the development and completion of new coal or nuclear generation facilities over the next five to ten years. As a result, North America is expected to continue to rely on natural gas-fired generation to satisfy a large portion of its growing electricity needs. North America has entered a period when it will no longer be able to rely solely on traditional sources of natural gas supply to meet its growing needs. This outlook for traditional sources of natural gas means that northern gas and offshore LNG could be required to fill the shortfall between supply and demand for natural gas. TransCanada is well positioned to capture related opportunities in natural gas transmission, LNG infrastructure and power generation. TransCanada is also expanding into the crude oil transmission business with the development of a 590,000 Bbl/d crude oil pipeline from Hardisty, Alberta to refineries in U.S. midwest markets. TransCanada has partnered with ConocoPhillips, a global, integrated oil and gas producer and refiner to construct the Keystone oil pipeline to transport crude oil from Alberta to refineries in Illinois and Oklahoma. The partnership provides TransCanada with a platform for developing future crude oil pipeline opportunities. Significant oilsands development in Alberta is providing opportunities for new crude oil transmission infrastructure. TransCanada has the financial strength and flexibility to build new infrastructure to support increased energy demand, to respond to shifting energy supply-demand dynamics and to replace aging North American infrastructure. Pipelines Assets TransCanada’s natural gas pipeline assets link gas supplies from basins in Western Canada, the U.S. mid-continent and Gulf of Mexico to premium North American markets. These assets are well-positioned to connect emerging natural gas supplies, including northern gas and offshore LNG imports, to growing markets. With increasing production from the oilsands in Alberta and growing demand for secure, reliable sources of energy, TransCanada has identified opportunities to develop oil pipeline capacity. TransCanada’s Alberta System gathered 68 per cent of the natural gas produced in Western Canada or 16 per cent of total North American production in 2007. TransCanada exports natural gas from the Western Canada Sedimentary Basin (WCSB) to Eastern Canada and the U.S. West, Midwest and Northeast through three wholly owned pipeline systems: the Canadian Mainline, the GTN System and Foothills Pipe Lines Ltd. (Foothills). Attachment 1 CAPP 11 Page 13 of 142 MANAGEMENT’S DISCUSSION AND ANALYSIS 9

American Natural Resources Company and ANR Storage Company (collectively, ANR) were acquired in February 2007. ANR Pipeline Company (ANR Pipeline), a subsidiary of American Natural Resources Company, transports natural gas from producing fields located primarily in Oklahoma, Texas, Louisiana and the Gulf of Mexico to markets located primarily in Wisconsin, Michigan, Illinois, Ohio and Indiana. ANR Pipeline also connects with numerous other natural gas pipelines, providing customers with access to diverse sources of North American supply, including Western Canada and the Rocky Mountain region, and access to a variety of end-user markets in the midwestern and northeastern U.S. As a result of the ANR acquisition, TransCanada owns and operates approximately 235 Bcf of regulated natural gas storage capacity in Michigan, making it one of North America’s largest gas storage operators. TransCanada also exports natural gas from the WCSB to Eastern Canada and to the U.S. West, Midwest and Northeast through six partially owned natural gas pipeline systems: Great Lakes Transmission Limited Partnership (Great Lakes), Iroquois Gas Transmission System, L.P. (Iroquois), Portland Natural Gas Transmission System (Portland), Trans Quebec´ & Maritimes System (TQM), Northern Border Pipeline Company (Northern Border) and Tuscarora Gas Transmission Company (Tuscarora). Certain of these pipeline systems are held through the Company’s 32.1 per cent interest in TC PipeLines, LP (PipeLines LP). The Company also transports natural gas through the wholly owned TransCanada Pipeline Ventures Limited Partnership (Ventures LP) pipeline in Alberta, North Baja pipeline in the U.S. and Tamazunchale pipeline in Mexico, as well as the partially owned TransGas de Occidente S.A. (TransGas) pipeline in Columbia and Gasoducto del Pacifico S.A. (Gas Pacifico) pipeline in Argentina. In addition, the Company has a 50 per cent ownership interest in each of TransCanada Keystone Pipeline Limited Partnership (Keystone Canada) and TransCanada Keystone Pipeline LP (Keystone U.S.), (collectively Keystone). Currently beginning its construction phase, Keystone will transport crude oil from Hardisty, Alberta, to U.S. Midwest markets at Wood River and Patoka in Illinois, and to Cushing, Oklahoma. Energy Assets TransCanada has built a substantial energy business over the past decade and has achieved a significant presence in power generation in selected regions of Canada and the U.S. TransCanada owns, or has rights or interests in, approximately 7,700 MW of power generation in Canada and the U.S. These assets are primarily low-cost, base-load generation and/or are assets backed by secure, long-term power sales agreements. More recently, TransCanada has also developed a significant non-regulated natural gas storage business in Alberta.

Power by Fuel Source The Company’s power assets are concentrated in two main regions: Western Power in Alberta Wind and Eastern Power in the Eastern Canada and New England markets. TransCanada’s portfolio of Hydro 6% 7% power supply is shown in the accompanying chart. Natural Gas 33% All of TransCanada’s non-regulated natural gas storage assets are located in Alberta. TransCanada Coal owns or has rights to 120 Bcf or approximately one-third of the natural gas storage capacity in 22% the province. Opportunities and developments in the Company’s Pipelines and Energy businesses are

Nuclear discussed further in the ‘‘Pipelines’’ and ‘‘Energy’’ sections of this MD&A. 9FEB20080121077332%

TRANSCANADA’S STRATEGY TransCanada’s vision is to be the leading energy infrastructure company in North America, with a strong focus on pipelines and power generation opportunities located in regions where the Company enjoys significant competitive advantages. Since 2000, TransCanada’s key strategies have evolved with the Company’s progression and the changing business environment. Today, TransCanada’s corporate strategy consists of the following six components: • Maximize the long-term value of the Company’s natural gas transmission business; • Grow the North American pipeline and related infrastructure business; • Maximize the long-term value of existing power generation and power marketing and related businesses; • Grow North American power and energy businesses; Attachment 1 CAPP 11 Page 14 of 142 10 MANAGEMENT’S DISCUSSION AND ANALYSIS

• Drive for operational excellence; and • Maximize TransCanada’s competitive strength and enduring value. Maximize the long-term value of the Company’s natural gas transmission business TransCanada continues to place a priority on maximizing the long-term value of its natural gas transmission business. There is a strong focus on connecting supply with markets through expansions, extensions, acquisitions and strategic relationships. The Company also aims to offer competitive rates and services to meet stakeholder needs and enhance the value of its natural gas pipeline assets. Grow the North American pipeline and related infrastructure business TransCanada is pursuing the development of greenfield and brownfield pipeline projects to grow its North American pipeline and related infrastructure business. These include frontier natural gas pipeline projects such as the Mackenzie Gas Pipeline (MGP) and the Alaska Pipeline as well as crude oil pipeline projects to meet the growing demand for transportation of Alberta oilsands production. Other possible avenues of growth include: • Acquiring synergistic natural gas transmission assets that complement TransCanada’s existing core regions; • Acquiring partners’ interests in associated pipelines to enhance strategic control, profitability and value; and • Acquiring stand-alone gas transmission enterprises in new regions of North America where critical mass and solid competitive advantage can be established. The Company is also pursuing the development of natural gas pipeline infrastructure and associated LNG regasification terminals in Mexico and aims to grow pipeline earnings from PipeLines LP through acquisitions and organic growth. Maximize the long-term value of existing power generation and power marketing and related businesses TransCanada aims to maximize the long-term value of existing power generation and power marketing and related businesses, such as unregulated natural gas storage. The Company’s approach involves engaging in marketing activities – guided by strategic criteria and defined risk boundaries – that optimize the value of owned assets, as well as exercising disciplined asset management and being actively involved in regulatory and market developments. Grow North American power and energy businesses The Company is focusing primarily on the core western and eastern regions to grow its North American power and energy businesses. Consideration will be given to new markets with attractive fundamentals where TransCanada can take advantage of its competencies to enhance its competitive strengths. There is a continued focus on low-cost, base- load power assets or assets backed by firm long-term contracts with reputable counterparties. The Company is also pursuing the development of LNG regasification terminals and associated natural gas pipeline infrastructure terminals to feed TransCanada’s gas transmission grids in Eastern Canada and the U.S. Northeast, Pacific Northwest, and Gulf of Mexico. Greenfield development and acquisition of power generation, transmission and natural gas storage will be considered if they meet the Company’s rigorous strategic and value creation criteria. Drive for operational excellence TransCanada maintains a commitment to provide safe, low-cost, reliable and responsible service to customers under its operational excellence business model. The Company will continue to focus efforts in this critical area on efficiencies, operational reliability, the environment and safety. Maximize TransCanada’s competitive strength and enduring value In addition to the strategies discussed above, a number of other initiatives are being pursued in order to maximize TransCanada’s competitive strength and enduring value. These include: • Managing relationships with key stakeholder groups; • Managing counterparty and commodity exposures within the Company’s limits; • Maintaining high standards in corporate governance practices; • Enhancing strategic thinking, analysis and constructive debate that lead to astute investment decision-making; • Attracting, retaining and engaging employees to maximize performance; and • Maintaining access to abundant, low-cost capital in all market environments. Attachment 1 CAPP 11 Page 15 of 142 MANAGEMENT’S DISCUSSION AND ANALYSIS 11

CONSOLIDATED FINANCIAL REVIEW

SELECTED THREE-YEAR CONSOLIDATED FINANCIAL DATA(1) (millions of dollars, except per share amounts)

2007 2006 2005 Income Statement Revenues 8,828 7,520 6,124 Net income Continuing operations 1,223 1,051 1,209 Discontinued operations – 28 – 1,223 1,079 1,209

Comparable earnings(2) 1,107 925 839 Per Common Share Data Net income – basic Continuing operations $2.31 $2.15 $2.49 Discontinued operations – 0.06 – $2.31 $2.21 $2.49

Net income – diluted Continuing operations $2.30 $2.14 $2.47 Discontinued operations – 0.06 – $2.30 $2.20 $2.47

Comparable earnings per share(2) $2.09 $1.90 $1.72 Dividends declared $1.36 $1.28 $1.22 Summarized Cash Flow Funds generated from operations(2) 2,621 2,378 1,951 Decrease/(increase) in operating working capital 215 (303) (49) Net cash provided by operations 2,836 2,075 1,902

Balance Sheet Total assets 30,330 25,909 24,113 Total long-term liabilities 16,511 14,464 13,012

(1) The selected three-year consolidated financial data is based on the Company’s financial statements which are prepared in accordance with Canadian generally accepted accounting principles (GAAP). (2) Refer to the ‘‘Non-GAAP Measures’’ section of this MD&A for further discussion of comparable earnings, comparable earnings per share and funds generated from operations. Attachment 1 CAPP 11 Page 16 of 142 12 MANAGEMENT’S DISCUSSION AND ANALYSIS

HIGHLIGHTS Net Income • Net income and net income from continuing operations (net earnings) was $1,223 million or $2.31 per share in 2007 compared to net income of $1,079 million or $2.21 per share and net earnings of $1,051 million or $2.15 per share in 2006.

Comparable Earnings • TransCanada’s comparable earnings in 2007 excluded favourable income tax adjustments of $102 million and a gain of $14 million on sale of land. Comparable earnings increased $182 million to $1,107 million or $2.09 per share in 2007 compared to $925 million or $1.90 per share in 2006.

Cash from Operations • Net cash provided by operations was $2,836 million in 2007, an increase of $761 million from 2006. • Funds generated from operations were $2,621 million in 2007, an increase of $243 million from 2006, due primarily to increased earnings.

Investing Activities • TransCanada invested approximately $5.9 billion in its Pipelines and Energy businesses in 2007, comprised primarily of the following: • The Company completed the acquisition, in February 2007, of ANR and acquired an additional 3.6 per cent interest in Great Lakes for a total of US$3.4 billion, subject to certain post-closing adjustments, including US$491 million of assumed long-term debt. The additional interest in Great Lakes increased TransCanada’s direct ownership to 53.6 per cent. • PipeLines LP completed its acquisition in February 2007 of a 46.4 per cent interest in Great Lakes for US$942 million, subject to certain post-closing adjustments, including US$209 million of assumed long-term debt.

Financing Activities • TransCanada issued approximately $2.6 billion of Long-Term Debt, US$1.0 billion of Junior Subordinated Notes and approximately $1.9 billion of Common Shares in 2007, comprised primarily of: • TransCanada issued US$1.0 billion of Senior Unsecured Notes in October 2007. • The Company entered into an agreement in February 2007 for a US$1.0-billion committed five-year term and revolving credit facility. • PipeLines LP increased the size of its revolving credit and term loan to US$950 million from US$410 million in February 2007. • TransCanada issued US$1.0 billion of Junior Subordinated Notes in April 2007. • The issue of 45.4 million common shares at $38.00 each in first-quarter 2007, resulted in gross proceeds of approximately $1.7 billion. • In accordance with its Dividend Reinvestment and Share Purchase Plan (DRP), TransCanada issued 4.1 million common shares from treasury in 2007 in lieu of making cash dividend payments totalling $157 million. • PipeLines LP completed a private placement offering in February 2007 of 17.4 million common units at a price of US$34.57 per unit for gross proceeds of US$600 million. TransCanada acquired 50 per cent of the units for US$300 million and made an additional investment of approximately US$12 million to maintain its general partner interest, increasing its total ownership to 32.1 per cent from 13.4 per cent. • The Company redeemed US$460 million of preferred securities in July 2007. • The Company entered into an agreement in February 2007 for a US$2.2-billion one-year bridge loan facility.

Balance Sheet • Total assets increased by $4.4 billion to $30.3 billion in 2007 compared with 2006, due primarily to the ANR and Great Lakes acquisitions. • TransCanada’s Shareholders’ Equity increased by $2.1 billion to $9.8 billion in 2007 compared with the previous year. Attachment 1 CAPP 11 Page 17 of 142 MANAGEMENT’S DISCUSSION AND ANALYSIS 13

Dividend • On January 28, 2008, the Board of Directors of TransCanada increased the quarterly dividend on the Company’s outstanding common shares for the quarter ending March 31, 2008 by six per cent to $0.36 per share from $0.34 per share. This was the eighth consecutive annual increase in the common share dividend. Refer to ‘‘Results of Operations’’ below and to the ‘‘Liquidity and Capital Resources’’ section of this MD&A for further discussion of these highlights.

RESULTS OF OPERATIONS Net income was $1,223 million or $2.31 per share in 2007 compared to $1,079 million or $2.21 per share in 2006 and $1,209 million or $2.49 per share in 2005. Results in 2006 included net income from discontinued operations of $28 million or $0.06 per share, reflecting bankruptcy settlements with Mirant Corporation and certain of its subsidiaries (Mirant) related to their transactions with TransCanada’s Gas Marketing business. TransCanada divested its Gas Marketing business in 2001. Net earnings were $1,223 million or $2.31 per share in 2007 compared to $1,051 million or $2.15 per share in 2006 and $1,209 million or $2.49 per share in 2005. Net earnings in 2007 included $102 million of favourable income tax adjustments and an after-tax gain of $14 million on the sale of land. Net earnings in 2006 included $95 million of favourable income tax adjustments, an $18-million after-tax bankruptcy settlement with Mirant and an after-tax gain of $13 million from the sale of TransCanada’s general partner interest in Northern Border Partners, L.P. Net earnings of $1,209 million in 2005 included after-tax gains of $193 million on the sale of the Company’s interest in TransCanada Power, L.P. (Power LP), $115 million on the sale of the Company’s interest in P.T. Paiton Energy Company (Paiton Energy), $49 million on the sale of PipeLines LP units, and $13 million arising from a Canadian Mainline tolls settlement adjustment related to 2004 earnings. Excluding the above-noted items, comparable earnings for the years 2007, 2006 and 2005 were $1,107 million ($2.09 per share), $925 million ($1.90 per share) and $839 million ($1.72 per share), respectively. Comparable earnings in 2007 increased $182 million or $0.19 per share compared to 2006 due primarily to additional earnings from the acquisition of ANR in February 2007 and the first full year of earnings from the Becancour´ cogeneration plant and the Edson gas storage facility as well as positive impacts from rate case settlements for the GTN System and the Canadian Mainline. These increases were partially offset by a lower contribution by Bruce Power A L.P. (Bruce A) and Bruce Power L.P. (Bruce B) (collectively, Bruce Power) in 2007. Comparable earnings increased $86 million or $0.18 per share in 2006 compared to 2005. The increase was due primarily to significantly higher operating income from Western Power, Eastern Power and the Company’s investment in Bruce Power. The higher operating income was partially offset by decreased Pipelines results as net earnings from the Canadian Mainline and the Alberta System declined due to lower approved rates of return on common equity (ROE) and lower average investment bases in 2006. In addition, the Company’s Other Pipelines businesses and the GTN System and North Baja (collectively, GTN) experienced lower earnings in 2006. Results from each business segment are discussed further in the ‘‘Pipelines’’, ‘‘Energy’’ and ‘‘Corporate’’ sections of this MD&A.

FORWARD-LOOKING INFORMATION This MD&A may contain certain information that is forward-looking and is subject to important risks and uncertainties. The words ‘‘anticipate’’, ‘‘expect’’, ‘‘believe’’, ‘‘may’’, ‘‘should’’, ‘‘estimate’’, ‘‘project’’, ‘‘outlook’’, ‘‘forecast’’ or other similar words are used to identify such forward looking information. All forward-looking statements reflect TransCanada’s beliefs and assumptions based on information available at the time the statements were made. Actual results or events may differ from those predicted in these forward-looking statements. Factors that could cause actual results or events to differ materially from current expectations include, among other things, the ability of TransCanada to successfully implement its strategic initiatives and whether such strategic initiatives will yield the expected benefits, the operating performance of the Company’s pipeline and energy assets, the availability and price of energy Attachment 1 CAPP 11 Page 18 of 142 14 MANAGEMENT’S DISCUSSION AND ANALYSIS

commodities, regulatory processes and decisions, changes in environmental and other laws and regulations, competitive factors in the pipeline and energy industry sectors, construction and completion of capital projects, labour, equipment and material costs, access to capital markets, interest and currency exchange rates, technological developments and the current economic conditions in North America. By its nature, forward-looking information is subject to various risks and uncertainties, which could cause TransCanada’s actual results and experience to differ materially from the anticipated results or expectations expressed. Additional information on these and other factors is available in the reports filed by TransCanada with Canadian securities regulators and with the U.S. Securities and Exchange Commission (SEC). Readers are cautioned to not place undue reliance on this forward-looking information, which is given as of the date it is expressed in this MD&A or otherwise, and to not use future-oriented information or financial outlooks for anything other than their intended purpose. TransCanada undertakes no obligation to update publicly or revise any forward- looking information, whether as a result of new information, future events or otherwise, except as required by law.

NON-GAAP MEASURES TransCanada uses the measures ‘‘comparable earnings’’, ‘‘comparable earnings per share’’, ‘‘funds generated from operations’’ and ‘‘operating income’’ in this MD&A. These measures do not have any standardized meaning prescribed by GAAP. They are, therefore, considered to be non-GAAP measures and are unlikely to be comparable to similar measures presented by other entities. Management of TransCanada uses non-GAAP measures to increase its ability to compare financial results between reporting periods and to enhance its understanding of operating performance, liquidity and ability to generate funds to finance operations. Non-GAAP measures are also provided to readers as additional information on TransCanada’s operating performance, liquidity and ability to generate funds to finance operations. Comparable earnings comprise net earnings adjusted for specific items that are significant but not typical of the Company’s operations. Specific items are subjective, however, management uses its best judgement and informed decision-making when identifying items to be excluded in calculating comparable earnings. Specific items may include but are not limited to certain income tax refunds and adjustments, gains or losses on sales of assets, legal settlements, and bankruptcy settlements with former customers. The table in the ‘‘Segment Results-at-a-Glance’’ section of this MD&A presents a reconciliation of comparable earnings to net income. Comparable earnings per share is calculated by dividing comparable earnings by the weighted average number of shares outstanding for the period. Funds Generated from Operations comprises net cash provided by operations before changes in operating working capital. A reconciliation of funds generated from operations to net cash provided by operations is presented in the ‘‘Liquidity and Capital Resources’’ section of this MD&A. Operating Income is reported in the Company’s Energy business segment and comprises revenues less operating expenses as shown on the consolidated income statement. A reconciliation of operating income to net earnings is presented in the Energy section of this MD&A.

OUTLOOK The Company’s net earnings and cash flow, combined with a strong balance sheet, are expected to continue to provide the financial flexibility TransCanada will need in 2008 and beyond to complete its current capital expenditure program and continue to pursue opportunities and create additional long-term value for its shareholders. TransCanada views diligence and discipline as important elements of its strategy for long-term growth in its Pipelines and Energy businesses. In 2008, the Company will continue to implement its strategy and grow its Pipelines and Energy businesses as discussed in the ‘‘TransCanada’s Strategy’’ section of this MD&A. The Company’s results in 2008 may be affected positively or negatively by a number of factors and developments as discussed throughout this MD&A, including in the ‘‘Forward-Looking Information’’ section. Refer to the ‘‘Pipelines – Outlook’’, ‘‘Energy – Outlook’’ and ‘‘Corporate – Outlook’’ sections of this MD&A for further discussion regarding outlook. Attachment 1 CAPP 11 Page 19 of 142 MANAGEMENT’S DISCUSSION AND ANALYSIS 15

SEGMENT RESULTS-AT-A-GLANCE Reconciliation of Comparable Earnings to Net Income Year ended December 31 (millions of dollars except per share amounts) 2007 2006 2005 Pipelines Comparable earnings 686 529 617 Specific items: Bankruptcy settlement with Mirant – 18 – Gain on sale of Northern Border Partners, L.P. interest – 13 – Gain on sale of PipeLines LP units – – 49 Canadian Mainline NEB decision related to 2004 – – 13 Net earnings 686 560 679 Energy Comparable earnings 466 429 258 Specific items: Income tax reassessments and adjustments 34 23 – Gain on sale of land 14 –– Gain on sale of Power LP units – – 193 Gain on sale of Paiton Energy – – 115 Net earnings 514 452 566 Corporate Comparable expenses (45) (33) (36) Specific item: Income tax reassessments and adjustments 68 72 – Net earnings 23 39 (36) Net Income Continuing operations(1) 1,223 1,051 1,209 Discontinued operations – 28 – Net Income 1,223 1,079 1,209 Comparable Earnings(1) 1,107 925 839

Net Income per Share Continuing operations(2) $2.31 $2.15 $2.49 Discontinued operations – 0.06 – Basic $2.31 $2.21 $2.49 Comparable Earnings per Share(2) $2.09 $1.90 $1.72

(1)Comparable Earnings 1,107 925 839 Specific items (net of tax, where applicable): Income tax reassessments and adjustments 102 95 – Gain on sale of land 14 –– Bankruptcy settlement with Mirant – 18 – Gain on sale of Northern Border Partners, L.P. interest – 13 – Gain on sale of Power LP units – – 193 Gain on sale of Paiton Energy – – 115 Gain on sale of PipeLines LP units – –49 Canadian Mainline NEB decision related to 2004 13 Net Income from Continuing Operations 1,223 1,051 1,209 (2)Comparable Earnings Per Share $2.09 $1.90 $1.72 Specific items – per share: Income tax reassessments and adjustments 0.19 0.18 – Gain on sale of land 0.03 –– Bankruptcy settlement with Mirant – 0.04 – Gain on sale of Northern Border Partners, L.P. interest – 0.03 – Gain on sale of Power LP units – – 0.40 Gain on sale of Paiton Energy – – 0.24 Gain on sale of PipeLines LP units – – 0.10 Canadian Mainline NEB decision related to 2004 0.03 Net Income per Share from Continuing Operations $2.31 $2.15 $2.49 Attachment 1 CAPP 11 Page 20 of 142 16 MANAGEMENT’S DISCUSSION AND ANALYSIS

PIPELINES

Natural Gas Pipelines

1 Canadian Mainline 2 Alberta System 3 GTN System 4 Foothills 5 North Baja 16 15 6 Ventures LP 7 Tamazunchale 8 Tuscarora 9 Northern Border 2 6 10 Great Lakes 11 Iroquois 12 TQM 13 Portland 4 1 14 ANR 3 15 Alaska Highway Pipeline Project 12 13 (proposed by TransCanada) 10 16 Mackenzie Gas Pipeline Project 8 9 11 (proposed by producers) 18 17 14 Oil Pipeline

17 Keystone Pipeline Project 5 (under construction)

Natural Gas Storage 18 ANR Natural Gas Storage

Wholly owned Partially owned Under construction

Proposed 7

26FEB200822484073

CANADIAN MAINLINE Owned 100 per cent by TransCanada, the Canadian Mainline is a 14,957-km natural gas transmission system in Canada that extends from the Alberta/Saskatchewan border east to the Quebec/Vermont´ border and connects with other natural gas pipelines in Canada and the U.S. ALBERTA SYSTEM Owned 100 per cent by TransCanada, the Alberta System is a 23,570-km natural gas transmission system in Alberta. One of the largest transmission systems in North America, it gathers natural gas for use within the province and delivers it to provincial boundary points for connection with the Company’s Canadian Mainline and Foothills natural gas pipelines as well as the natural gas pipelines of other companies. ANR Owned 100 per cent by TransCanada, the 17,000-km ANR transmission system transports natural gas from producing fields located primarily in Texas and Oklahoma on its southwest leg and in the Gulf of Mexico and Louisiana on its southeast leg. The system extends to markets located mainly in Wisconsin, Michigan, Illinois, Ohio and Indiana. ANR’s natural gas pipeline also connects with other natural gas pipelines to give access to diverse sources of North American supply including Western Canada and the Rocky Mountain supply basin, and a variety of markets in the midwestern and northeastern U.S. ANR also owns and operates regulated underground natural gas storage facilities in Michigan with a total capacity of approximately 235 Bcf. Attachment 1 CAPP 11 Page 21 of 142 MANAGEMENT’S DISCUSSION AND ANALYSIS 17

GTN SYSTEM Owned 100 per cent by TransCanada, the GTN System is a 2,174-km natural gas transmission system that links Foothills with Pacific Gas and Electric Company’s California Gas Transmission System, with Williams Companies, Inc.’s Northwest Pipeline in Washington and Oregon, and with Tuscarora. FOOTHILLS Owned 100 per cent by TransCanada, the 1,241-km Foothills transmission system in Western Canada carries natural gas for export from central Alberta to the U.S. border to serve markets in the U.S. Midwest, Pacific Northwest, California and Nevada. TransCanada’s BC System was integrated into Foothills effective April 1, 2007. NORTH BAJA Owned 100 per cent by TransCanada, the North Baja natural gas transmission system extends 129 km from Ehrenberg in southwestern Arizona to a point near Ogilby, California on the California/Mexico border and connects with the Gasoducto Bajanorte natural gas pipeline system in Mexico. GREAT LAKES Owned 53.6 per cent by TransCanada and 46.4 per cent by PipeLines LP, the 3,404-km Great Lakes natural gas transmission system connects with the Canadian Mainline at Emerson, Manitoba, and serves markets in Central Canada and the midwestern U.S. TransCanada operates Great Lakes and effectively owns 68.5 per cent of the system through its 53.6 per cent direct ownership interest and its indirect ownership through its 32.1 per cent interest in PipeLines LP. NORTHERN BORDER Owned 50 per cent by PipeLines LP, the 2,250-km Northern Border natural gas transmission system serves the U.S. Midwest from a connection with Foothills near Monchy, Saskatchewan. TransCanada operates Northern Border and effectively owns 16.1 per cent of the system through its 32.1 per cent interest in PipeLines LP. TUSCARORA Owned 100 per cent by PipeLines LP, Tuscarora is a 491-km pipeline system transporting natural gas from the GTN System at Malin, Oregon, to Wadsworth, Nevada, with delivery points in northeastern California and northwestern Nevada. TransCanada operates Tuscarora and its 32.1 per cent interest in PipeLines LP gives TransCanada a 32.1 per cent ownership interest in the system. IROQUOIS Owned 44.5 per cent by TransCanada, the 666-km Iroquois pipeline system connects with the Canadian Mainline near Waddington, New York, and delivers natural gas to customers in the northeastern U.S. TRANSGAS Owned 46.5 per cent by TransCanada, TransGas is a 344-km natural gas pipeline system extending from Mariquita in the central region of Colombia to Cali in southwestern Colombia. PORTLAND Owned 61.7 per cent by TransCanada, Portland is a 474-km pipeline that connects with TQM near East Hereford, Quebec´ and delivers natural gas to customers in the northeastern U.S. Portland is operated by TransCanada. VENTURES LP Owned 100 per cent by TransCanada, Ventures LP has a 121-km pipeline and related facilities that supply natural gas to the oilsands region of northern Alberta as well as a 27-km pipeline that supplies natural gas to a petrochemical complex at Joffre, Alberta. TAMAZUNCHALE Owned 100 per cent by TransCanada, the 130-km Tamazunchale natural gas pipeline in east central Mexico extends from the facilities of Pemex Gas near Naranjos, Veracruz, to an electricity generating station near Tamazunchale, San Luis Potosi. Tamazunchale went into service on December 1, 2006. TQM Owned 50 per cent by TransCanada, TQM is a 572-km pipeline system that connects with the Canadian Mainline and transports natural gas from Montreal´ to Quebec´ City in Quebec,´ and connects with the Portland system. TQM is operated by TransCanada. GAS PACIFICO/INNERGY Owned 30 per cent by TransCanada, Gas Pacifico is a 540-km natural gas pipeline extending from Loma de la Lata, Argentina to Concepcion,´ Chile. TransCanada also has a 30 per cent ownership interest in INNERGY, an industrial natural gas marketing company based in Concepcion´ that markets natural gas transported on Gas Pacifico. KEYSTONE Owned 50 per cent by TransCanada, Keystone is a 3,456-km oil pipeline project under construction that is expected to transport crude oil from Hardisty, Alberta to U.S. midwest markets at Wood River and Patoka in Illinois, and to Cushing, Oklahoma. Attachment 1 CAPP 11 Page 22 of 142 18 MANAGEMENT’S DISCUSSION AND ANALYSIS

PIPELINES – HIGHLIGHTS

Net Earnings • Net earnings from Pipelines were $686 million in 2007, an increase of $126 million from $560 million in 2006. The growth was due primarily to the acquisitions of ANR and additional interest in Great Lakes, higher earnings as a result of the Canadian Mainline and GTN System rate settlements, and an increased ownership interest in PipeLines LP.

Expanding Asset Base • TransCanada expanded its North American natural gas pipeline and storage operations through its US$3.4-billion acquisitions of ANR and additional interest in Great Lakes in 2007. • At December 31, 2007, TransCanada has secured sufficient long-term contracts to underpin construction of the US$5.2-billion Keystone oil pipeline, including an extension to Cushing, Oklahoma, in which the Company holds a 50 per cent ownership interest. • TransCanada applied to the Alberta Energy and Utilities Board (EUB) in late 2007 for approval to further expand its Alberta System by adding 300 km of natural gas pipeline at an estimated total capital cost of $983 million. • TransCanada received approval from the EUB in 2007 to construct four new natural gas transmission facilities to serve the firm intra-Alberta delivery contract requirements of oilsands developers in the Fort McMurray, Alberta area. The capital cost of the four pipeline facilities, which total 150 km, together with a 15-MW compression facility, is expected to be $367 million.

Canadian Mainline • The National Energy Board (NEB) approved a negotiated five-year settlement of Canadian Mainline tolls, which included a deemed common equity ratio of 40 per cent and certain performance-based and operating, maintenance and administration (OM&A) cost-saving incentive arrangements.

Alberta System • The Alberta System operated under the terms of the 2005-2007 Revenue Requirement Settlement in 2007 and is currently negotiating a settlement with stakeholders for 2008.

GTN System • The Federal Energy Regulatory Commission (FERC) approved in January 2008 the GTN System’s uncontested rate case settlement. Under the settlement, the GTN System’s rates increased by approximately 27 per cent, effective January 1, 2007.

Foothills • After receiving NEB approval, the BC System was integrated into Foothills effective April 1, 2007.

Other Pipelines • TransCanada acquired approximately eight million units of PipeLines LP in February 2007, increasing the Company’s ownership interest to 32.1 per cent. Through its increased ownership interest in PipeLines LP, TransCanada increased its effective ownership in Great Lakes to 68.5 per cent. Attachment 1 CAPP 11 Page 23 of 142 MANAGEMENT’S DISCUSSION AND ANALYSIS 19

PIPELINES RESULTS-AT-A-GLANCE Year ended December 31 (millions of dollars) 2007 2006 2005 Wholly Owned Pipelines Canadian Mainline 273 239 270 Alberta System 138 136 150 ANR(1) 104 GTN 58 46 71 Foothills(2) 26 27 27 599 448 518

Other Pipelines Great Lakes(3) 47 44 46 PipeLines LP(4) 18 49 Iroquois 15 15 17 TransGas 15 11 11 Portland 11 13 11 Ventures LP 11 12 12 Tamazunchale(5) 10 2 TQM 6 77 Gas Pacifico/INNERGY(6) 3 86 Northern Development (7) (5) (4) General, administrative, support costs and other (42) (30) (16) 87 81 99 Comparable earnings(7) 686 529 617 Bankruptcy settlement with Mirant – 18 – Gain on sale of Northern Border Partners, L.P. interest – 13 – Gain on sale of PipeLines LP units – – 49 Canadian Mainline NEB decision related to 2004 – – 13 Net earnings 686 560 679

(1) ANR was acquired February 22, 2007. (2) Foothills’ results reflect the combined operations of Foothills and the BC System. (3) Great Lakes’ results reflect TransCanada’s 53.6 per cent ownership in Great Lakes since February 22, 2007, and 50 per cent ownership prior to this date. (4) PipeLines LP’s results include a 46.4 per cent ownership interest in Great Lakes since February 22, 2007, as well as an additional 20 per cent ownership of Northern Border since April 6, 2006, and an additional 49 per cent ownership of Tuscarora since December 19, 2006. PipeLines LP’s results also reflect TransCanada’s 32.1 per cent ownership since February 22, 2007. (5) Tamazunchale’s results include operations since December 1, 2006. (6) INNERGY Holdings S.A. (7) Refer to the ‘‘Non-GAAP Measures’’ section of this MD&A for further discussion of comparable earnings.

Net earnings from the Pipelines business were $686 million in 2007 compared to $560 million in 2006 and $679 million in 2005. Net earnings in 2006 included the $18-million bankruptcy settlement with Mirant and the $13-million gain on sale of TransCanada’s general partner interest in Northern Border Partners, L.P. Net earnings in 2005 included the $49-million gain on sale of PipeLines LP units. Net earnings in 2005 also included a $13-million positive Attachment 1 CAPP 11 Page 24 of 142 20 MANAGEMENT’S DISCUSSION AND ANALYSIS

adjustment related to 2004 as a result of the NEB’s decision in 2005 to increase the deemed common equity ratio to 36 per cent from 33 per cent under the Canadian Mainline’s 2004 Tolls and Tariff Application (Phase II). Comparable earnings from the Pipelines business were $686 million in 2007, an increase of $157 million compared to $529 million in 2006. The increase was due primarily to the acquisitions of ANR and additional interest in Great Lakes, higher earnings as a result of the Canadian Mainline and GTN System rate settlements and an increased ownership in PipeLines LP. Comparable earnings decreased $88 million to $529 million in 2006 compared to $617 million in 2005. The decline was due primarily to lower net earnings from the Canadian Mainline, the Alberta System, GTN and Other Pipelines.

PIPELINES – FINANCIAL ANALYSIS

Canadian Mainline The Canadian Mainline is regulated by the NEB. The NEB sets tolls that provide TransCanada with the opportunity to recover its projected costs of transporting natural gas, including a return on the Canadian Mainline’s average investment base. The NEB also approves new facilities before their construction begins. Net earnings of the Canadian Mainline are affected by changes in the investment base, the ROE, the level of deemed common equity and potential incentive earnings. In February 2007, TransCanada reached a five-year tolls settlement effective January 1, 2007 to December 31, 2011 on the Canadian Mainline. In May 2007, the NEB approved TransCanada’s application of the settlement as filed, including TransCanada’s request that interim tolls be made final for 2007. As part of the settlement, it was agreed that the cost of capital reflect an ROE on a deemed common equity ratio of 40 per cent, an increase from 36 per cent, as determined under the NEB’s ROE formula. The remaining capital structure will consist of short- and long-term debt, following the agreed upon redemption of the US$460 million 8.25 per cent Preferred Securities that were included in the Canadian Mainline’s capital structure. The settlement also established certain elements of the Canadian Mainline’s fixed OM&A costs for each year of the settlement. The variance between actual and agreed upon OM&A costs will accrue to TransCanada from 2007 to 2009, and will be shared equally between TransCanada and its customers in 2010 and 2011. The settlement also allows for performance-based incentive arrangements that will provide mutual benefits to both TransCanada and its customers. Net earnings of $273 million in 2007 were $34 million higher than 2006 net earnings of $239 million. The increase primarily reflected the positive impact of the increase in deemed common equity ratio in the Canadian Mainline tolls settlement, performance-based incentive arrangements and OM&A cost savings, partially offset by a lower allowed ROE of 8.46 per cent in 2007 (8.88 per cent in 2006), as determined under the NEB’s formula, and a lower average investment base. Canadian Mainline generated comparable earnings of $239 million in 2006, a decrease of $31 million from 2005. The decrease was due primarily to a combination of a lower allowed ROE and a lower average investment base in 2006

Canadian Mainline Canadian Mainline Canadian Mainline Canadian Mainline Net Earnings Average Throughput Capital Expenditures (millions of dollars) Investment Base Volumes (Bcf) (millions of dollars) 283 273 (millions of dollars) 185 239 7,807 3,183 7,459 7,292 2,997 2,955

98

49

2005 2006 2007 2005 2006 2007 2005 2006 2007 200515FEB2008210158952006 2007 Attachment 1 CAPP 11 Page 25 of 142 MANAGEMENT’S DISCUSSION AND ANALYSIS 21

compared to 2005. Comparable earnings in 2005 excluded the $13-million positive adjustment from the NEB decision related to 2004. TransCanada reached a tolls settlement with its Canadian Mainline customers and other interested parties that included an NEB-allowed ROE of 8.88 per cent for 2006, which was determined under the NEB’s return adjustment formula on a deemed common equity ratio of 36 per cent. The NEB-allowed ROE for 2005 was 9.46 per cent.

Alberta System The EUB was reorganized into the Energy Resources Conservation Board and the Alberta Utilities Commission (AUC) effective January 1, 2008. The AUC regulates construction and operation of facilities and the terms and conditions of services, including rates, for the Alberta System, primarily under the provisions of the Gas Utilities Act and the Pipeline Act. The Alberta System has been operating for the past three years under the 2005-2007 Revenue Requirement Settlement. The settlement addresses all elements of the Alberta System including OM&A costs, ROE, depreciation and income and municipal taxes. The settlement fixed OM&A costs at $207 million for 2007, $201 million for 2006, and $193 million for 2005. In each year, any variance between actual OM&A and other fixed costs and those agreed to in the settlement accrued to TransCanada. The majority of other cost elements of the 2005, 2006 and 2007 revenue requirements are treated on a flow-through basis. Alberta System net earnings of $138 million in 2007 were $2 million higher than in 2006. The increase was due primarily to OM&A cost savings, partially offset by a lower allowed ROE and a lower investment base in 2007. The allowed ROE prescribed by the EUB was 8.51 per cent in 2007 compared with 8.93 per cent in 2006 on deemed common equity of 35 per cent. Net earnings of $136 million in 2006 were $14 million lower than in 2005. The decrease was due primarily to a lower investment base and a lower allowed ROE in 2006. The allowed ROE prescribed by the EUB was 9.50 per cent in 2005 on deemed common equity of 35 per cent.

Alberta System Alberta System Alberta System Alberta System Net Earnings Average Throughput Capital (millions of dollars) Investment Base Volumes (Bcf) Expenditures (millions of dollars) (millions of dollars) 225 225 4,446 4,287 4,224 4,051 150 3,999 4,020 136 138

75

2005 2006 2007 2005 2006 2007 2005 2006 2007 27FEB2008085138272005 2006 2007

ANR TransCanada completed the acquisition of ANR on February 22, 2007 and included its net earnings from this date. The operations of ANR are regulated primarily by the FERC. ANR provides natural gas transportation, storage and various capacity-related services to a variety of customers in both the U.S. and Canada. The transmission system has a peak-day capacity of 6.8 Bcf/d. ANR also owns and operates numerous underground natural gas storage facilities in Michigan. ANR’s FERC-regulated natural gas storage and transportation services operate under current FERC-approved tariff rates. These tariffs include maximum and minimum rate levels for services and permit ANR to discount or negotiate rates on a non-discriminatory basis. ANR Pipeline’s rates were established pursuant to a settlement approved by a FERC order issued in February 1998 and the settlement rates became effective November 1, 1997. ANR Storage Company’s rates were established pursuant to a settlement approved by the FERC in April 1990 and these settlement rates became effective June 1, 1990. None of ANR’s FERC-regulated operations are required to file for new rates at any time in the future, nor are any of the operations prohibited from filing a rate case. ANR’s revenues are derived primarily from its interstate natural gas transmission and storage, gathering and related services. Due to the seasonal nature of the Attachment 1 CAPP 11 Page 26 of 142 22 MANAGEMENT’S DISCUSSION AND ANALYSIS

business, ANR’s volumes, revenues and net earnings are generally expected to be higher in the winter months. ANR’s net earnings were $104 million from the date of its acquisition by TransCanada on February 22, 2007, to December 31, 2007 and were in line with the Company’s expectations.

GTN The FERC regulates GTN. Both of GTN’s systems, the GTN System and North Baja, are subject to FERC-approved tariffs that establish maximum and minimum rates for various services. The systems are permitted to discount or negotiate these rates on a non-discriminatory basis. On October 31, 2007, the GTN System filed a Stipulation and Agreement with the FERC that comprises an uncontested settlement of all aspects of its 2006 General Rate Case. The settlement rates went into effect on an interim basis on November 1, 2007, in accordance with the FERC’s Order dated November 16, 2007. The FERC approved the settlement on January 7, 2008, with settlement rates effective January 1, 2007. GTN’s financial results in 2007 reflect the terms of the settlement. The net earnings of GTN are affected by variations in contracted volume levels, volumes delivered and prices charged under the various service types that are provided, as well as by variations in the costs of providing services. GTN’s comparable earnings increased $12 million in 2007, compared to 2006 due primarily to the positive impact of the rate case settlement, partially offset by lower long-term firm contracted volumes and a weaker U.S. dollar in 2007. In addition, comparable earnings in 2007 were negatively affected by a higher provision taken in 2007 for non-payment of contract revenues from a subsidiary of Calpine Corporation (Calpine) that filed for bankruptcy protection. Net earnings were $46 million in 2006, a $25-million decrease from 2005. This decrease was due primarily to lower transportation revenues, higher operating costs, the impact of the weaker U.S. dollar and the provision for non-payment of contract revenues from the Calpine subsidiary.

Other Pipelines TransCanada’s direct and indirect investments in various natural gas pipelines and its project development activities relating to natural gas and oil transmission opportunities throughout North America are included in Other Pipelines. TransCanada’s comparable earnings from Other Pipelines were $87 million in 2007 compared to $81 million in 2006. The increase was due primarily to higher earnings in PipeLines LP, which were affected positively by TransCanada’s increased ownership interests in PipeLines LP and Great Lakes, and Tamazunchale, which completed its first full year of operations in 2007. These increases were partially offset by higher project development and support costs associated with growing the Pipelines business, the effects of the weaker U.S. dollar in 2007, and proceeds of a bankruptcy settlement received by Portland in 2006. Comparable earnings from Other Pipelines were $81 million in 2006, $18 million lower than in 2005. The decrease was due primarily to higher project development and support costs associated with growing the Pipelines business, reduced ownership in PipeLines LP, the effects of the weaker U.S. dollar, and proceeds of bankruptcy settlements received by Iroquois in 2005. These decreases were partially offset by higher net earnings from Portland due to the proceeds it received in 2006 from the bankruptcy settlement.

PIPELINES – OPPORTUNITIES AND DEVELOPMENTS

Keystone Keystone is expected to extend 3,456 km and is designed to deliver 590,000 Bbl/d of crude oil from Hardisty, Alberta, to U.S. Midwest markets at Wood River and Patoka in Illinois, and to Cushing, Oklahoma. The Company has currently secured long-term contracts for a total of 495,000 Bbl/d with an average duration of 18 years. Deliveries to Patoka are expected to begin in late 2009. TransCanada and Keystone Canada received regulatory approval from the NEB in 2007 to transfer a portion of TransCanada’s Canadian Mainline natural gas transmission facilities to Keystone Canada, and to construct and operate new oil pipeline facilities in Canada. Keystone Canada filed an application with the NEB in November 2007 to add new Attachment 1 CAPP 11 Page 27 of 142 MANAGEMENT’S DISCUSSION AND ANALYSIS 23

pumping facilities to accommodate the increase in scope and scale of the project. An NEB oral hearing is scheduled to commence in April 2008. Keystone U.S. received, from the U.S. Department of State in January 2008, the Final Environmental Impact Statement (FEIS) regarding construction of the Keystone U.S. pipeline and its Cushing extension. The FEIS stated the pipeline would result in limited adverse environmental impacts. The FEIS is a requirement to proceed with the Presidential Permit process, which governs the construction and operation of facilities at the U.S.-Canada border crossing. The Presidential Permit is expected to be issued in March 2008. ConocoPhillips contributed $207 million to acquire a 50 per cent ownership interest in Keystone in December 2007. Affiliates of TransCanada will be responsible for constructing and operating Keystone, which is expected to have a capital cost of approximately US$5.2 billion.

Canadian Mainline In July 2007, the NEB approved TransCanada’s request to add a new LNG receipt point at Gros Cacouna, Quebec,´ as well as its request to calculate tolls for service from this point on a rolled-in basis. The approvals will be effective on the date the facilities required to connect the Gros Cacouna receipt point are placed in service. On November 29, 2007, the NEB announced that, pursuant to its formula, the 2008 allowed ROE for NEB-regulated pipelines, including the Canadian Mainline, will be 8.71 per cent, up from 8.46 per cent in 2007.

Alberta System TransCanada received approval from the EUB in July 2007 to initiate negotiations on the Alberta System revenue requirement with the intent of reaching a settlement for a term of up to three years commencing January 1, 2008. Settlement negotiations with stakeholders are progressing. TransCanada has a requirement to file a 2008 General Rate application or a settlement in first-quarter 2008. On November 30, 2007 the EUB finalized the Alberta System’s 2008 allowed ROE at 8.75 per cent, compared to 8.51 per cent in 2007. TransCanada received approval from the EUB in 2007 to construct four new natural gas transmission facilities to serve the firm intra-Alberta delivery contract requirements of oilsands developers in the Fort McMurray, Alberta area. The capital cost of the four pipeline facilities, which total 150 km, together with a 15-MW compression facility are expected to be $367 million. TransCanada submitted an application to the EUB in November 2007 for a permit to construct the North Central Corridor expansion, which comprises a 300-km natural gas pipeline and associated facilities on the northern section of the Alberta System. The expansion, if approved, will connect the northwest portion of the Alberta System with the northeast portion of the system. The estimated capital cost of this expansion is $983 million. The project is expected to be completed in two stages, the first one beginning in late 2008 with an in-service date of April 1, 2009 and the second one with an in-service date of April 1, 2010.

ANR As of December 31, 2007, ANR substantially completed a project that increased its saleable natural gas storage capacity by 13 Bcf, of which 10 Bcf was previously used for system operations. Construction has commenced on a second storage enhancement project, which is expected to increase ANR’s natural gas storage capacity by 14 Bcf in 2008. ANR is considering an additional storage expansion project, which, along with the utilization of other natural gas pipeline assets across TransCanada’s system, is intended to allow customers to access additional storage and markets. ANR is also pursuing potential additions of supply on both its southwest and southeast legs. Supply on the southwest leg was increased in early 2008 as a result of an interconnect with the Rockies Express natural gas pipeline, which commenced service in January 2008. There is potential for new supply on the southeast leg from LNG additions, shale gas from the mid-continent, and a potential additional interconnect with the Rockies Express pipeline. Attachment 1 CAPP 11 Page 28 of 142 24 MANAGEMENT’S DISCUSSION AND ANALYSIS

GTN In August 2007, Gas Transmission Northwest Corporation (GTNC), a wholly owned subsidiary of TransCanada, and Northwest Natural Gas Company (NW Natural) formed an equally owned joint venture, Palomar Gas Transmission LLC (Palomar), to develop a 354-km (220 mile) natural gas pipeline to serve the Oregon, Pacific Northwest and Western U.S markets. The proposed Palomar pipeline would connect TransCanada’s existing GTN System in central Oregon with NW Natural’s distribution system near Molalla, Oregon, and could be extended to a proposed pipeline near the town of Wauna, Oregon. The Palomar pipeline is in the preliminary stages of the FERC permitting process.

North Baja North Baja received a FERC expansion certificate in October 2007 authorizing modifications that would allow it to import natural gas from the Costa Azul LNG terminal in northwestern Mexico, which is nearing completion. The imported gas would serve markets in California and the U.S. Southwest. The FERC certificate authorizes phased expansion of North Baja. The first phase of the expansion includes system modifications to allow for bi-directional natural gas flow and the addition of a lateral natural gas pipeline to interconnect with a Southern California Gas Co. pipeline near Blythe, California. The first phase will also give North Baja the ability to import approximately 600 million cubic feet per day (mmcf/d) of natural gas from Mexico.

Foothills TransCanada’s BC System was integrated into Foothills in 2007. In first quarter 2007, the NEB approved the transfer of assets and finalized the revised tolls for 2007. Foothills will continue to be regulated on a complaint basis only.

Tamazunchale The Company’s Tamazunchale natural gas pipeline in Mexico is designed to transport initial volumes of 170 mmcf/d. The pipeline’s capacity is expected to be expanded to approximately 430 mmcf/d, to meet the needs of two additional proposed power plants near Tamazunchale. The timing of the expansion will be driven by the Comision´ Federal de Electricidad’s requirements for the power plants.

Mackenzie Gas Pipeline Project The MGP is a proposed 1,200-km natural gas pipeline to be constructed from a point near Inuvik, Northwest Territories to the northern border of Alberta, where it is expected to connect to the Alberta System. TransCanada’s involvement with the MGP arises from a 2003 agreement between the Mackenzie Valley Aboriginal Pipeline Group (APG) and the MGP, whereby TransCanada agreed to finance the APG’s one-third share of the pre-development costs associated with the project. Cumulative advances made by TransCanada in this respect totalled $137 million at December 31, 2007 and are included in Other Assets. These amounts constitute a loan to the APG, which becomes repayable only after the pipeline commences commercial operations. The total amount of the loan is expected to form part of the rate base of the pipeline and subsequently be repaid from the APG’s share of future natural gas pipeline revenues or from alternate financing. If the project does not proceed, TransCanada has no recourse against the APG for recovery of advances made. Accordingly, TransCanada’s ability to recover its investment is dependant upon a successful outcome of the project. Under the terms of certain MGP agreements, TransCanada holds an option to acquire up to a five per cent equity ownership in the natural gas pipeline at the time of the decision to construct. In addition, TransCanada gains certain rights of first refusal to acquire 50 per cent of any divestitures by existing partners and an entitlement to obtain a one-third interest in all expansion opportunities once the APG reaches a one-third ownership share, with the other natural gas pipeline owners and the APG sharing the balance. TransCanada and the other co-venture companies involved in the MGP continue to pursue approval of the proposed project, focusing on the regulatory process and discussions with the Canadian government on fiscal framework. Project timing is uncertain and is conditional upon resolution of regulatory and fiscal matters. Attachment 1 CAPP 11 Page 29 of 142 MANAGEMENT’S DISCUSSION AND ANALYSIS 25

Alaska Pipeline Project TransCanada continued its discussions with Alaska North Slope producers and the State of Alaska in 2007 to advance the proposed Alaska Pipeline Project. TransCanada submitted an application in November 2007 for a license to construct the Alaska Pipeline Project under the Alaska Gasline Inducement Act (AGIA). The State of Alaska announced on January 4, 2008, that TransCanada had submitted a complete AGIA application and would be advancing to the Public Comment stage. No other applicant met all the AGIA requirements. If approved by the Alaska Administration and the Alaska Legislature, TransCanada could be granted the AGIA license by mid-2008. Upon receipt of the AGIA license, TransCanada will proceed with an open season to secure shipping commitments from shippers. Foothills holds the priority right to build, own and operate the first natural gas pipeline through Canada for the transportation of Alaskan gas. This right was granted under the Northern Pipeline Act of Canada (NPA) following a lengthy competition hearing before the NEB in the late 1970s, which produced a decision in favour of Foothills. The NPA creates a single-window regulatory regime that is uniquely available to Foothills. It has been used by Foothills to construct facilities in Alberta, British Columbia (B.C.) and Saskatchewan that constitute a pre-build for the Alaska Pipeline Project, and to expand these facilities five times, the latest of which was in 1998. Continued development of the Alaska Pipeline Project under the NPA is expected to ensure the earliest in-service date for the project.

PIPELINES – BUSINESS RISKS

Supply, Markets and Competition TransCanada faces competition at both the supply and market ends of its systems. This competition comes from other natural gas pipelines accessing the increasingly mature WCSB and markets served by TransCanada’s pipelines. In addition, the continued expiration of long-term firm transportation (FT) contracts has resulted in significant reductions in long-term firm contracted capacity and shifts to short-term firm contracts on the Canadian Mainline, the Alberta System, Foothills and the GTN System. TransCanada’s primary source of natural gas supply is the WCSB. As of December 2006, the WCSB had remaining discovered natural gas reserves of approximately 57 trillion cubic feet and a reserves-to-production ratio of approximately nine years at current levels of production. Historically, sufficient additional reserves have been discovered on an ongoing basis to maintain the reserves-to-production ratio at close to nine years. However, gas supply is expected to decline due to a continued reduction in levels of drilling activity in the WCSB. The reduced drilling activity is a result of lower prices, higher supply costs, which include higher royalties, and the stronger Canadian dollar. TransCanada anticipates there will be excess natural gas pipeline capacity out of the WCSB in the foreseeable future as a result of capacity expansion on its wholly owned and partially owned natural gas pipelines over the past decade, competition from other pipelines, and significant growth in natural gas demand in Alberta driven by oilsands and electricity generation requirements. TransCanada’s Alberta System is the major natural gas gathering and transportation system for the WCSB, connecting most of the natural gas processing plants in Alberta to domestic and export markets. Despite reduced overall drilling levels, activity remains robust in certain areas of the WCSB, which has resulted in the need for new transmission infrastructure. The primary areas of high activity have been deeper conventional drilling in western Alberta and in the foothills region of B.C., and coalbed methane development in central Alberta. The Alberta System has faced, and will continue to face, increasing competition from other natural gas pipelines. An emerging competitive issue for the Alberta System is the existence and access to natural gas liquids (NGL) contained in the natural gas transported by the pipeline system. In 2007, the EUB began a proceeding in relation to NGL extraction matters. The outcome of this proceeding may affect the way in which regulated natural gas pipelines compete within Alberta. Historically, TransCanada’s eastern natural gas pipeline system has been supplied by long-haul flows from the WCSB and by short-haul volumes received from storage fields and interconnecting pipelines in southwestern Ontario. Over the last few years, the Canadian Mainline has experienced reductions in long-haul flows, which have been partially offset by Attachment 1 CAPP 11 Page 30 of 142 26 MANAGEMENT’S DISCUSSION AND ANALYSIS

increases in short-haul volumes. This reflects the combined impact of new U.S. Midwest-to-Ontario pipeline capacity and lower supply available for export from the WCSB region. Demand for natural gas in TransCanada’s key eastern markets, which are served by the Canadian Mainline, is expected to continue to increase, particularly to meet the expected growth in natural gas-fired power generation. Although there are opportunities to increase market share in Canadian and U.S. export markets, TransCanada faces significant competition in these regions. Consumers in the northeastern U.S. generally have access to an array of natural gas pipeline and supply options. Eastern markets that historically received Canadian supplies only from TransCanada are now capable of receiving supplies from new natural gas pipelines that can source U.S. and Western and Atlantic Canadian supplies. ANR’s primary natural gas supply is sourced from the Gulf of Mexico and mid-continent U.S. regions, which are served by competing natural gas pipelines. ANR also has competition from other natural gas pipelines in its primary markets in the U.S. Midwest. The Gulf of Mexico region is extremely competitive given its extensive natural gas pipeline network. ANR is one of many interstate and intrastate pipelines in the region competing for new and existing production as well as for new supplies from LNG, from shale production in the mid-continent, and from the Rockies Express natural gas pipeline originating in the Rocky Mountain region. Several new natural gas pipelines are proposed or under construction to connect new supplies to the numerous pipelines in the Gulf of Mexico region. ANR competes with other natural gas pipelines in the region to attract supply to its pipeline for alternative markets and storage. The most recent changes in ANR’s market region are the FERC-approved expansions of two competing pipelines, which will provide approximately 500 mmcf/d of incremental capacity into the Wisconsin market and approximately 200 mmcf/d of incremental capacity into the market extending from Chicago, Illinois, to Dawn, Ontario. The expanded transportation capacity competes directly with alternatives provided by ANR and Great Lakes, while incremental storage connections provide competitive alternatives to ANR’s storage in Michigan. The GTN System must compete with other pipelines to access natural gas supplies and markets. Transportation service capacity on the GTN System provides customers in the U.S. Pacific Northwest, California and Nevada with access to supplies of natural gas primarily from the WCSB. These three markets may also access supplies from other basins. In the Pacific Northwest market, natural gas transported on the GTN System competes with the Rocky Mountain natural gas supply and with additional western Canadian supply transported by other natural gas pipelines. Historically, natural gas supplies from the WCSB have been competitively priced in relation to supplies from the other regions serving these markets. The GTN System experienced significant contract non-renewals in 2005 and 2006 as natural gas transported from the WCSB on the GTN System competed for the California and Nevada markets against supplies from the Rocky Mountain and southwestern U.S. supply basins. Recently, Pacific Gas and Electric Company, the GTN System’s largest customer, filed an application with the California Public Utilities Commission (CPUC) requesting approval to commit to capacity on a proposed project out of the Rocky Mountain basin to the California border. This project has not yet been filed with the FERC and TransCanada is protesting the application filed with the CPUC.

Regulatory Financial Risk Regulatory decisions continue to have a significant impact on the financial returns from existing investments in TransCanada’s Canadian wholly owned pipelines and are expected to have a similarly significant impact on financial returns from future investments. TransCanada remains concerned that financial returns approved by regulators could potentially fail to be competitive with returns from assets with similar risk profiles. In recent years, TransCanada applied to the NEB and the EUB for an ROE of 11 per cent on 40 per cent deemed common equity for both the Canadian Mainline and the Alberta System, respectively. The NEB has reaffirmed its ROE formula and the EUB has established a generic ROE, which largely aligns with the NEB formula. Through rate applications and negotiated settlements, TransCanada has been able to improve the common equity components of its Canadian Mainline and Alberta System capital structures to the current 40 per cent and 35 per cent respectively. TQM filed an application with the NEB in December 2007 requesting a fair return on capital, consisting of an ROE of 11 per cent on 40 per cent deemed common equity. The outcome of this proceeding may influence the regulators’ view of fair financial returns on equity associated with TransCanada’s other Canadian wholly owned pipelines. Attachment 1 CAPP 11 Page 31 of 142 MANAGEMENT’S DISCUSSION AND ANALYSIS 27

Throughput Risk As transportation contracts expire, TransCanada’s U.S. natural gas pipelines are expected to be more exposed to the risk of reduced throughput and their revenues more likely to experience increased variability. Throughput risk is created by supply and market competition, gas basin pricing, economic activity, weather variability, natural gas pipeline competition and pricing of alternative fuels.

Execution and Capital Cost Risk The construction of Keystone is subject to execution and capital cost risks, which is subject to a capital cost risk- and reward-sharing mechanism with its customers. Refer to the ‘‘Risk Management and Financial Instruments’’ section of this MD&A for information on managing risks in the Pipelines business.

PIPELINES – OUTLOOK

Demand for natural gas and crude oil is expected to continue to grow across North America in 2008. TransCanada’s Pipelines business will continue to focus on the delivery of natural gas to growing markets, connecting new supply, progressing development of new infrastructure to connect natural gas from the north and unconventional supplies such as coalbed methane and LNG, and development of the Keystone oil pipeline. TransCanada expects producers will continue to explore and develop new fields in Western Canada, particularly in northeastern B.C. and the west central foothills regions of Alberta. There is also expected to be significant activity aimed at unconventional resources such as coalbed methane, which will be further incented starting in 2009 due to the new royalty structure in Alberta benefiting lower productivity wells. Most of TransCanada’s current expansion plans in Canadian natural gas transmission are focused on the Alberta System. New facilities are expected to be needed to expand the integrated Alberta System to reflect changes in the distribution of supply and market within Alberta, connect new discrete supply sources, as well as new delivery points, primarily in the Alberta oilsands region and the central Alberta industrial heartland. In the U.S., TransCanada expects unconventional production will continue to be developed from the coalbed methane and tight gas sands of the Rocky Mountain region, as well as from shale plays in east Texas, southwestern Oklahoma and Arkansas. In addition, incremental supplies are anticipated from LNG imports into the U.S. Significant infrastructure is being built in the U.S. to accommodate these supply sources. The resulting growth in supply from LNG and the unconventional supply sources is likely to offer additional commercial opportunities for TransCanada. In particular, the southwest leg of ANR is expected to continue to remain fully subscribed for the foreseeable future, and new transport routes are being developed to move additional Rocky Mountain production to midwestern and eastern U.S. markets, including interconnections with ANR. The southeast leg of ANR has the capacity to transport additional volumes of LNG and mid-continent shale production as these supplies develop. Producers continue to develop new oil supply in the WCSB. In 2008, there are several new oilsands projects that will begin production, along with growth at existing projects. Oilsands production is expected to grow from 1.2 million Bbl/d in 2007 to 3.0 million Bbl/d in 2015, while total WCSB oil supply is projected to grow from 2.5 million Bbl/d to 3.9 million Bbl/d over the same period. The primary market for this new oilsands production is the U.S., extending from the U.S. Midwest to the Gulf of Mexico region, which contains a number of very large refineries, well equipped to handle Canadian heavy crude oil blends. WCSB crude oil is expected to replace declining U.S. imports of heavy crude oil from other countries. This increase in WCSB crude oil exports requires new pipeline capacity, including Keystone, and further expansions to the Gulf of Mexico. TransCanada will continue to pursue additional opportunities to move crude oil from the Alberta oilsands to U.S. markets. Attachment 1 CAPP 11 Page 32 of 142 28 MANAGEMENT’S DISCUSSION AND ANALYSIS

TransCanada will continue to focus on operational excellence and on collaborative efforts with all stakeholders to achieve negotiated settlements and service options that will increase the value of the Company’s business to customers and shareholders.

Earnings The Company expects continued growth on its Alberta System. The Company anticipates a modest level of investment in its other existing Canadian natural gas pipelines, resulting in an expected continued net decline in the average investment base due to annual depreciation. A net decline in the average investment base has the effect of reducing year-over-year earnings from these assets. However, this impact will be partially mitigated in 2008 by a slight increase in the formula-based regulated ROEs. Additionally, a settlement resulting from the current negotiations on the Alberta System may provide the opportunity for additional earnings contribution in 2008. Under the current regulatory model, earnings from Canadian pipelines are not affected by short-term fluctuations in the commodity price of natural gas, changes in throughput volumes or changes in contract levels. Reduced FT contract volumes due to customer defaults, reduced supply available for export from the WCSB and expiry of long-term contracts could have a negative impact on short-term earnings from TransCanada’s U.S. natural gas pipelines, unless the available capacity can be recontracted. The ability to recontract available capacity is influenced by prevailing market conditions and competitive factors including competing natural gas pipelines and supply from other natural gas sources in markets served by TransCanada’s U.S. pipelines. Earnings from Pipelines’ foreign operations are impacted by changes in foreign currency exchange rates. Pipelines’ earnings in 2008 are expected to be positively impacted by a full year of operations from ANR and the additional interests in Great Lakes. Certain subsidiaries of Calpine filed for bankruptcy protection in both Canada and the U.S. in 2005. Portland and GTNC have reached agreements with Calpine for allowed unsecured claims of US$125 million and US$192.5 million, respectively, in the Calpine bankruptcy. Creditors will receive shares in the re-organized Calpine and these shares will be subject to market price fluctuations as the new Calpine shares begin to trade. In February 2008, Portland and GTNC received initial distributions of 6.1 million shares and 9.4 million shares, respectively, which are expected to result in a significant increase in TransCanada’s net earnings in first-quarter 2008. Claims by NOVA Gas Transmission Limited and Foothills Pipe Lines (South B.C.) Ltd. for $31.6 million and $44.4 million, respectively, were received in cash in January 2008 and will be passed on to shippers on these systems.

Capital Expenditures Excluding the cost of acquiring ANR and additional interests in Great Lakes, total capital spending for the wholly owned pipelines in 2007 was $487 million. Capital spending for the wholly owned pipelines in 2008 is expected to be approximately $1.0 billion. In addition, capital spending for TransCanada’s 50 per cent share of constructing the Keystone pipeline is expected to be approximately $800 million. Attachment 1 CAPP 11 Page 33 of 142 MANAGEMENT’S DISCUSSION AND ANALYSIS 29

NATURAL GAS THROUGHPUT VOLUMES (Bcf) 2007 2006 2005 Canadian Mainline(1) 3,183 2,955 2,997 Alberta System(2) 4,015 4,051 3,999 ANR(3) 1,210 GTN System 827 790 777 Foothills(4) 1,441 1,403 1,372 North Baja 90 95 84 Great Lakes 829 816 850 Northern Border 800 799 808 Iroquois 394 384 394 TQM 207 158 166 Ventures LP 178 179 138 Gas Pacifico 71 52 34 Portland 58 52 62 Tamazunchale(5) 29 – Tuscarora 28 28 25 TransGas 24 22 19

(1) Canadian Mainline deliveries originating at the Alberta border and in Saskatchewan in 2007 were 2,199 Bcf (2006 – 2,224 Bcf; 2005 – 2,215 Bcf). (2) Field receipt volumes for the Alberta System in 2007 were 4,047 Bcf (2006 – 4,160 Bcf, 2005 – 4,034 Bcf). (3) ANR was acquired February 22, 2007 and its volumes are included from this date. (4) Foothills volumes reflects the combined operations of Foothills and the BC System. (5) Tamazunchale’s results include volumes since December 1, 2006. Attachment 1 CAPP 11 Page 34 of 142 30 MANAGEMENT’S DISCUSSION AND ANALYSIS

ENERGY

Power Generation

1 Bear Creek 2 MacKay River 3 Redwater 4 Sundance A PPA 5 Sundance B PPA (50% ownership) 6 Sheerness PPA 7 Carseland 8 Cancarb 2 1 9 Bruce Power 18 3 (Bruce A – 48.7%, Bruce B – 31.6%) 4 5 19 10 6 Halton Hills (under construction) 7 11 Portlands Energy (under construction) 8 13 12 Bécancour 20 14 13 Cartier Wind 12 15 (62% ownership, under construction) 11 9 10 16 14 Grandview 17 15 Kibby Wind (proposed) 21 16 TC Hydro 17 OSP

Gas Storage

18 Edson 19 CrossAlta

Liquefied Natural Gas

20 Cacouna (proposed by TransCanada and Petro-Canada)

21 Broadwater (proposed by TransCanada and Shell US Gas & Power LLC)

26FEB200822483893

BEAR CREEK An 80-MW natural gas-fired cogeneration plant, Bear Creek is located near Grande Prairie, Alberta. MACKAY RIVER A 165-MW natural gas-fired cogeneration plant, MacKay River is located near Fort McMurray, Alberta. REDWATER A 40-MW natural gas-fired cogeneration plant, Redwater is located near Redwater, Alberta. SUNDANCE A&B The largest coal-fired electric power generating facility in Western Canada, Sundance is located in south-central Alberta. TransCanada has the rights to 100 per cent of the generating capacity of the 560-MW Sundance A facility under a power purchase arrangement (PPA), which expires in 2017. TransCanada also has the rights to 50 per cent of the generating capacity of the 706-MW Sundance B facility under a PPA, which expires in 2020. SHEERNESS Consisting of two 390-MW coal-fired thermal power generating units, the Sheerness plant is located in southeastern Alberta. TransCanada has the rights to 756 MW of generating capacity from the Sheerness PPA, which expires in 2020. Attachment 1 CAPP 11 Page 35 of 142 MANAGEMENT’S DISCUSSION AND ANALYSIS 31

CARSELAND An 80-MW natural gas-fired cogeneration plant, Carseland is located near Carseland, Alberta. CANCARB A 27-MW facility fuelled by waste heat from TransCanada’s adjacent thermal carbon black facility, Cancarb is located in Medicine Hat, Alberta. BRUCE POWER Consisting of two generating stations, Bruce A with approximately 3,000 MW of generating capacity and Bruce B with approximately 3,200 MW of generating capacity, Bruce Power is located in Ontario. TransCanada owns 48.7 per cent of Bruce A, which has four power generating units, two of which have been idled for refurbishing and are expected to restart in 2010. TransCanada owns 31.6 per cent of Bruce B, which also has four power generating units. HALTON HILLS A 683-MW natural gas-fired power plant, Halton Hills is under construction near the town of Halton Hills, Ontario, and is expected to be in service in third-quarter 2010. PORTLANDS ENERGY A 550-MW high-efficiency, combined-cycle natural gas generation power plant, Portlands Energy is under construction near downtown Toronto, Ontario. The plant is 50 per cent owned by TransCanada and is expected to be operational in simple-cycle mode, delivering 340 MW of electricity to the City of Toronto, beginning in June 2008. It is expected to be fully commissioned in its combined-cycle mode, delivering 550 MW of power, in second-quarter 2009. BECANCOUR´ A 550-MW natural gas-fired cogeneration power plant, Becancour´ is located near Trois-Rivieres,` Quebec.´ The entire power output is supplied to Hydro-Quebec´ under a 20-year power purchase contract. Steam is also sold to an industrial customer for use in commercial processes. CARTIER WIND The 740-MW Cartier wind farm project consists of six wind power projects located in Quebec.´ Cartier Wind is 62 per cent owned by TransCanada. Baie-des-Sables, with a generation capacity of 110 MW, and Anse-a-´ Valleau, with a generation capacity of 101 MW, were placed into service in November 2006 and November 2007, respectively. Construction of a third project, the 110-MW Carleton wind farm, began in late 2007. Planning and construction of the remaining three projects will continue, subject to future approvals. GRANDVIEW A 90-MW natural gas-fired cogeneration power plant, Grandview is located in Saint John, New Brunswick. Irving Oil Limited receives 100 per cent of the plant’s heat and electricity output under a 20-year tolling agreement. KIBBY WIND A 132-MW wind power project, the proposed Kibby Wind includes 44 turbines located in Kibby and Skinner Townships in northwestern Franklin County, Maine. Subject to U.S. federal and state approvals, construction could begin in early 2008 and the new facilities could go into service in 2009–2010. TC HYDRO With a total generating capacity of 583 MW, TC Hydro comprises 13 hydroelectric facilities, including stations and associated dams and reservoirs, on the Connecticut and Deerfield rivers in New Hampshire, Vermont and Massachusetts. OSP A 560-MW natural gas-fired, combined-cycle facility, OSP is located in Rhode Island. EDSON An underground natural gas storage facility, Edson is connected to the Alberta System near Edson, Alberta. The facility’s central processing system is capable of maximum injection and withdrawal rates of 725 mmcf/d of natural gas. Edson has a working natural gas storage capacity of approximately 50 Bcf. CROSSALTA An underground natural gas storage facility, CrossAlta is connected to the Alberta System and is located near Crossfield, Alberta. TransCanada owns 60 per cent of CrossAlta, which has a working natural gas capacity of 54 Bcf with a maximum deliverability capability of 480 mmcf/d. CACOUNA A proposed LNG project at Gros Cacouna Harbour on the St. Lawrence River in Quebec,´ Cacouna would be capable of receiving, storing and regasifying imported LNG with an average send-out capacity of approximately 500 mmcf/d of natural gas. TransCanada has a 50 per cent ownership interest in Cacouna. BROADWATER A proposed offshore LNG project located in the New York waters of Long Island Sound, Broadwater would be capable of receiving, storing and regasifying imported LNG with an average send-out capacity of approximately 1 Bcf/d of natural gas. TransCanada has a 50 per cent ownership interest in Broadwater. Attachment 1 CAPP 11 Page 36 of 142 32 MANAGEMENT’S DISCUSSION AND ANALYSIS

ENERGY – HIGHLIGHTS

Net Earnings • Energy’s net earnings were $514 million in 2007, an increase of $62 million from $452 million in 2006. • Energy’s comparable earnings were $466 million in 2007, up $37 million from $429 million in 2006. Comparable earnings excluded positive income tax adjustments in 2007 and 2006 and a gain on sale of land in 2007, and increased primarily due to higher operating income from Eastern Power and Natural Gas Storage. • Results in 2007 included the first full year of earnings from the Becancour´ cogeneration plant, the Baie-des-Sables Cartier Wind project, and the Edson natural gas storage facility.

Expanding Asset Base • Approximately 2,000 MW of additional generation capacity was under construction at December 31, 2007, with an anticipated capital cost of more than $4.2 billion. • Since 1999, TransCanada’s Energy business has grown its nominal generating capacity by approximately 5,300 MW, excluding 2,000 MW currently under construction, representing an investment of more than $5 billion to the end of 2007. • The Anse-a-Valleau´ Cartier Wind project was completed and placed into service in November 2007. • Construction continued in 2007 on the Bruce A refurbishment and restart project, which includes restart of the currently idle power generating Units 1 and 2, and replacement of the steam generators and installation of new fuel channels on Units 3 and 4.

Plant Availability • Weighted average power plant availability was 91 per cent in 2007, which was consistent with 2006. • Weighted average power plant availability, excluding Bruce, was 93 per cent in 2007, which was consistent with 2006.

ENERGY RESULTS-AT-A-GLANCE Year ended December 31 (millions of dollars) 2007 2006 2005 Western Power 308 297 123 Eastern Power 255 187 137 Bruce Power 167 235 195 Natural Gas Storage 146 93 32 Power LP Investment – –29 General, administrative, support costs and other (158) (144) (129) Operating income 718 668 387 Financial charges (22) (23) (11) Interest income and other 10 5 5 Income taxes (240) (221) (123) Comparable earnings(1) 466 429 258 Income tax adjustments 34 23 – Gain on sale of land 14 –– Gain on sale of Paiton Energy – – 193 Gain on sale of Power LP units – – 115 Net earnings 514 452 566

(1) Refer to the ‘‘Non-GAAP Measures’’ section of this MD&A for further discussion of comparable earnings. Attachment 1 CAPP 11 Page 37 of 142 MANAGEMENT’S DISCUSSION AND ANALYSIS 33

Energy Net Earnings Power Sales Energy’s net earnings in 2007 were $514 million compared to $452 million (millions of dollars) Volumes (GWh) in 2006. Comparable earnings were $466 million in 2007, an increase of $37 million from 2006. Comparable earnings exclude the $14-million gain 566 43,818 514 37,984 on sale of land and the $34-million favourable income tax adjustments in 308 452 30,009 2007 as well as the $23-million favourable impact in 2006 from future income taxes as a result of reductions in Canadian federal and provincial

258 corporate income tax rates. The increase was due primarily to higher operating income in Eastern Power, Natural Gas Storage and Western Power, partially offset by a reduced contribution from Bruce Power. 2005 2006 2007 2005 2006 2007 Energy’s net earnings in 2006 were $452 million compared to $566 million Gains related to Power LP and Paiton Energy18FEB200819383515 in 2005. The decrease was due primarily to the inclusion in 2005 net earnings of gains related to the disposal of TransCanada’s investments in Paiton Energy and Power LP. In 2005, TransCanada sold its interest of approximately 11 per cent in Paiton Energy resulting in an after-tax gain of $115 million and sold its ownership interest in Power LP resulting in an after-tax gain of $193 million. Energy’s comparable earnings, which exclude the $23-million favourable impact on future income taxes in 2006 and the Power LP and Paiton Energy gains in 2005, were $429 million in 2006, an increase of $171 million from $258 million in 2005. The increase was due primarily to higher contributions from each of Energy’s existing businesses, including a full year of earnings from TC Hydro, partially offset by the loss of operating income associated with the sale of the Power LP interest in 2005.

POWER PLANTS – NOMINAL GENERATING CAPACITY AND FUEL TYPE MW Fuel Type Western Power Sheerness(1) 756 Coal Sundance A(2) 560 Coal Sundance B(2) 353 Coal MacKay River 165 Natural gas Carseland 80 Natural gas Bear Creek 80 Natural gas Redwater 40 Natural gas Cancarb 27 Natural gas 2,061

Eastern Power Halton Hills(3) 683 Natural gas TC Hydro(4) 583 Hydro OSP 560 Natural gas Becancour´ (5) 550 Natural gas Cartier Wind(6) 458 Wind Portlands Energy(7) 275 Natural gas Grandview(8) 90 Natural gas 3,199 Bruce Power(9) 2,474 Nuclear Total nominal generating capacity 7,734 Attachment 1 CAPP 11 Page 38 of 142 34 MANAGEMENT’S DISCUSSION AND ANALYSIS

(1) TransCanada has sole access to 756 MW from Sheerness through a long-term PPA lease. (2) TransCanada directly or indirectly has the rights to 560 MW from Sundance A and 353 MW from Sundance B through long-term PPAs, which represents 100 per cent of the Sundance A and 50 per cent of the Sundance B power plant output. (3) Currently under construction. (4) Acquired in second-quarter 2005. (5) Placed in service in third-quarter 2006. (6) Represents TransCanada’s 62 per cent share of the total 740-MW project. Two of six wind farms were placed in service, one in November 2006 and the other in November 2007, with a combined generating capacity of 211 MW. (7) Represents TransCanada’s 50 per cent share of this 550-MW facility, which is currently under construction. (8) Placed in service in first-quarter 2005. (9) Represents TransCanada’s 48.7 per cent proportionate interest in Bruce A and 31.6 per cent proportionate interest in Bruce B. Bruce A consists of four 750-MW reactors, two of which are currently being refurbished and are expected to restart in 2010. Bruce B consists of four reactors, which are currently in operation and have a combined capacity of approximately 3,200 MW.

ENERGY – FINANCIAL ANALYSIS

Western Power As at December 31, 2007, Western Power owns or has the rights to approximately 2,100 MW of power supply in Alberta from its three long-term PPAs and five natural gas-fired cogeneration facilities. The power supply portfolio of Western Power comprises approximately 1,700 MW of low-cost, base-load coal-fired generation supply through the three long-term PPAs and approximately 400 MW of natural gas-fired cogeneration assets. This supply portfolio is among the lowest-cost, most competitive generation in the Alberta market area. On December 31, 2005, $585 million was paid to the Alberta Balancing Pool for the remaining rights of the Sheerness PPA, which has a remaining term of approximately 13 years. The Sundance A and B PPAs have remaining terms of 10 years and 13 years, respectively. Western Power relies on its two integrated functions, marketing and plant operations, to generate earnings. The marketing function, based in Calgary, Alberta, purchases and resells electricity sourced from the PPAs, markets uncommitted volumes from the cogeneration facilities, and purchases and resells power and gas to maximize the value of the cogeneration facilities. The marketing function is integral to optimizing Energy’s return from its portfolio of power supply and to managing risks associated with uncontracted volumes. A portion of its power is sold into the spot market for operational reasons and the amount of supply volumes eventually sold into the spot market is dependent upon the ability to transact in forward sales markets at acceptable contract terms. This approach to portfolio management helps to minimize costs in situations where TransCanada would otherwise have to purchase electricity in the open market to fulfil its contractual sales obligations. To reduce its exposure to spot market prices on uncontracted volumes, Western Power had, as at December 31, 2007, fixed-price power sales contracts to sell approximately 9,200 gigawatt hours (GWh) in 2008 and 6,800 GWh in 2009. Plant operations consist of five natural gas-fired cogeneration power plants located in Alberta with an approximate combined output capacity of 400 MW ranging from 27 MW to 165 MW per facility. A portion of the expected output is sold under long-term contracts and the remaining output is subject to fluctuations in the price of power and gas. Market heat rate is an economic measure for natural gas-fired power plants and is determined by dividing the average price of power per megawatt hour (MWh) by the average price of natural gas per gigajoule (GJ) for a given period. To the extent power is not sold under long-term contracts and plant fuel gas has not been purchased under long-term contracts, the profitability of a natural gas-fired generating facility rises in proportion to increases in the market heat rate, and, conversely, declines in proportion to decreases in the market heat rate. Market heat rates in Alberta decreased in 2007 by approximately 16 per cent as a result of a decrease in average power prices, while spot market natural gas prices remained relatively unchanged. Market heat rates averaged approximately 11.4 GJ/MWh in 2007 compared to approximately 13.5 GJ/MWh in 2006. Attachment 1 CAPP 11 Page 39 of 142 MANAGEMENT’S DISCUSSION AND ANALYSIS 35

All plants in Western Power operated with an average plant availability of approximately 90 per cent in 2007 compared to 88 per cent in 2006.

Western Power Results-at-a-Glance Year ended December 31 (millions of dollars) 2007 2006 2005 Revenues Power 1,045 1,185 715 Other(1) 89 169 158 1,134 1,354 873 Commodity purchases resold Power (608) (767) (476) Other(2) (65) (135) (104) (673) (902) (580) Plant operating costs and other (135) (135) (149) Depreciation (18) (20) (21) Operating income 308 297 123

(1) Includes natural gas sold and Cancarb Thermax, the thermal carbon black facility adjacent to Cancarb. (2) Includes the cost of natural gas sold.

Western Power Sales Volumes Year ended December 31 (GWh) 2007 2006 2005 Supply Generation 2,154 2,259 2,245 Purchased Sundance A & B and Sheerness PPAs 12,199 12,712 6,974 Other purchases 1,433 1,905 2,687 15,786 16,876 11,906

Contracted vs. Spot Contracted 11,998 12,750 10,374 Spot 3,788 4,126 1,532 15,786 16,876 11,906

Operating income was $308 million in 2007, an increase of $11 million from $297 million in 2006. The increase was due primarily to lower PPA costs, partially offset by slightly lower overall realized power prices. Revenues decreased in 2007 compared to 2006 due mainly to the lower overall power sales prices realized in 2007 as well as lower volumes purchased and generated. Commodity purchases resold decreased in 2007 compared to 2006 due primarily to lower PPA costs, a decrease in volumes purchased and the expiry of certain retail contracts. Purchased power volumes in 2007 decreased compared to 2006 mainly as a result of an increase in outage hours at the Sundance A facility and the expiry Attachment 1 CAPP 11 Page 40 of 142 36 MANAGEMENT’S DISCUSSION AND ANALYSIS

of certain retail contracts. Approximately 24 per cent of power sales volumes were sold in to the spot market in 2007, which was consistent with 2006. Operating income was $297 million in 2006, an increase of $174 million from $123 million in 2005. The increase was due primarily to incremental earnings from the acquisition of the Sheerness PPA on December 31, 2005, and increased margins from a combination of higher overall realized power prices and higher market heat rates on uncontracted volumes of power sold. Revenues and commodity purchases resold increased in 2006 compared to 2005 due mainly to the acquisition of the Sheerness PPA as well as higher realized power prices. Plant operating costs and other, which includes fuel gas consumed in power generation, decreased due to lower natural gas prices. Purchased power volumes in 2006 increased compared to 2005 due primarily to the acquisition of the Sheerness PPA. Approximately 24 per cent of power sales volumes were sold into the spot market in 2006 compared to 13 per cent in 2005.

Eastern Power Eastern Power owns approximately 3,200 MW of power generation capacity, including facilities under construction or in the development phase. Eastern Power’s current operating power generation assets are TC Hydro, Ocean State Power (OSP), Becancour´ and Grandview, and the Baie-des-Sables and Anse-a-Valleau´ wind farms. The TC Hydro assets include 13 hydroelectric stations housing 39 hydroelectric generating units in New Hampshire, Vermont and Massachusetts. Eastern Power conducts its business primarily in the deregulated New England power market and in Eastern Canada. In the New England market, TransCanada has established a successful marketing operation through its wholly owned subsidiary, TransCanada Power Marketing Ltd. (TCPM), located in Westborough, Massachusetts. To reduce exposure to spot market prices on uncontracted volumes, Eastern Power had, as at December 31, 2007, fixed price sales contracts to sell forward approximately 8,200 GWh in 2008 and 9,900 GWh in 2009. Fixed price sales contracts in 2008 exclude approximately 4,200 GWh of generation from the Becancour´ power plant as a result of the request from Hydro-Quebec´ to suspend electricity generation, beginning January 1, 2008. TCPM focuses on selling power under short- and long-term contracts to wholesale, commercial and industrial customers while managing a portfolio of power supplies sourced from both its own generation and wholesale power purchases. In 2007, TCPM continued to expand its marketing presence and customer base. In June 2006, the FERC approved a settlement agreement to implement a newly-designed Forward Capacity Market (FCM) for power generation in the New England power markets. The FCM design is intended to promote investment in new and existing power resources needed to meet growing consumer demand and maintain a reliable power system. The settlement agreement provides for a multi-year transition period beginning in December 2006 and ending in May 2010, whereby fixed payments ranging from US$3.05 to US$4.10 per kilowatt-month, will be made to owners of existing installed capacity. Eastern Power’s OSP plant and TC Hydro generation facilities are eligible to receive payments during the transition period. Under the new FCM design, Independent System Operator New England will project the needs of the power system three years in advance, following which it will hold an annual auction to purchase power resources to satisfy a region’s future needs. Suppliers will receive payments pursuant to the FCM auction mechanism commencing June 1, 2010. Attachment 1 CAPP 11 Page 41 of 142 MANAGEMENT’S DISCUSSION AND ANALYSIS 37

Eastern Power Results-at-a-Glance(1) Year ended December 31 (millions of dollars) 2007 2006 2005 Revenues Power 1,481 789 505 Other(2) 239 292 412 1,720 1,081 917 Commodity purchases resold Power (755) (379) (215) Other(2) (208) (257) (373) (963) (636) (588) Plant operating costs and other (454) (226) (167) Depreciation (48) (32) (25) Operating income 255 187 137

(1) Includes Becancour,´ Baie-des-Sables and Anse-a-Valleau,` effective September 17, 2006, November 21, 2006 and November 10, 2007, respectively. (2) Other includes natural gas sales and purchases.

Eastern Power Sales Volumes(1) Year ended December 31 (GWh) 2007 2006 2005 Supply Generation 8,095 4,700 2,879 Purchased 6,986 3,091 2,627 15,081 7,791 5,506

Contracted vs. Spot Contracted 14,505 7,374 4,919 Spot 576 417 587 15,081 7,791 5,506

(1) Includes Becancour,´ Baie-des-Sables and Anse-a-Valleau,` effective September 17, 2006, November 21, 2006 and November 10, 2007, respectively.

Operating income was $255 million in 2007, $68 million higher than the $187 million earned in 2006. The increase was due primarily to incremental income from the first full year of operation of the Becancour´ facility and the Baie-des-Sables wind farm, and from the start-up of the Anse-a-Valleau` wind farm in November 2007. Also contributing to the increase were payments received under the start-up of the FCM in New England and higher sales volumes to commercial and industrial customers in 2007. Partially offsetting these increases was the impact of reduced water flows from the TC Hydro generation assets in 2007, compared to the above-average water flows experienced in 2006 following higher precipitation in the surrounding area. Eastern Power’s revenues from power were $1,481 million in 2007, an increase of $692 million from $789 million in 2006. The substantial growth was driven primarily by the first full year of revenue from the Becancour´ facility and the Attachment 1 CAPP 11 Page 42 of 142 38 MANAGEMENT’S DISCUSSION AND ANALYSIS

Baie-des-Sables wind farm, which went into service in September and November 2006, respectively, as well as by increased sales volumes to commercial and industrial customers, and higher realized prices. Other revenue and other commodity purchases resold decreased year-over-year as a result of a reduction in the quantity of natural gas purchased and resold under OSP’s natural gas supply contracts. Power commodity purchases resold and purchased power volumes were higher in 2007 due to the impact of increased purchases to supply higher sales volumes to wholesale, commercial and industrial customers. The increase in purchased power volumes was partially offset by additional power generation from the OSP plant, which reduced the requirement to purchase power to fulfill contractual sales obligations. Plant operating costs and other, which includes fuel gas consumed in generation, were higher in 2007 due primarily to the full year of operations of the Becancour´ facility and increased power generation from the OSP plant. Operating income was $187 million in 2006, an increase of $50 million from $137 million earned in 2005. The increase was due mainly to incremental income from the full year of ownership of the TC Hydro assets, the start-up of the Becancour´ facility, a $10-million after-tax one-time restructuring payment in first-quarter 2005 from OSP to its natural gas fuel suppliers, and higher overall margins on power sales volumes in 2006.

Bruce Power In 2005, Bruce Power and the Ontario Power Authority (OPA) completed a long-term agreement whereby Bruce A committed to refurbish and restart the currently idle Units 1 and 2, extend the operating life of Unit 3 by replacing its steam generators and fuel channels when required, and replace the steam generators on Unit 4. An amendment to this agreement in 2007 is described further in the ‘‘Energy – Opportunities and Developments’’ section of this MD&A. As a result of an agreement between Bruce Power and the OPA, and Cameco Corporation’s (Cameco) decision not to participate in the refurbishment and restart program, the Bruce A partnership was formed by TransCanada and BPC Generation Infrastructure Trust (BPC), with each owning a 48.7 per cent interest in Bruce A at December 31, 2007 (2006 – 48.7 per cent; 2005 – 47.9 per cent). TransCanada and BPC each incurred a net cash outlay of approximately $100 million in 2005 to acquire Cameco’s interest. The remaining 2.6 per cent interest in Bruce A is owned by BPC, a trust established by the Ontario Municipal Employees Retirement System, the Power Worker’s Union and The Society of Energy Professionals. The Bruce A partnership subleases Bruce A Units 1 to 4 from Bruce B. TransCanada continues to own 31.6 per cent of Bruce B, which consists of Units 5 to 8. Upon reorganization, both Bruce A and Bruce B became jointly controlled entities and TransCanada proportionately consolidated these investments on a prospective basis from October 31, 2005. The following Bruce Power financial results reflect the operations of six of the eight Bruce Power units in all periods. Attachment 1 CAPP 11 Page 43 of 142 MANAGEMENT’S DISCUSSION AND ANALYSIS 39

Bruce Power Results-at-a-Glance Year ended December 31 (millions of dollars) 2007 2006 2005 Bruce Power (100 per cent basis) Revenues Power 1,920 1,861 1,907 Other(1) 113 71 35 2,033 1,932 1,942 Operating expenses Operations and maintenance(2) (1,051) (912) (871) Fuel (104) (96) (77) Supplemental rent(2) (170) (170) (164) Depreciation and amortization (151) (134) (198) (1,476) (1,312) (1,310) Revenues, net of operating expenses 557 620 632 Financial charges under equity accounting(3) – – (58) 557 620 574 TransCanada’s proportionate share – Bruce A 24 91 22 TransCanada’s proportionate share – Bruce B 161 137 166 TransCanada’s proportionate share 185 228 188 Adjustments (18) 77 TransCanada’s operating income from Bruce Power(3) 167 235 195 Bruce Power – Other Information Plant availability Bruce A 78% 81% 94% Bruce B 89% 91% 79% Combined Bruce Power 86% 88% 80% Planned outage days Bruce A 121 81 106 Bruce B 93 65 153 Unplanned outage days Bruce A 17 37 30 Bruce B 32 31 104 Sales volumes (GWh) Bruce A – 100 per cent 10,180 10,650 2,100 Bruce A – TransCanada’s proportionate share 4,959 5,158 999 Bruce B – 100 per cent 25,290 25,820 30,800 Bruce B – TransCanada’s proportionate share 7,992 8,159 9,733 Combined Bruce Power – 100 per cent 35,470 36,470 32,900 TransCanada’s proportionate share 12,951 13,317 10,732 Results per MWh Bruce A power revenues $59 $58 $57 Bruce B power revenues $52 $48 $58 Combined Bruce Power revenues $55 $51 $58 Combined Bruce Power fuel $3 $3 $2 Combined Bruce Power total operating expenses(4) $41 $35 $40 Percentage of output sold to spot market 45% 35% 49% Attachment 1 CAPP 11 Page 44 of 142 40 MANAGEMENT’S DISCUSSION AND ANALYSIS

(1) Includes fuel cost recoveries of $35 million for Bruce A in 2007 (2006 – $30 million; November 1 to December 31, 2005 – $4 million). Includes changes in fair value of held-for-trading derivatives of $47 million in 2007 (2006 – nil; 2005 – nil). (2) Includes adjustments to eliminate the effects of inter-partnership transactions between Bruce A and Bruce B. (3) TransCanada’s consolidated equity income in 2005 includes $168 million which represents TransCanada’s 31.6 per cent share of Bruce Power earnings for the ten months ended October 31, 2005. (4) Net of fuel cost recoveries.

TransCanada’s operating income from its investment in Bruce Power was $167 million in 2007 compared to $235 million in 2006. TransCanada’s proportionate share of operating income in Bruce B increased $24 million to $161 million in 2007 compared with 2006 due primarily to higher realized power prices, partially offset by higher operating costs associated with an increase in planned outage days in 2007. TransCanada’s proportionate share of operating income in Bruce A decreased $67 million to $24 million in 2007 compared with 2006 due primarily to lower output and higher operating costs associated with an increase in planned outage days in 2007. Higher post-employment benefit costs and lower positive purchase price amortizations related to the expiry of power sales agreements also contributed to the decrease in TransCanada’s operating income from its combined investment in Bruce power in 2007 compared to 2006. Combined Bruce Power prices (excluding other revenues) were $55 per MWh in 2007 compared to $51 per MWh in 2006, reflecting higher prices on both contracted volumes and uncontracted volumes sold into the spot market. Bruce Power’s combined operating expenses (net of fuel cost recoveries) increased to $41 per MWh in 2007 from $35 per MWh in 2006 due primarily to higher operating costs and decreased output in 2007. The Bruce units ran at a combined average availability of 86 per cent in 2007, compared to an 88 per cent average availability in 2006. The lower availability in 2007 was the result of more planned maintenance outage days, partially offset by fewer unplanned outage days in 2007. TransCanada’s operating income from its combined investment in Bruce Power was $235 million in 2006 compared to $195 million in 2005. The increase of $40 million was due primarily to an increased ownership interest in the Bruce A facilities and higher sales volumes resulting from increased plant availability, partially offset by lower overall realized prices. Adjustments to TransCanada’s combined interest in Bruce Power’s income before income taxes were lower in 2007 than in 2006 and 2005 due primarily to lower positive purchase price amortizations related to the expiry of power sales agreements. Income from Bruce B is directly affected by fluctuations in wholesale spot market prices for electricity. Income from both Bruce A and Bruce B is affected by overall plant availability, which in turn is affected by planned and unplanned maintenance. As a result of a contract with the OPA, all of the output from Bruce A is sold at a fixed price per MWh, adjusted for inflation annually on April 1, and before recovery of fuel costs from the OPA. Per the 2007 amendment of the contract with the OPA, discussed in the ‘‘Energy – Opportunities and Developments’’ section, effective April 1, 2008, the fixed price for output from Bruce A will also increase by $2.11 per MWh, subject to inflation adjustments from October 31, 2005.

per MWh April 1, 2007 – March 31, 2008 $59.69 April 1, 2006 – March 31, 2007 $58.63 October 31, 2005 – March 31, 2006 $57.37 Payments received pursuant to the fixed-price contract are capped at $575 million for the period ending on the commercial in-service date of the later of the restarted Unit 1 and Unit 2. Post-refurbishment prices will also be adjusted for capital cost variances associated with the refurbishment and restart projects. Attachment 1 CAPP 11 Page 45 of 142 MANAGEMENT’S DISCUSSION AND ANALYSIS 41

As part of this contract, sales from the Bruce B Units 5 to 8 are subject to a floor price adjusted annually for inflation on April 1. per MWh April 1, 2007 – March 31, 2008 $46.82 April 1, 2006 – March 31, 2007 $45.99 October 31, 2005 – March 31, 2006 $45.00

Payments received pursuant to the Bruce B floor price mechanism may be subject to a recapture payment dependent on annual spot prices over the term of the contract. Bruce B net earnings to date do not include any amounts received pursuant to this floor mechanism. To further reduce its exposure to spot market prices, Bruce B entered into fixed price sales contracts as at December 31, 2007, to sell forward approximately 10,200 GWh in 2008 and 4,900 GWh in 2009. The overall plant availability percentage in 2008 is expected to be in the low 90s for the four Bruce B units and the low 80s for the two operating Bruce A units. A planned maintenance outage of Bruce B Unit 7 began at the end of January 2008 and the unit is expected to be back in service in March 2008. A planned maintenance outage of Bruce B Unit 5 is scheduled to begin in early May 2008 and the unit is expected to return to service in late second-quarter 2008. A one-month maintenance outage of Bruce A Unit 4 is scheduled to start in late March 2008 and a two-month outage of Bruce A Unit 3 is expected to commence mid-September 2008. The Bruce partners have agreed that all excess cash from both Bruce A and Bruce B will be distributed on a monthly basis and that separate cash calls will be made for major capital projects, including the Bruce A refurbishment and restart project. Power LP Divestiture TransCanada sold all of its interest in Power LP to EPCOR Utilities Inc. in August 2005 for net proceeds of $523 million, resulting in an after-tax gain of $193 million. TransCanada’s investment in Power LP generated operating income of $29 million in 2005. Plant Availability Power Plant Availability Weighted average power plant availability for all plants, excluding Bruce Power, was 93 per cent in (excluding Bruce Power) (per cent) 2007 and 2006, compared to 87 per cent in 2005. Plant availability represents the percentage of time in a year that the plant is available to generate power whether actually running or not, 93 93 87 reduced by planned and unplanned outages. Western Power’s plant availability was affected negatively in 2006 and 2005 by an unplanned outage at Bear Creek, which returned to service in August 2006. A planned outage was taken in 2005 at the MacKay River facility, further decreasing Western Power’s plant availability in 2005. Eastern Power achieved plant availability of 96 per cent in 2007, which was consistent with 2006. Availability was lower in 2005 as a result of OSP 200512FEB2008150731852006 2007 experiencing two significant outages.

Weighted Average Plant Availability(1) Year ended December 31 2007 2006 2005 Western Power(2) 90% 88% 85% Eastern Power(3) 96% 95% 83% Bruce Power 86% 88% 80% Power LP investment(4) – – 94% All plants, excluding Bruce Power investment 93% 93% 87% All plants 91% 91% 84%

(1) Plant availability represents the percentage of time in a year that the plant is available to generate power, whether actually running or not, reduced by planned and unplanned outages. Attachment 1 CAPP 11 Page 46 of 142 42 MANAGEMENT’S DISCUSSION AND ANALYSIS

(2) The Sheerness PPA is included in Western Power, effective December 31, 2005. (3) TC Hydro, Becancour,´ Baie-des-Sables and Anse-a-Valleau´ are included in Eastern Power effective April 1, 2005, September 17, 2006, November 21, 2006 and November 10, 2007, respectively. (4) Power LP is included to August 31, 2005. Natural Gas Storage TransCanada became one of the largest natural gas storage providers in Western Canada when the Edson storage facility was placed in service on December 31, 2006, with a final commissioning date of April 1, 2007. TransCanada owns or has rights to 120 Bcf of natural gas storage capacity in Alberta, including a 60 per cent ownership interest in CrossAlta Gas Storage & Services Ltd. (CrossAlta), an independently operated storage facility. TransCanada also has contracts for long-term, Alberta-based storage capacity from a third party, which expire in 2030 and include mutual early termination rights in 2015.

Natural Gas Storage Capacity Working Gas Maximum Injection/ Storage Capacity Withdrawal Capacity (Bcf) (mmcf/d) Edson 50 725 CrossAlta(1) 32 288 Third-party storage 38 630 120 1,643

(1) Represents TransCanada’s 60 per cent ownership interest in CrossAlta, a 54-Bcf, 480-mmcf/d facility. TransCanada believes the market fundamentals for natural gas storage remain strong. The Company’s additional gas storage capacity is expected to help balance seasonal and short-term supply and demand, and bring flexibility to the supply of natural gas to Alberta and the rest of North America. The increasing seasonal imbalance in North American natural gas supply and demand has increased natural gas price volatility and the demand for storage services. Alberta- based storage will continue to serve market needs and could play an important role should northern gas be connected to North American markets. Energy’s natural gas storage business operates independently from TransCanada’s regulated natural gas transmission business and ANR’s regulated storage business, which is included in TransCanada’s Pipelines segment. TransCanada manages its non-regulated natural gas storage assets’ exposure to seasonal natural gas price spreads by hedging storage capacity with a portfolio of third-party storage capacity leases and proprietary natural gas purchases and sales. In Alberta, TransCanada offers a broad range of injection and withdrawal storage alternatives specific to customer needs in multi-year contracts. Market volatility frequently creates arbitrage opportunities and TransCanada’s storage operations offer solutions to capture value from these short-term price movements. Products consist of short-term deliver-redeliver contracts, parking, peak-day supply and other related services. Earnings from third-party storage capacity leases are recognized over the term of the lease. At December 31, 2007, TransCanada had contracted approximately 74 per cent of the total 120 Bcf of working gas storage capacity in 2008 and 50 per cent of storage capacity in 2009. TransCanada adopted an accounting policy to record proprietary natural gas inventory held in storage at its fair value using the one-month forward price for natural gas, effective April 1, 2007. Changes in the fair value of inventory are recorded in Net Income. Proprietary natural gas storage transactions are comprised of a forward purchase of natural gas to be injected into storage and a simultaneous forward sale of natural gas for withdrawal at a later period, typically during the winter withdrawal season. By matching purchase and sales volumes on a back-to-back basis, TransCanada locks in a margin, Attachment 1 CAPP 11 Page 47 of 142 MANAGEMENT’S DISCUSSION AND ANALYSIS 43

thereby effectively eliminating its exposure to the price movements of natural gas. These forward natural gas contracts provide highly effective economic hedges but do not meet the specific criteria for hedge accounting and, therefore, are recorded at their fair values based on the forward market prices for the contracted month of delivery. Changes in the fair value of these contracts are recorded in Net Income. In 2007, operating income included a $10-million net unrealized gain for the changes in fair value of the proprietary natural gas inventory and forward purchase and sales contracts. Natural Gas Storage operating income was $146 million in 2007, an increase of $53 million compared to 2006. The increase was due primarily to income earned from the first full year of operations of the Edson facility. Natural Gas Storage operating income was $93 million in 2006, an increase of $61 million compared to 2005. The increase was due primarily to higher contributions from CrossAlta as a result of increased utilization and higher natural gas storage spreads as well as income from contracted third-party natural gas storage capacity. The Edson facility did not contribute to earnings in 2006 as it went into service on December 31, 2006.

ENERGY – OPPORTUNITIES AND DEVELOPMENTS Portlands Energy Construction continued in 2007 on the Portlands Energy Centre L.P. (Portlands Energy) project. The capital cost is expected to be approximately $730 million and the facility is expected to be operational in single-cycle mode beginning June 2008. Upon final completion of the combined-cycle mode planned for second-quarter 2009, the plant is expected to provide power under a 20-year Accelerated Clean Energy Supply contract with the OPA. Halton Hills Site preparation and construction began in 2007 on the Halton Hills Generating Station (Halton Hills). The project includes the construction and operation of a natural gas-fired power plant near the town of Halton Hills, Ontario. TransCanada expects to invest approximately $670 million in the project, which is anticipated to be in service in third-quarter 2010. Power from the facility will be sold to the OPA under a 20-year Clean Energy Supply contract. Cartier Wind The Anse-a-Valleau` wind farm went into commercial operation in November 2007, providing up to 101 MW of power to the Hydro Quebec´ grid, and construction began in 2007 on the Carleton wind farm with a generation capacity of 110 MW. Carleton is expected to enter commercial service in fourth-quarter 2008. Anse-a-Valleau` and Carleton are the second and third phases, respectively, of the six-phase, multi-year Cartier Wind project, located in the Gaspe´ region of Quebec.´ The first phase, Baie-des-Sables, went into service in November 2006, generating up to 110 MW of power. The remaining phases of Cartier Wind are expected to be constructed through 2012, subject to the necessary approvals. Capacity is expected to total 740 MW when all six phases are complete. Kibby Wind In January 2008, Maine’s Land Use Regulation Commission voted to recommend the approval of the zoning changes and preliminary development plan submitted by TransCanada to build, own and operate a wind farm in Maine. Subject to U.S. federal and state approvals, construction of the new facilities could begin in 2008, with the project being commissioned in 2009-2010. Becancour´ TransCanada entered into an agreement with Hydro-Quebec´ in November 2007 to temporarily suspend all electricity generation from the Becancour´ power plant during 2008. The agreement, which was requested by Hydro- Quebec´ as a result of its excess electricity supply, was approved by Quebec’s´ Regie´ de l’energie´ in December 2007. The agreement also provides Hydro-Quebec´ the option to extend the suspension to 2009. TransCanada will receive payments under the agreement similar to those that would have been received under the normal course of operation. Bruce Power Bruce Power and the OPA amended their Bruce A refurbishment agreement in 2007 to allow for the installation of 480 new fuel channels in Unit 4. Under the original plan, Bruce Power intended to install new steam generators in all four Bruce A units and replace the fuel channels in Units 1, 2 and 3. By replacing the fuel channels in Unit 4, Bruce Power will extend the expected operational life of the unit to 2036 from 2017. Under the amended agreement, the OPA may elect prior to April 1, 2008 to proceed with a three-unit refurbishment and restart program. The amended refurbishment capital program was originally expected to cost $5.25 billion with $2.75 billion being attributed to refurbishing and restarting Units 1 and 2 and $2.5 billion being attributed to refurbishing Units 3 and 4. In January 2008, a milestone in the Bruce A Units 1 and 2 refurbishment and restart project was completed when the Attachment 1 CAPP 11 Page 48 of 142 44 MANAGEMENT’S DISCUSSION AND ANALYSIS

sixteenth and final new steam generator was installed. With the completion of this stage of the project, the authorized funding for Units 1 and 2 was increased to approximately $3.0 billion from $2.75 billion. Bruce Power is currently preparing a comprehensive estimate of the cost to complete the Unit 1 and 2 restart. This process is expected to result in a further increase in the total project cost. Project cost increases are subject to the capital cost risk- and reward- sharing mechanism under the agreement with the OPA. Bruce A Units 1 and 2 are expected to produce an additional 1,500 MW of power when completed in 2010. As at December 31, 2007, Bruce A had incurred $1.9 billion in costs with respect to the refurbishment and restart of Units 1 and 2 and approximately $0.2 billion for the refurbishment of Units 3 and 4. LNG Projects TransCanada continues to pursue proposals to build, own and operate LNG facilities, including the Broadwater LNG project (Broadwater) and the Cacouna LNG project (Cacouna). Broadwater Broadwater, a joint venture with Shell US Gas & Power LLC in which TransCanada holds a 50 per cent interest, is a proposed LNG facility in New York State waters in Long Island Sound. The Broadwater terminal would be capable of receiving, storing, and regasifying imported LNG with an average send-out capacity of approximately 1 Bcf/d of natural gas. Coincident with the FERC process, Broadwater applied to the New York Department of State for a determination that the project is consistent with New York’s coastal zone policies. The state’s decision is expected in second-quarter 2008. In January 2008, the FERC issued the FEIS, which confirmed project need, supported the location of the project with acknowledgement of its target market and delivery goals, and found safety and security risks to be limited and acceptable. The FEIS also concluded that with adherence to federal and state permit requirements and regulations, Broadwater’s proposed mitigation measures and the FERC’s recommendations, the project will not result in a significant impact on the environment. At December 31, 2007, the Company had capitalized $40 million related to Broadwater. Cacouna Cacouna, a joint venture with Petro-Canada in which TransCanada holds a 50 per cent interest, is a proposed LNG project at the Gros Cacouna Harbour on the St. Lawrence River in Quebec.´ The proposed terminal would be capable of receiving, storing, and regasifying imported LNG with an average throughput capacity of approximately 500 mmcf/d of natural gas. Following public hearings in 2006, the Quebec´ government granted a provincial decree in June 2007 approving the Cacouna terminal. Also in June 2007, the project received federal approvals pursuant to the Canadian Environmental Assessment Act. A delay to 2012 from 2010 in the planned in-service date for the regasification terminal was announced in September 2007. This delay resulted from a need to assess the impacts of permit conditions, to review the facility design in light of escalating costs and to align the schedule with potential LNG supply facilities. In February 2008, the potential anchor LNG supplier for the Cacouna terminal announced it would no longer be pursuing the development of its LNG supply as originally planned. As a result of this announcement, TransCanada and Petro-Canada are currently reviewing their strategy for the project.

ENERGY – BUSINESS RISKS Fluctuating Power and Natural Gas Market Prices TransCanada operates in competitive power and natural gas markets in North America. Volatility in power and natural gas prices is caused by market forces such as fluctuating supply and demand, which are greatly affected by weather events. Energy’s earnings from the sale of uncontracted volumes are subject to price volatility. Although Energy commits a significant portion of its supply to medium- to long-term sales contracts, it retains an amount of unsold supply in order to provide flexibility in managing the Company’s portfolio of wholly owned assets. Uncontracted Volumes Energy has certain uncontracted power sales volumes in Western Power and Eastern Power and through its investment in Bruce Power. Sale of uncontracted power volumes into the spot market is subject to market price volatility, which directly impacts earnings. Bruce B has a significant amount of uncontracted volumes sold into the wholesale power spot market while 100 per cent of the Bruce A output is sold into the Ontario wholesale power spot market under fixed contract price terms with the OPA. The natural gas storage business is subject to fluctuating natural gas seasonal spreads generally Attachment 1 CAPP 11 Page 49 of 142 MANAGEMENT’S DISCUSSION AND ANALYSIS 45

determined by the differential in natural gas prices in the traditional summer injection and winter withdrawal seasons. As a result, the Company hedges capacity with a portfolio of contractual commitments containing varying terms. Plant Availability Maintaining plant availability is essential to the continued success of the Energy business. Plant operating risk is mitigated through a commitment to TransCanada’s operational excellence strategy, which is to provide low-cost, reliable operating performance at each of the Company’s facilities. Unexpected plant outages and the duration of outages could result in lower plant output and sales revenue, reduced margins and increased maintenance costs. At certain times, unplanned outages may require power or natural gas purchases at market prices to ensure TransCanada meets its contractual obligations. Weather Extreme temperature and weather events in North America and the Gulf of Mexico often create price volatility and demand for power and natural gas. These same events may also restrict the availability of power and natural gas. Seasonal changes in temperature can also affect the efficiency and output capability of natural gas-fired power plants. Variability in wind speeds may impact the earnings of the Cartier Wind assets in Quebec.´ Hydrology TransCanada’s power operations are subject to hydrology risk arising from the ownership of hydroelectric power generation facilities in the northeastern U.S. Weather changes, weather events, local river management and potential dam failures at these plants or upstream facilities pose potential risks to the Company. Execution and Capital Cost Energy’s new construction programs in Ontario and Quebec,´ including its investment in Bruce Power, are subject to execution and capital cost risks. At Bruce Power, Bruce A’s four unit refurbishment and restart project is also subject to a capital cost risk- and reward-sharing mechanism with the OPA. Asset Commissioning Although all of TransCanada’s newly constructed assets go through rigorous acceptance testing prior to being placed in service, there is a risk that these assets may have lower than expected availability or performance, especially in their first year of operations. Power Regulatory TransCanada operates in both regulated and deregulated power markets. As electricity markets evolve across North America, there is the potential for regulatory bodies to implement new rules that could negatively impact TransCanada as a generator and marketer of electricity. These may be in the form of market rule changes, price caps, emission controls, unfair cost allocations to generators or attempts to control the wholesale market by encouraging new plant construction. TransCanada continues to monitor regulatory issues and regulatory reform and participate in and lead discussions around these topics. Refer to the ‘‘Risk Management and Financial Instruments’’ section of this MD&A for information on managing risks in the Energy business.

ENERGY – OUTLOOK Although TransCanada has sold forward significant output from its Alberta PPAs and power plants and capacity from its natural gas storage facilities, operating income in 2008 can be affected by changes in the spot market price of power, market heat rates, hydrology, natural gas storage spreads and unplanned outages. Operating income from Energy’s foreign operations is impacted by changes in foreign currency exchange rates. TransCanada’s operating income from its investment in Bruce B can be significantly affected by the impact on uncontracted output of changes in spot market prices for power. Bruce Power’s operating income is expected to be impacted by higher projected generation volumes and lower outage costs resulting from a decrease in planned outages in 2008 compared to 2007. Attachment 1 CAPP 11 Page 50 of 142 46 MANAGEMENT’S DISCUSSION AND ANALYSIS

Other factors such as plant availability, regulatory changes, weather, currency movements, and overall stability of the energy industry can also impact 2008 operating income. Refer to the ‘‘Energy – Business Risks’’ section of this MD&A for a complete discussion of these factors.

Capital Expenditures Total capital expenditures for Energy in 2007 were $1.1 billlion. Energy’s overall capital spending in 2008 is expected to be approximately $1.1 billion and includes cash calls for the Bruce A refurbishment and restart project as well as continued construction at Halton Hills, Portlands Energy and Cartier Wind.

CORPORATE

CORPORATE RESULTS-AT-A-GLANCE Year ended December 31 (millions of dollars) 2007 2006 2005 Indirect financial charges and non-controlling interests248 136 130 Interest income and other(83) (31) (29) Income taxes (120) (72) (65) Comparable expenses(1) 45 33 36 Income tax reassessments and adjustments (68) (72) – Net (earnings)/expenses, after income taxes (23) (39) 36

(1) Refer to the ‘‘Non-GAAP Measures’’ section of this MD&A for further discussion of comparable earnings.

Corporate reflects net expenses not allocated to specific business segments, including: • Indirect Financial Charges and Non-Controlling Interests Direct financial charges are reported in their respective business segments and are associated primarily with debt and preferred securities related to the Company’s wholly owned natural gas pipelines. Indirect financial charges, including the related foreign exchange impacts, reside mainly in Corporate. These costs are influenced directly by the amount of debt that TransCanada maintains and the degree to which the Company is affected by fluctuations in interest and foreign exchange rates. • Interest Income and Other Interest income includes interest earned on invested cash balances and income tax refunds. Gains and losses on foreign exchange related to hedges of the Company’s U.S.-dollar net income and of working capital are also included in Interest Income and Other. • Income Taxes Income tax recoveries includes income taxes calculated on Corporate’s net expenses as well as income tax refunds, reassessments and adjustments that have not been excluded for comparable earnings purposes.

CORPORATE – FINANCIAL RESULTS

Net earnings in Corporate were $23 million in 2007 compared to net earnings of $39 million in 2006 and net expenses of $36 million in 2005. Corporate’s net earnings included favourable income tax reassessments and adjustments of $68 million and $72 million in 2007 and 2006, respectively. Excluding these income tax adjustments, Corporate had comparable expenses of $45 million in 2007, an increase of $12 million from comparable expenses of $33 million in 2006. Gains on derivatives used to manage the Company’s exposure to foreign exchange rate fluctuations and the impact of positive tax rate differentials were more than offset by higher financial charges resulting primarily from financing the acquisitions of ANR and additional interest in Great Lakes. Attachment 1 CAPP 11 Page 51 of 142 MANAGEMENT’S DISCUSSION AND ANALYSIS 47

The increase in Corporate’s net earnings in 2006 compared with 2005 was due mainly to the $72 million of favourable income tax legislative changes, reassessments and adjustments and the positive impact of the weaker U.S. dollar.

CORPORATE – OUTLOOK

Corporate’s net expenses in 2007 included certain favourable income tax reassessments and adjustments that are not expected to recur in 2008. Financing costs associated with debt issued in 2007 and new debt expected to be issued in 2008 to partially finance the Company’s capital programs are expected to increase net expenses in Corporate in 2008, which will be partially offset by capitalized interest for projects under construction. Corporate’s results could also be affected by debt levels, interest rates, foreign exchange and income tax refunds and adjustments. The performance of the Canadian dollar relative to the U.S. dollar will influence Corporate’s results, although this impact is mitigated by offsetting U.S.-dollar exposures in certain of TransCanada’s other businesses and by the Company’s hedging activities.

DISCONTINUED OPERATIONS

TransCanada did not have income from discontinued operations in 2007 and 2005. Income from discontinued operations was $28 million in 2006, reflecting bankruptcy settlements with Mirant related to TransCanada’s Gas Marketing business, which the Company divested in 2001.

LIQUIDITY AND CAPITAL RESOURCES

SUMMARIZED CASH FLOW Year ended December 31 (millions of dollars) 2007 2006 2005 Funds generated from operations2,621 2,378 1,951 Decrease/(increase) in operating working capital215 (303) (49) Net cash provided by operations2,836 2,075 1,902

HIGHLIGHTS

Investing Activities • Capital expenditures and acquisitions, including assumed debt, totalled approximately $11.0 billion over the three-year period ending December 31, 2007.

Dividend • TransCanada’s Board of Directors declared a $0.36 per common share dividend for the quarter ending March 31, 2008, an increase of six per cent over the previous dividend amount. Attachment 1 CAPP 11 Page 52 of 142 48 MANAGEMENT’S DISCUSSION AND ANALYSIS

Funds Generated from Operations Funds Generated Funds Generated from Operations were $2.6 billion in 2007 compared to $2.4 billion and from Operations $2.0 billion, in 2006 and 2005, respectively. The increase in 2007 compared to 2006 was mainly a (millions of dollars) result of higher earnings. The Pipelines business was the primary source of the increase in Funds 2,621 2,378 Generated from Operations in each of the three years. Growth in Energy’s operations also caused an 1,951 increase in Funds Generated from Operations in 2007 compared to the two prior years. At December 31, 2007, TransCanada’s ability to generate adequate amounts of cash in the short term and the long term when needed and to maintain financial capacity and flexibility to provide for planned growth was consistent with recent years. 20059FEB2008012102312006 2007

Investing Activities Capital expenditures totalled $1,651 million in 2007 compared to $1,572 million in 2006 and $754 million in 2005. Expenditures in 2007 were related primarily to construction of new power plants in Canada, the development of new pipelines, including Keystone, and maintenance and capacity projects in the Pipelines business in Canada and the U.S. Expenditures in 2006 and 2005 were related primarily to construction of new power plants and natural gas storage facilities in Canada and maintenance and capacity projects in the Pipelines business.

TransCanada acquired, from El Paso Corporation, 100 per cent of ANR and an additional Capital Expenditures and Acquisitions, 3.6 per cent interest in Great Lakes for US$3.4 billion in 2007, subject to certain post-closing including Assumed adjustments, including approximately US$491 million of assumed long-term debt. The additional Debt (millions of dollars) interest in Great Lakes increased TransCanada’s ownership to 53.6 per cent. PipeLines LP acquired, 6,687 from El Paso Corporation, the remaining 46.4 per cent of Great Lakes for US$942 million, subject to certain post-closing adjustments, including US$209 million of assumed long-term debt.

2,071 2,266 In December 2007, PipeLines LP purchased, from Sierra Pacific Resources, a one per cent ownership interest in Tuscarora for approximately $2 million. In a separate transaction, PipeLines LP also purchased TransCanada’s one per cent ownership interest in Tuscarora for approximately $2 million. 20059FEB200801210078 2006 2007 As a result of these transactions, PipeLines LP owns 100 per cent of Tuscarora. At December 31, 2007, TransCanada held a 32.1 per cent interest in PipeLines LP. In fourth-quarter 2007, the Company’s Energy segment sold land in Ontario that had been previously held for development, generating net proceeds of $38 million. In 2006, PipeLines LP acquired an additional 49 per cent interest in Tuscarora for US$100 million, subject to closing adjustments, in addition to indirectly assuming US$37 million of debt. PipeLines LP also acquired an additional 20 per cent general partnership interest in Northern Border for US$307 million, in addition to indirectly assuming US$122 million of debt. TransCanada sold its 17.5 per cent general partner interest in Northern Border Partners, L.P. for proceeds of $35 million, net of current tax. In 2005, TransCanada obtained the remaining rights to full generating capacity under the Sheerness PPA for $585 million, invested $100 million in Bruce A as part of the Bruce Power reorganization, purchased the TC Hydro assets from USGen New England, Inc. for US$503 million and acquired an additional 3.52 per cent ownership interest in Iroquois for US$14 million. TransCanada sold its ownership interest in Power LP for proceeds of $444 million, net of current tax, and also sold its ownership interest of approximately 11 per cent in Paiton Energy for proceeds of $125 million, net of current tax, and PipeLines LP units for proceeds of $102 million, net of current tax.

Financing Activities In 2007, TransCanada issued Long-Term Debt of $2.6 billion and Junior Subordinated Notes of US$1.0 billion, and its proportionate share of Long-Term Debt issued by joint ventures was $142 million. The Company also reduced its Long-Term Debt by $1.1 billion, its Notes Payable by $46 million and its proportionate share of the Long-Term Debt of Attachment 1 CAPP 11 Page 53 of 142 MANAGEMENT’S DISCUSSION AND ANALYSIS 49

Joint Ventures by $157 million. In February 2007, the Company established a US$2.2-billion, committed, unsecured, one-year bridge loan facility and utilized $1.5 billion and US$700 million to partially finance its acquisition of ANR and its increased ownership in Great Lakes. At December 31, 2007, US$370 million remained outstanding on this facility. At December 31, 2007, total unsecured revolving and demand credit facilities of $2.9 billion were available to support the Company’s commercial paper program and for general corporate purposes. These credit facilities include the following: • in December 2007, the $1.5 billion committed five-year term syndicated credit facility was increased to $2.0 billion and extended to December 2012. The cost to maintain the credit facility was $2 million in 2007 (2006 – $2 million). • at December 31, 2007, a US$300 million five-year, extendible revolving facility was available, which is part of the US$1.0 billion TransCanada PipeLine USA Ltd. credit facility discussed below in the section ‘‘2007 Long-Term Debt Financing Activities‘‘. • the Company also has in place $600 million of demand lines, which support the issuance of letters of credit and provide additional liquidity. The Company had used approximately $334 million of its total lines of credit for letters of credit at December 31, 2007. When drawn, interest on the lines of credit is charged at prime rates of Canadian chartered and U.S. banks, and at other negotiated financial bases.

2007 Long-Term Debt Financing Activities In March 2007, the Company filed debt shelf prospectuses in Canada and the U.S. qualifying for issuance $1.5 billion of Medium-Term Notes and US$1.5 billion of debt securities, respectively. At December 31, 2007, the Company had issued no Medium-Term Notes under the Canadian prospectus and, in September 2007, replaced the March 2007 U.S. debt shelf prospectus with a new US$2.5-billion U.S. debt shelf prospectus. In October 2007, TransCanada issued US$1.0 billion of Senior Unsecured Notes under the US$2.5-billion U.S. debt shelf prospectus. These notes mature on October 15, 2037 and bear interest at a rate of 6.20 per cent. US$1.5 billion remains available under the U.S. debt shelf at December 31, 2007. In July 2007, TransCanada exercised its rights to redeem the US$460-million 8.25 per cent Preferred Securities due 2047. The Preferred Securities were redeemed for cash, at par, as part of the settlement on the Canadian Mainline. The foreign exchange gain realized on redemption of the securities will flow through to Canadian Mainline shippers over the five-year period of the settlement. In April 2007, TransCanada PipeLines Limited (TCPL) issued US$1.0 billion of Junior Subordinated Notes, maturing in 2067 and bearing interest of 6.35 per cent per year until May 15, 2017, when interest will convert to a floating rate, reset quarterly to the three-month London Interbank Offered Rate (LIBOR) plus 221 basis points. The Company has the option to defer payment of interest for periods of up to ten years without giving rise to a default and without permitting acceleration of payment under the terms of the Junior Subordinated Notes. The Company would be prohibited from paying dividends during any deferral period. The Junior Subordinated Notes are subordinated in right of payment to existing and future senior indebtedness and are effectively subordinated to all indebtedness and obligations of TCPL. The Junior Subordinated Notes are callable at the Company’s option at any time on or after May 15, 2017 at 100 per cent of the principal amount of the Junior Subordinated Notes plus accrued and unpaid interest to the date of redemption. The Junior Subordinated Notes are callable earlier at the Company’s option, in whole or in part, at an amount equal to the greater of 100 per cent of the principal amount of the Junior Subordinated Notes plus accrued and unpaid interest to the date of redemption and an amount determined by formula in accordance with the terms of the Junior Subordinated Notes. The Junior Subordinated Notes were issued under the U.S. shelf prospectus filed in March 2007. In April 2007, Northern Border increased its five-year bank facility to US$250 million from US$175 million. A portion of the bank facility was drawn to refinance US$150 million of Senior Notes that matured on May 1, 2007, with the balance available to fund Northern Border’s ongoing operations. Attachment 1 CAPP 11 Page 54 of 142 50 MANAGEMENT’S DISCUSSION AND ANALYSIS

In March 2007, ANR Pipeline voluntarily withdrew the New York Stock Exchange listing of its 9.625 per cent Debentures due 2021, 7.375 per cent Debentures due 2024, and 7.0 per cent Debentures due 2025. With the delisting, which became effective April 12, 2007, ANR Pipeline deregistered these securities with the SEC. In February 2007, the Company established a US$1.0 billion committed, unsecured credit facility, consisting of a US$700-million five-year term loan and a US$300-million five-year, extendible revolving facility. The Company utilized US$1.0 billion from this facility and an additional US$100 million from an existing demand line to partially finance the ANR acquisition and increased ownership in Great Lakes, as well as its additional investment in PipeLines LP. At December 31, 2007, US$860 million remained outstanding on the committed facility and the demand line had been fully repaid. In February 2007, PipeLines LP increased the size of its syndicated revolving credit and term loan facility in connection with its Great Lakes acquisition. The amount available under the facility increased to US$950 million from US$410 million and consisted of a US$700-million senior term loan and a US$250-million senior revolving credit facility, with US$194 million of the available senior term loan amount being terminated upon closing of the Great Lakes acquisition. At December 31, 2007, US$507 million remained outstanding on the facility. In January 2008, the Company retired $105 million of 6.0 per cent Medium-Term Notes. In October 2007, the Company retired $150 million of 6.15 per cent Medium-Term Notes. In February 2007, the Company retired $275 million of 6.05 per cent Medium-Term Notes.

2006 Long-Term Debt Financing Activities In 2006, TransCanada reduced its Long-Term Debt by $729 million, its Notes Payable by $495 million and its proportionate share of the Long-Term Debt of Joint Ventures by a net amount of $14 million. In January 2006, the Company issued $300 million of 4.3 per cent five-year Medium-Term Notes due 2011. In March 2006, the Company issued US$500 million of 5.85 per cent 30-year Senior Unsecured Notes due 2036. In October 2006, TransCanada issued $400 million of 4.65 per cent ten-year Medium-Term Notes due 2016. In April 2006, PipeLines LP borrowed US$307 million under its unsecured credit facility to finance the cash portion of its acquisition of an additional 20 per cent interest in Northern Border. In December 2006, the credit facility was repaid in full and replaced with a US$410-million syndicated revolving credit and term loan agreement, of which US$397 million was drawn as at December 31, 2006, a portion of which was utilized to finance the acquisition of additional interests in Tuscarora. In February 2007, PipeLines LP increased the size of this facility, as discussed above.

2005 Long-Term Debt Financing Activities In 2005, TransCanada reduced its Long-Term Debt by $1,113 million and increased its Notes Payable by $416 million. Financing activities included a net reduction in the Company’s proportionate share of Long-Term Debt of Joint Ventures of $42 million. In June 2005, GTNC redeemed all of its outstanding US$150-million 7.8 per cent Senior Unsecured Debentures and US$250-million 7.1 per cent Senior Unsecured Notes. Following an application by GTNC, it no longer has any securities registered under U.S. securities laws. In June 2005, GTNC also completed a US$400-million multi- tranche private placement of senior debt with a weighted average interest rate of 5.28 per cent and weighted average life of approximately 18 years. In 2005, TransCanada also issued $300 million of 5.1 per cent Medium-Term Notes due 2017 under the Company’s Canadian shelf prospectus.

2007 Equity Financing Activities In January 2007, TransCanada filed a short form shelf prospectus with securities regulators in Canada and the U.S. to allow for the offering of up to $3.0 billion of common shares, preferred shares and/or subscription receipts in Canada and the U.S. until February 2009. In February and March 2007, the Company issued 45,390,500 common shares under the short form shelf prospectus, at a price of $38.00 each, resulting in gross proceeds of approximately $1.7 billion, which were used towards financing the ANR acquisition and increased ownership in Great Lakes. In 2007, TransCanada’s Board of Directors authorized the issuance of common shares from treasury at a discount of two per cent to participants in the Company’s DRP. Under this plan, eligible shareholders may reinvest their dividends Attachment 1 CAPP 11 Page 55 of 142 MANAGEMENT’S DISCUSSION AND ANALYSIS 51

and make optional cash payments to obtain additional TransCanada common shares. Commencing with the dividend payable in April 2007, the DRP shares were provided to the participants at a two per cent discount to the average market price in the five days before dividend payment. Dividends of $157 million were paid in 2007 through the issuance of 4.1 million common shares issued from treasury in accordance with the DRP. In February 2007, PipeLines LP completed a private placement offering of 17,356,086 common units at a price of US$34.57 per unit, of which 50 per cent were acquired by TransCanada for US$300 million. TransCanada also invested an additional US$12 million to maintain its general partnership ownership interest in PipeLines LP. As a result of these additional investments, TransCanada’s ownership in PipeLines LP increased to 32.1 per cent on February 22, 2007. The total private placement together with TransCanada’s additional general partnership investment resulted in gross proceeds to PipeLines LP of US$612 million, which were used to partially finance its acquisition of a 46.4 per cent ownership interest in Great Lakes.

Dividends Cash dividends on common shares amounting to $546 million were paid in 2007 compared to cash dividends amounting to $617 million in 2006 and $586 million in 2005. The reduction in 2007 compared to 2006 reflected the Company’s issuance of $157 million of common shares under the DRP, in lieu of cash dividends. In January 2008, TransCanada’s Board of Directors approved an increase in the quarterly common share dividend payment to $0.36 per share from $0.34 per share for the quarter ending March 31, 2008. This was the eighth consecutive year of dividend increase beginning with the dividend of $0.20 per share declared in fourth-quarter 2000 and represents an 80 per cent increase in the dividend over this period.

Issuer Ratings TransCanada’s issuer rating assigned by Moody’s Investors Service (Moody’s) is A3 with a stable outlook. TCPL’s senior with a stable מunsecured debt is rated A with a stable outlook by DBRS, A2 with a stable outlook by Moody’s, and A outlook by Standard and Poor’s.

CONTRACTUAL OBLIGATIONS

Obligations and Commitments At December 31, 2007, the Company had total long-term debt of $12.9 billion and $1.0 billion of Junior Subordinated Notes, compared to long-term debt of $11.5 billion at December 31, 2006. TransCanada’s share of the total debt of joint ventures, including capital lease obligations, was $903 million at December 31, 2007, compared to $1.3 billion at December 31, 2006. Total notes payable, including TransCanada’s proportionate share of the notes payable of joint ventures, were $421 million at December 31, 2007, compared to $467 million at December 31, 2006. The security provided by each joint venture, except for the capital lease obligation at Bruce Power, is limited to the rights and assets of the joint venture and does not extend to the rights and assets of TransCanada, but does extend to the Company’s investment. TransCanada has provided certain pro-rata guarantees related to the capital lease obligations of Bruce Power and to the performance obligations of Bruce Power and certain other partially owned entities. Attachment 1 CAPP 11 Page 56 of 142 52 MANAGEMENT’S DISCUSSION AND ANALYSIS

CONTRACTUAL OBLIGATIONS Year ended December 31 (millions of dollars) Payments Due by Period Less than 1 - 3 3 - 5 More than Total one year years years 5 years Long-term debt(1) 14,568 577 1,965 2,182 9,844 Capital lease obligations 243 9 23 33 178 Operating leases(2) 1,081 49 91 106 835 Purchase obligations 11,694 3,414 2,657 1,635 3,988 Other long-term liabilities reflected on the balance sheet 372 10 24 29 309 Total contractual obligations 27,958 4,059 4,760 3,985 15,154

(1) Includes Junior Subordinated Notes. (2) Represents future annual payments, net of sub-lease receipts, for various premises, services, equipment and a natural gas storage facility. The operating lease agreements for premises expire at various dates through 2021, with an option to renew certain lease agreements for one to ten years. The operating lease agreement for the natural gas storage facility expires in 2030. The lessee has the right to terminate the agreement on anniversary dates five years apart commencing in 2010, and the lessor has the right to terminate the agreement on the same schedule commencing in 2015.

TransCanada’s commitments under the Alberta PPAs are considered to be operating leases and a portion of these PPAs have been subleased to third parties under similar terms and conditions. Future payments under these PPAs have been excluded from the above table as these payments are dependent upon plant availability, among other things. The amount of power purchased under the PPAs in 2007 was $440 million (2006 – $499 million; 2005 – $230 million). At December 31, 2007, scheduled principal repayments and interest payments related to long-term debt and the Company’s proportionate share of the long-term debt of joint ventures were as follow:

PRINCIPAL REPAYMENTS Year ended December 31 (millions of dollars) Payments Due by Period Less than 1 - 3 3 - 5 More than Total one year years years 5 years Long-term debt 12,933 556 1,619 2,051 8,707 Junior subordinated notes 975 – – – 975 Long-term debt of joint ventures 660 21 346 131 162 Total principal repayments 14,568 577 1,965 2,182 9,844 Attachment 1 CAPP 11 Page 57 of 142 MANAGEMENT’S DISCUSSION AND ANALYSIS 53

INTEREST PAYMENTS Year ended December 31 (millions of dollars) Payments Due by Period Less than 1 - 3 3 - 5 More than Total one year years years 5 years Interest payments on long-term debt 10,978 832 1,511 1,339 7,296 Interest payments on junior subordinated notes 588 63 125 125 275 Interest payments on long-term debt of joint ventures 332 55 85 53 139 Total interest payments 11,898 950 1,721 1,517 7,710

At December 31, 2007, the Company’s approximate future purchase obligations were as follow:

PURCHASE OBLIGATIONS(1) Year ended December 31 (millions of dollars) Payments Due by Period Less than 1 - 3 3 - 5 More than Total one year years years 5 years Pipelines Transportation by others(2) 719 197 283 133 106 Capital expenditures(3)(4) 1,677 1,107 567 3 – Other 153 55 46 46 6

Energy Commodity purchases(5) 7,381 1,134 1,278 1,225 3,744 Capital expenditures(3)(6) 1,293 723 354 168 48 Other(7) 377 175 83 42 77

Corporate Information technology and other 94 23 46 18 7 Total purchase obligations 11,694 3,414 2,657 1,635 3,988

(1) The amounts in this table exclude funding contributions to pension plans and funding to the APG. (2) Rates are based on known 2008 levels. Beyond 2008, demand rates are subject to change. The contract obligations in the table are based on known or contracted demand volumes only and exclude commodity charges incurred when volumes flow. (3) Amounts are estimates and are subject to variability based on timing of construction and project enhancements. The Company expects to fund these projects with cash from operations and, if necessary, new debt. (4) Primarily consists of capital expenditures related to TransCanada’s share of the construction costs for Keystone and other pipeline projects. (5) Commodity purchases include fixed and variable components. The variable components are estimates and are subject to variability in plant production, market prices and regulatory tariffs. (6) Primarily consists of capital expenditures related to TransCanada’s share of the construction costs for Halton Hills, Portlands Energy and the remaining Cartier Wind projects. (7) Includes estimates of certain amounts that are subject to change depending on plant fired hours, the consumer price index, actual plant maintenance costs, plant salaries, and changes in regulated rates for transportation. Attachment 1 CAPP 11 Page 58 of 142 54 MANAGEMENT’S DISCUSSION AND ANALYSIS

TransCanada expects to make funding contributions to the Company’s pension plans and other benefit plans in the amount of approximately $60 million and $14 million, respectively, in 2008. The expected increase in total pension and post-retirement benefits funding in 2008, from $61 million in 2007, is attributed primarily to a decline in the actual return on plan assets compared to investment performance expectations for 2007 and plan experience being different than expected. TransCanada’s proportionate share of funding contributions expected to be made by joint ventures to their respective pension plans and other benefit plans in 2008 is approximately $31 million and $3 million, respectively. TransCanada and its affiliates have long-term natural gas transportation and natural gas purchase arrangements as well as other purchase obligations, all of which are transacted at market prices and in the normal course of business.

Bruce Power Bruce A has signed commitments to third-party suppliers related to refurbishing and restarting Units 1 and 2 and refurbishing Units 3 and 4 to extend their operating life. TransCanada’s share of these signed commitments, which extend over the four-year period ending December 31, 2011, are as follow:

Year ended December 31 (millions of dollars)

2008 360 2009 151 2010 69 2011 14 594

Aboriginal Pipeline Group On June 18, 2003, the Mackenzie Delta gas producers, the APG and TransCanada reached an agreement governing TransCanada’s role in the MGP project to build a natural gas pipeline from Inuvik, Northwest Territories, to the northern border of Alberta, where it would connect with the Company’s Alberta System. Under the agreement, TransCanada agreed to finance the APG for its one-third share of project pre-development costs. These costs are currently forecasted to be between $150 million and $200 million, depending on the pace of project development. As at December 31, 2007, the Company had advanced $137 million of this total. TransCanada and the other co-venture companies involved in the MGP continue to pursue approval of the proposed project, focusing on the regulatory process and discussions with the Canadian government on the fiscal framework. Project timing is uncertain and is conditional upon resolution of regulatory and fiscal matters. TransCanada’s ability to recover its investment depends on the successful outcome of the project.

Contingencies The Canadian Alliance of Pipeline Landowners’ Associations (CAPLA) and two individual landowners commenced an action in 2003 against TransCanada and Enbridge Inc. under Ontario’s Class Proceedings Act, 1992 for damages of $500 million. The damages are alleged to have arisen from the creation of a control zone within 30 metres of a pipeline pursuant to Section 112 of the National Energy Board Act. In November 2006, TransCanada and Enbridge Inc. were granted a dismissal of the case but CAPLA appealed the decision. The Ontario Court of Appeal heard the appeal on December 18, 2007, and reserved its decision. The Company continues to believe the claim is without merit and will vigorously defend the action. The Company has made no provision for any potential liability. A liability, if any, would be dealt with through the regulatory process. Attachment 1 CAPP 11 Page 59 of 142 MANAGEMENT’S DISCUSSION AND ANALYSIS 55

TransCanada and its subsidiaries are subject to various legal proceedings and actions arising in the normal course of business. While the final outcome of such legal proceedings and actions cannot be predicted with certainty, it is the opinion of management that the resolution of such proceedings and actions will not have a material impact on the Company’s consolidated financial position or results of operations. Guarantees TransCanada, Cameco and BPC have each severally guaranteed one-third of certain contingent financial obligations of Bruce B related to power sales agreements, operator licenses, a lease agreement and contractor services. The guarantees have terms ranging from one year ending in 2008 to perpetuity. TransCanada and BPC have each severally guaranteed one-half of certain contingent financial obligations related to an agreement with the OPA to refurbish and restart Bruce A power generation units. The guarantees were part of the reorganization of Bruce Power in 2005 and have terms ending in 2019 to 2036. TransCanada’s share of the potential exposure under these Bruce Power guarantees was estimated at December 31, 2007, to range from $711 million to a maximum of $750 million. The fair value of these guarantees is estimated to be $12 million. The Company and its partners in certain jointly owned entities have severally and joint and severally guaranteed the performance of these entities related primarily to construction projects, redelivery of natural gas, PPA payments and the payment of liabilities. TransCanada’s share of the potential exposure under these guarantees was estimated at December 31, 2007 to range from $699 million to a maximum of $1,210 million. For certain of these entities, any payments made by TransCanada under these guarantees in excess of its ownership interest are to be reimbursed by its partners. Deferred Amounts includes $7 million for the fair value of these joint and several guarantees. TransCanada has guaranteed a subsidiary’s equity undertaking that supports the payment, under certain conditions, of principal and interest on US$75 million of the public debt obligations of TransGas. The Company has a 46.5 per cent interest in TransGas. Under the terms of a shareholder agreement, TransCanada and another major multinational company may be required to severally fund more than their proportionate share of debt obligations of TransGas in the event that the minority shareholders fail to contribute. Any payments made by TransCanada under this agreement convert into share capital of TransGas. The Company’s potential exposure is contingent on the impact any change of law would have on the ability of TransGas to service the debt. There has been no change in applicable law since the issuance of debt in 1995 and, thus, no exposure for TransCanada. The debt matures in 2010. The Company has made no provision related to this guarantee.

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS FINANCIAL RISKS Risk Management Overview TransCanada has exposure to market, counterparty credit and liquidity risk. The risk management function assists in managing these risks. TransCanada’s primary risk management objective is to protect earnings and cash flow, and ultimately shareholder value. Risk management strategies, policies and limits are designed to ensure TransCanada’s risks and related exposures are in line with the Company’s business objectives and risk tolerance. Risks are managed within limits established by the Company’s Board of Directors, implemented by senior management and monitored by risk management personnel. TransCanada’s Audit Committee oversees how management monitors compliance with risk management policies and procedures, and management’s review of the adequacy of the risk management framework. Internal audit personnel assist the Audit Committee in its oversight role by performing regular and ad-hoc reviews of risk management controls and procedures, the results of which are reported to the Audit Committee.

Market Risk The Company constructs and invests in large infrastructure projects, purchases and sells commodities, issues short- and long-term debt including amounts in foreign currencies, and invests in foreign operations. These activities expose the Company to market risk from changes in commodity prices, foreign exchange rates and interest rates, which affect the Company’s earnings and the value of the financial instruments it holds. Attachment 1 CAPP 11 Page 60 of 142 56 MANAGEMENT’S DISCUSSION AND ANALYSIS

The Company uses derivatives as part of its overall risk management policy to manage exposures to market risk that result from these activities. Contracts used to manage market risk generally consist of the following: • Forwards and futures contracts – contractual agreements to purchase or sell a specific financial instrument or commodity at a specified price and date in the future. TransCanada enters into foreign exchange and commodity forwards and futures to mitigate the impact of volatility in foreign exchange rates and commodity prices. • Swaps – contractual agreements between two parties to exchange streams of payments over time according to specified terms. The Company enters into interest rate, cross-currency and commodity swaps to mitigate the impact of changes in interest rates, foreign exchange rates and commodity prices. • Options – contractual agreements to convey the right, but not the obligation, for the purchaser to buy or sell a specific amount of a financial instrument or commodity at a fixed price, either at a fixed date or at any time within a specified period. The Company enters into option agreements to mitigate the impact of changes in interest rates, foreign exchange rates and commodity prices. • Heat rate contracts – contracts for the purchase or sale of power that are priced based on a natural gas index. Commodity Price Risk The Company is exposed to commodity price movements as part of its normal business operations, particularly in relation to the prices of power and natural gas. A number of strategies are used to mitigate these exposures, including the following: • The Company enters into offsetting or back-to-back physical positions and derivative financial instruments to manage market risk exposures created by certain fixed and variable pricing arrangements at different pricing indices and delivery points. • Subject to the Company’s overall risk management policies, the Company commits a significant portion of its power supply to medium- or long-term sales contracts, while reserving an amount of unsold supply to maintain operational flexibility in the overall management of its asset portfolio. • The Company purchases a portion of the natural gas required for its gas-fired cogeneration plants or enters into heat-rate contracts that base the sales price of electricity on the cost of natural gas, effectively locking in a margin. A significant portion of the electricity needed to fulfill the Company’s power requirements is purchased with forward contracts or fulfilled through power generation, thereby reducing the Company’s exposure to fluctuating commodity prices. The Company assesses its commodity contracts and derivative instruments used to manage energy commodity risk to determine the appropriate accounting treatment. Contracts, with the exception of leases, have been assessed to determine whether they meet the definition of a derivative. Certain commodity purchase and sale contracts are derivatives but are not within the scope of CICA Handbook Section 3855 ‘‘Financial Instruments – Recognition and Measurement’’, as they were entered into and continue to be held for the purpose of receipt or delivery in accordance with the Company’s normal purchases and normal sales exemption. Certain other contracts are not within the scope of Section 3855 as they are considered to meet other exemptions. TransCanada manages its exposure to seasonal natural gas price spreads in its natural gas storage business by hedging storage capacity with a portfolio of third-party storage capacity leases and proprietary natural gas purchases and sales. By matching purchase and sale volumes, TransCanada locks in a margin on a back-to-back basis and thereby effectively eliminates its exposure to natural gas market price fluctuations. Natural Gas Inventory Price Risk Effective April 1, 2007, TransCanada began valuing its proprietary natural gas inventory held in storage at fair value, as measured by the one-month forward price for natural gas. At December 31, 2007, $190 million of proprietary natural gas inventory was included in Inventories. The amount recorded in 2007 in Revenues for the net change in the fair value of proprietary natural gas held in inventory was insignificant. A gain of $10 million was recorded in 2007 in Revenues for the net change in fair value of the forward proprietary natural gas purchase and sales contracts. Attachment 1 CAPP 11 Page 61 of 142 MANAGEMENT’S DISCUSSION AND ANALYSIS 57

Foreign Exchange and Interest Rate Risk Foreign exchange and interest rate risk is created by fluctuations in the fair values or cash flows of financial instruments due to changes in foreign exchange rates and/or changes in the market interest rates. A portion of TransCanada’s earnings from its Pipelines and Energy operations outside of Canada is generated primarily in U.S. dollars and is subject to currency fluctuations. The performance of the Canadian dollar relative to the U.S. dollar could positively or negatively affect TransCanada’s earnings. This foreign exchange impact is offset by exposures in certain of TransCanada’s businesses and by the Company’s hedging activities. Due to its growing operations in the U.S., including the acquisitions of ANR and additional interests in Great Lakes and PipeLines LP, TransCanada expects to have a greater exposure to U.S. dollar fluctuations than in prior years. The Company uses foreign currency and interest rate derivatives to manage the foreign exchange and interest rate risks related to its U.S. dollar-denominated debt and other transactions, as well as to manage the interest rate exposures of the Canadian Mainline, Alberta System and Foothills. Certain of the realized gains and losses on these derivatives are shared with shippers on predetermined terms. These gains and losses are deferred as regulatory assets and liabilities until they are recovered from or paid to the shippers in accordance with the terms of the shipping agreements. The Company has fixed-rate long-term debt, which subjects it to interest rate price risk, and has floating interest rate debt, which subjects it to interest rate cash flow risk. The Company uses a combination of forwards, interest rate swaps and options to manage its exposure to these risks. Net Investment in Self-Sustaining Foreign Operations The Company hedges its net investment in self-sustaining foreign operations on an after-tax basis with U.S. dollar- denominated debt, forward contracts, cross-currency interest rate swaps and options. The Company had designated U.S. dollar-denominated debt with a carrying value of $4.7 billion (US$4.7 billion) and a fair value of $4.8 billion (US$4.8 billion) as a net investment hedge at December 31, 2007. The forwards, swaps and options are recorded at their fair value and are included in Other Assets. The fair values and notional or principal amount for the derivatives designated as a net investment hedge were as follow:

2007 2006 Asset/(Liability) Notional or Notional or Fair Principal Principal December 31 (millions of dollars) Value(1) Amount Fair Value(1) Amount U.S. dollar cross-currency swaps (maturing 2009 to 2014) 77 U.S. 350 58 U.S. 400 U.S. dollar options (maturing 2008) 3 U.S. 600 (6) U.S. 500 U.S. dollar forward foreign exchange contracts (maturing 2008) (4) U.S. 150 (7) U.S. 390 76 U.S. 1,100 45 U.S. 1,290

(1) Other Comprehensive Income in 2007 included unrealized foreign currency translation losses of $350 million (2006 – gains of $6 million; 2005 – losses of $34 million) related to the change in value of investments in foreign operations. Other Comprehensive Income also included unrealized gains of $79 million (2006 – losses of $6 million; 2005 – gains of $15 million) for changes in fair value of hedges of investments in foreign operations. VaR Analysis TransCanada uses a Value-at-Risk methodology (VaR) to estimate the potential impact resulting from its exposure to market risk. VaR estimates the potential change in pre-tax earnings over a given holding period for a specified confidence level. The VaR number calculated and used by TransCanada reflects the 95 per cent probability that the daily change resulting from normal market fluctuations in its liquid positions will not exceed the reported VaR. VaR methodology is a statistically-defined, probability-based approach that takes into consideration market volatilities as well Attachment 1 CAPP 11 Page 62 of 142 58 MANAGEMENT’S DISCUSSION AND ANALYSIS

as risk diversification by recognizing offsetting positions and correlations between products and markets. Risks are measured across all products and markets, and risk measures can be aggregated to arrive at a single VaR number. There is currently no uniform industry methodology for estimating VaR. The use of VaR has limitations because it is based on historical correlations and volatilities in commodity prices, interest rates and foreign exchange rates, and assumes that future price movements will follow a statistical distribution. Although losses are not expected to exceed the statistically estimated VaR on 95 per cent of occasions, losses on the other five per cent of occasions could be substantially greater than the estimated VaR. TransCanada’s estimation of VaR includes wholly owned subsidiaries, and incorporates relevant risks associated with each market or business unit. The calculation does not include the Pipelines segment as the rate-regulated nature of the pipeline business reduces the impact of market risks and limits TransCanada’s ability to manage these risks. The Company’s Board of Directors has established a VaR limit, which is monitored on an ongoing basis as part of the Company’s risk management policy. TransCanada’s consolidated VaR was less than $10 million at December 31, 2007.

Counterparty Credit Risk Counterparty credit risk represents the financial loss that the Company would experience if a counterparty to a financial instrument, in which the Company has an amount owing from the counterparty, failed to meet its obligations in accordance with the terms and conditions of its contracts with the Company. Counterparty credit risk is mitigated through established credit management techniques, including conducting financial and other assessments to establish and monitor a counterparty’s creditworthiness, setting exposure limits, monitoring exposures against these limits, utilizing master netting arrangements and obtaining financial assurances where warranted. In general, financial assurances include guarantees, letters of credit and cash. The Company monitors and manages its concentration of counterparty credit risk on an ongoing basis. TransCanada’s maximum counterparty credit exposure at the balance sheet date consists primarily of the carrying amount of non-derivative financial assets as well as the fair value of derivative financial assets. The Company has contracts for the sale of non-financial items. Many of these contracts do not meet the definition of a financial instrument since the underlying volumes are physically delivered during the Company’s normal course of business. Exposure to counterparty credit risk on these non-financial contracts results from the potential of a counterparty defaulting on invoiced amounts owing to TransCanada. These invoiced amounts are included in the Accounts Receivable and Other Assets amounts disclosed in the Non-Derivative Financial Instruments Summary table presented later in this section. Some of these non-financial contracts do meet the definition of a derivative and are recorded at fair value. The carrying amounts and fair values of financial assets and non-financial derivatives are disclosed in the Non-Derivative Financial Instruments Summary and the Derivative Financial Instruments Summary tables presented later in this section. The Company does not have any significant concentrations of counterparty credit risk and the majority of the counterparty credit exposure is with counterparties who are investment grade. The Company has reached agreements for allowed unsecured claims with certain subsidiaries of Calpine, former shippers on TransCanada’s pipeline systems that have filed for bankruptcy protection, as discussed in the ‘‘Pipelines – Outlook’’ section of this MD&A.

Liquidity Risk Liquidity risk is the risk that TransCanada will not be able to meet its financial obligations as they fall due. The Company’s approach to managing liquidity risk is to ensure that it always has sufficient cash and credit facilities to meet its obligations when due, under both normal and stressed conditions, without incurring unacceptable losses or damage to the Company’s reputation. Management typically forecasts cash flows for a period of 12 months to identify financing requirements. These requirements are then addressed through a combination of committed and demand credit facilities, and through access to capital markets. Attachment 1 CAPP 11 Page 63 of 142 MANAGEMENT’S DISCUSSION AND ANALYSIS 59

Fair Values The fair value of Cash and Cash Equivalents and Notes Payable approximates their carrying amounts due to the short time period to maturity. The fair value of foreign exchange and interest rate derivatives has been calculated using year-end market rates. The fair value of power, natural gas and heat rate derivatives has been calculated using estimated forward prices for the relevant period. Fair values of financial instruments are determined by reference to quoted bid or asking price, as appropriate, in active markets at period-end dates. In the absence of an active market, the Company determines fair value by using valuation techniques that refer to observable market data or estimated market prices. These include comparisons with similar instruments that have observable market prices, option pricing models and other valuation techniques commonly used by market participants. Fair values determined using valuation models require the use of assumptions about the amount and timing of estimated future cash flows and discount rates. In making these assumptions, the Company looks primarily to readily observable external market input factors such as interest rate yield curves, currency rates, and price and rate volatilities as applicable. The fair value of the Company’s Long-Term Debt was estimated based on quoted market prices for the same or similar debt instruments and, when such information was not available, by discounting future payments of interest and principal at estimated interest rates that were made available to the Company at December 31, 2007. Non-Derivative Financial Instruments Summary The carrying and fair values of non-derivative financial instruments were as follow:

Carrying December 31, 2007 (millions of dollars) Amount Fair Value Financial Assets(1) Cash and cash equivalents 504 504 Accounts receivable and other assets(2)(3) 1,231 1,231 Available-for-sale assets(2) 17 17 1,752 1,752

Financial Liabilities(1)(3) Notes payable 421 421 Accounts payable and deferred amounts(4) 1,454 1,454 Long-term debt and junior subordinated notes 13,908 15,340 Long-term debt of joint ventures 903 937 Other long-term liabilities of joint ventures(4) 60 60 16,746 18,212

(1) Consolidated Net Income in 2007 included unrealized gains or losses of nil for the fair value adjustments to each of these financial instruments. (2) The Consolidated Balance Sheet included financial assets of $1,018 million in Accounts Receivable and $230 million in Other Assets at December 31, 2007. (3) Recorded at amortized cost, except for Long-Term Debt of $150 million and US$200 million adjusted to fair value. (4) The Consolidated Balance Sheet included financial liabilities of $1,436 million in Accounts Payable and $78 million in Deferred Amounts at December 31, 2007. Attachment 1 CAPP 11 Page 64 of 142 60 MANAGEMENT’S DISCUSSION AND ANALYSIS

Derivative Financial Instruments Summary Information for the Company’s derivative financial instruments is as follows.

2007 December 31 (all amounts in millions unless otherwise Foreign indicated) Power Natural Gas Exchange Interest Derivative Financial Instruments Held for Trading Fair Values(1) Assets $55 $43 $11 $23 Liabilities $(44) $(19) $(79) $(18) Notional Values Volumes(2) Purchases 3,774 47 – – Sales 4,469 64 – – Canadian dollars – – – 615 U.S. dollars – – U.S. 484 U.S. 550 Japanese yen (in billions) – – JPY 9.7 – Cross-currency – – 227/U.S. 157 – Unrealized gains/(losses) in the period(3) $16 $(10) $8 $(5) Realized (losses)/gains in the period(3) $(8) $47 $39 $5 Maturity dates 2008 - 2016 2008 - 2010 2008 - 2012 2008 - 2016 Derivative Financial Instruments in Hedging Relationships(4)(5)(6) Fair Values(1) Assets $135 $19 $ – $2 Liabilities $(104) $(7) $(62) $(16) Notional Values Volumes(2) Purchases 7,362 28 – – Sales 16,367 4 – – Canadian dollars – – – 150 U.S. dollars – – U.S. 113 U.S. 875 Cross-currency – – 136/U.S. 100 – Realized (losses)/gains in the period(3) $(29) $18 $ – $3 Maturity dates 2008 - 2013 2008 - 2010 2008 - 2013 2008 - 2013

(1) Fair value is equal to the carrying value of these derivatives. (2) Volumes for power and natural gas derivatives are in gigawatt hours and billion cubic feet, respectively. (3) All realized and unrealized gains and losses are included in Net Income. Realized gains are included in Net Income after the financial instrument has been settled. (4) All hedging relationships are designated as cash flow hedges except for $2 million of interest-rate derivative financial instruments designated as fair value hedges. (5) Net Income in 2007 included gains of $7 million for the changes in fair value of power and natural gas cash flow hedges that were ineffective in offsetting the change in fair value of their related underlying positions. Net Income in 2007 included a loss of $4 million for the changes in fair value of an interest-rate cash flow hedge that was reclassified as a result of discontinuance of cash flow hedge accounting. The cash flow hedge accounting was discontinued when the anticipated transaction was not probable of occurring by the end of the originally specified time period. (6) Other Comprehensive Income in 2007 included unrealized gains of $42 million for the change in fair value of cash flow hedges. Attachment 1 CAPP 11 Page 65 of 142 MANAGEMENT’S DISCUSSION AND ANALYSIS 61

Balance Sheet Presentation of Derivative Financial Instruments The fair values of the derivative financial instruments in the Company’s Balance Sheet were as follow:

December 31 (millions of dollars) 2007 Current Other Current Assets 160 Accounts Payable (144)

Long-term Other Assets 204 Deferred Amounts (205)

OTHER RISKS

Development Projects and Acquisitions TransCanada continues to focus on growing its Pipelines and Energy operations through greenfield projects and acquisitions. TransCanada capitalizes costs incurred on certain of its greenfield development projects during the period prior to construction when the project meets specific criteria and is expected to proceed through to completion. The related capital costs of a project that does not proceed through to completion would be expensed at the time it is discontinued. There is a risk with respect to TransCanada’s acquisition of existing assets and operations that certain commercial opportunities and operational synergies may not materialize as expected.

Health, Safety and Environment Risk Management TransCanada is committed to providing a safe and healthy environment for its employees, contractors and the public, and to protecting the environment. Health, safety and environment (HS&E) is a priority in all of TransCanada’s operations and the Company is committed to ensuring it is in conformance with its internal policies and regulated requirements, and is an industry leader. The HS&E Committee of TransCanada’s Board of Directors monitors conformance with TransCanada’s HS&E corporate policy through regular reporting. TransCanada’s HS&E management system is modeled to the elements of the International Organization of Standardization (ISO) standard for environmental management systems, ISO 14001, and focuses resources on the areas of significant risk to the organization’s HS&E business activities. Management is regularly advised of all important HS&E operational issues and initiatives by way of formal reporting processes. TransCanada’s HS&E management system and performance are assessed by an independent outside firm every three years or more often if requested by the HS&E Committee. The most recent assessment was conducted in November 2006. These assessments involve senior management and employee interviews, review of policies, procedures, objectives, performance measurement and reporting.

Health and Safety In 2007, employee and contractor health and safety performance continued to improve relative to previous years and benchmarked within the top level of industry peers. The Company’s assets were highly reliable in 2007 and there were no incidents that were material to the Company’s operations. Under the approved regulatory models in Canada, pipeline integrity expenditures on NEB-and AUC-regulated pipelines are treated on a flow-through basis and, as a result, have no impact on TransCanada’s earnings. The Company expects to spend approximately $120 million in 2008 for pipeline integrity on its wholly owned pipelines, which is slightly higher than the amount spent in 2007, reflecting the acquisition of ANR and slightly increased spending in Canada. Spending associated with public safety on the Energy assets is focused primarily on hydro dams and associated equipment, and is consistent with previous years. Attachment 1 CAPP 11 Page 66 of 142 62 MANAGEMENT’S DISCUSSION AND ANALYSIS

Environment TransCanada’s operations are subject to various environmental laws and regulations that establish compliance and remediation obligations. There are no outstanding orders, material claims or lawsuits against the Company in relation to the release or discharge of any material into the environment or in connection with environmental protection. The Company believes that it has established appropriate reserves, where required, for environmental liabilities. Environmental risks from TransCanada’s facilities typically include air emissions such as nitrogen oxides (NOx), particulate matter and greenhouse gases, potential land impacts, including land reclamation following construction, releases, chemical and hydrocarbon storage, and waste management control to minimize hazardous wastes, and water impacts such as water discharge. TransCanada utilizes a risk-based environmental assessment approach. All businesses are assessed annually and specific facilities, installations and activities are reviewed on a one- to three-year cycle, depending on the Company’s assessment of risk. Business and/or facility inspections are completed on a monthly, quarterly or annual basis, depending on the entity and the assessment of risk. There were no materially significant environmental matters arising from these assessments conducted during 2007. Climate change policy continues to evolve at regional, national and international levels. Under the Specified Gas Emitters Regulation, as of July 1, 2007, industrial facilities in Alberta are required to reduce their greenhouse gas emissions intensities by 12 per cent. TransCanada’s Alberta-based facilities are subject to this regulation, which also extends to the Sundance and Sheerness facilities with which the Company has PPAs. Plans have been developed to manage the costs of compliance incurred by these assets. The regulation is not expected to have a material impact on the Company’s results. Compliance costs related to the Alberta System are expected to be recovered through tolls paid by customers. Recovery of compliance costs related to the Company’s power generation facilities in Alberta is dependent ultimately on market prices for electricity. The Company recorded a charge of $14 million for the period from July 1, 2007 to December 31, 2007 related to the new Alberta environmental regulation. A hydrocarbon royalty tax took effect in Quebec´ on October 1, 2007 and is expected to affect mainly the Becancour´ power generation facility. A regulatory proceeding is under way to determine the method of collecting the tax. The Company recorded a charge of $2 million for the period October 1, 2007 to December 31, 2007 for Quebec´ royalties. British Columbia recently announced a carbon tax, with an effective date of July 2008, which is expected to be applied to fuel usage at the Company’s pipeline compressor facilities in that province. The specifics of the application of the tax are still being assessed. Compliance costs related to this tax are anticipated to be recovered through tolls paid by customers. The Government of Canada released in April 2007 the Regulatory Framework for Air Emissions (Framework). The Framework outlines short-, medium- and long-term objectives for managing both greenhouse gas emissions and air pollutants in Canada. The Company expects a number of its facilities will be affected by pending Federal climate change regulations that will be put in place to meet the Framework’s objectives. It is unknown at this time whether the impacts from the pending regulations will be material as the final form of compliance options is still evolving. Climate change legislation is evolving at both the federal and state levels in the U.S. The Company expects a number of its facilities could be affected by these legislative initiatives, but timing and specific policy objectives remain uncertain. The Company continues to be involved in discussions with governments in jurisdictions where TransCanada has operations and where climate change policy is under development. TransCanada is also continuing its programs to manage greenhouse gas emissions from its facilities and to evaluate new processes and technologies that result in improved efficiencies and lower greenhouse gas emission rates. The Company also incorporates compliance costs associated with environmental regulations as part of its normal assessment of existing operations and new growth opportunities. Attachment 1 CAPP 11 Page 67 of 142 MANAGEMENT’S DISCUSSION AND ANALYSIS 63

CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures Disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed in reports filed with or submitted to, securities regulatory authorities is recorded, processed, summarized and reported within the time periods specified under Canadian and U.S. securities laws. The information is accumulated and communicated to management, including the President and Chief Executive Officer and the Chief Financial Officer, to allow timely decisions regarding required disclosure. As at December 31, 2007, an evaluation was carried out under the supervision of and with the participation of management, including the President and Chief Executive Officer and Chief Financial Officer, of the effectiveness of TransCanada’s disclosure controls and procedures as defined under the rules adopted by the Canadian securities regulatory authorities and by the SEC. Based on this evaluation, the President and Chief Executive Officer and the Chief Financial Officer concluded that the design and operation of TransCanada’s disclosure controls and procedures were effective as at December 31, 2007.

Management’s Annual Report on Internal Control over Financial Reporting Internal control over financial reporting is a process designed by or under the supervision of senior management, and effected by the Board of Directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and preparation of consolidated financial statements for external purposes in accordance with Canadian GAAP, including a reconciliation to U.S. GAAP. Management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting, no matter how well designed, has inherent limitations and can only provide reasonable assurance with respect to the preparation and fair presentation of published financial statements. Under the supervision and with the participation of the President and Chief Executive Officer and the Chief Financial Officer, management conducted an evaluation of the effectiveness of its internal control over financial reporting based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. In 2007, the Company acquired ANR and began consolidating the operations of ANR into the Company. Management excluded this business from its evaluation of the effectiveness of the Company’s internal control over financial reporting as at December 31, 2007. The net income attributable to this business represented approximately nine per cent of the Company’s consolidated net income in 2007, and its aggregate total assets represented approximately 12 per cent of the Company’s consolidated total assets as at December 31, 2007. Based on this evaluation, management concluded that internal control over financial reporting is effective as at December 31, 2007, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external reporting purposes. In 2007, there was no change in TransCanada’s internal control over financial reporting that materially affected or is reasonably likely to materially affect TransCanada’s internal control over financial reporting.

CEO and CFO Certifications TransCanada’s President and Chief Executive Officer has provided the New York Stock Exchange with the annual CEO certification for 2007 regarding TransCanada’s compliance with the New York Stock Exchange’s corporate governance listing standards applicable to foreign issuers. In addition, TransCanada’s President and Chief Executive Officer and Chief Financial Officer have filed with the SEC and the Canadian securities regulators certifications regarding the quality of TransCanada’s public disclosures relating to its fiscal 2007 reports filed with the SEC and the Canadian securities regulators. Attachment 1 CAPP 11 Page 68 of 142 64 MANAGEMENT’S DISCUSSION AND ANALYSIS

SIGNIFICANT ACCOUNTING POLICIES AND CRITICAL ACCOUNTING ESTIMATES

To prepare financial statements that conform with Canadian GAAP, TransCanada is required to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses. The Company uses the most current information available and exercises careful judgment in making these estimates and assumptions.

Regulated Accounting The Company accounts for the impacts of rate regulation in accordance with GAAP. Three criteria must be met to use these accounting principles: the rates for regulated services or activities must be subject to approval by a regulator; the regulated rates must be designed to recover the cost of providing the services or products; and it must be reasonable to assume that rates set at levels to recover the cost can be charged to and will be collected from customers in view of the demand for services or products and the level of direct and indirect competition. The Company’s management believes that all three of these criteria have been met with respect to each of the regulated natural gas pipelines accounted for using regulated accounting principles. The most significant impact from the use of these accounting principles is that, in order to appropriately reflect the economic impact of the regulators’ decisions regarding the Company’s revenues and tolls, and to thereby achieve a proper matching of revenues and expenses, the timing of recognition of certain expenses and revenues in the regulated businesses may differ from that otherwise expected under GAAP.

Financial Instruments Effective January 1, 2007, the Company adopted the new Canadian Institute of Chartered Accountants (CICA) Handbook accounting requirements for Section 3855 ‘‘Financial Instruments – Recognition and Measurement’’ and Section 3865 ‘‘Hedges’’. The CICA Handbook requirements for Section 3862 ‘‘Financial Instruments – Disclosure’’ and Section 3863 ‘‘Financial Instruments – Presentation’’ are effective January 1, 2008, however the Company chose to adopt these standards effective December 31, 2007. These standards are described further in the ‘‘Risk Management and Financial Instruments’’ and ‘‘Accounting Changes’’ sections of this MD&A.

Depreciation and Amortization Expense TransCanada’s plant, property and equipment are depreciated on a straight-line basis over their estimated useful lives. Pipeline and compression equipment are depreciated at annual rates ranging from two per cent to six per cent. Metering and other plant equipment are depreciated at various rates. Major power generation and natural gas storage plant, equipment and structures in the Energy business are depreciated on a straight-line basis over estimated service lives at average annual rates ranging from two per cent to ten per cent. Nuclear power generation assets under capital lease are amortized on a straight-line basis over the shorter of their useful life and the remaining terms of their lease. Other equipment is depreciated at various rates. Corporate plant, property and equipment are depreciated on a straight-line basis over estimated useful lives at average annual rates ranging from three to 20 per cent. Depreciation expense in 2007 was $1,179 million (2006 – $1,059 million) and primarily affects the Pipelines and Energy segments of the Company. In Pipelines, depreciation rates are approved by regulators where applicable and depreciation expense is recoverable based on the cost of providing the services or products. If regulators permit recovery through rates, a change in the estimate of the useful lives of plant, property and equipment in the Pipelines segment would have no material impact on TransCanada’s net income but would directly affect funds generated from operations.

ACCOUNTING CHANGES

Changes in Accounting Policies for 2007 Effective January 1, 2007, the Company adopted the CICA Handbook accounting requirements for Sections 1506 ‘‘Accounting Changes’’, 1530 ‘‘Comprehensive Income’’, 3251 ‘‘Equity’’, 3855 ‘‘Financial Instruments – Recognition and Attachment 1 CAPP 11 Page 69 of 142 MANAGEMENT’S DISCUSSION AND ANALYSIS 65

Measurement’’, and 3865 ‘‘Hedges’’. In addition, the Company chose to adopt the accounting requirements for Sections 3862 ‘‘Financial Instruments – Disclosure’’, 3863 ‘‘Financial Instruments – Presentation’’ and 1535 ‘‘Capital Disclosures’’ at December 31, 2007, as well as the accounting requirements for Section 3031 ‘‘Inventories’’ at April 1, 2007. Adjustments to the consolidated financial statements for 2007 have been made in accordance with the transitional provisions for these new standards.

Comprehensive Income and Equity The Company’s financial statements include statements of Consolidated Comprehensive Income and Consolidated Accumulated Other Comprehensive Income. In addition, as required in CICA Handbook Section 3251, the Company now presents separately, in the Consolidated Shareholders’ Equity statement, the changes for each of its components of Shareholders’ Equity, including Accumulated Other Comprehensive Income.

Financial Instruments All financial instruments must initially be included on the balance sheet at their fair value. Subsequent measurement of the financial instruments is based on their classification. Financial assets are classified into the following categories: held for trading, available for sale, held-to-maturity investments and loans and receivables. Financial liabilities are classified as held for trading or other financial liabilities. Held-for-trading financial assets and liabilities consist of swaps, options, forwards and futures, and are entered into with the intention of generating a profit. A financial asset or liability that does not meet this criterion may also be designated as held for trading. Power and natural gas held-for-trading instruments are initially recorded at their fair value and changes to fair value are included in Revenues. Changes in the fair value of interest rate and foreign exchange held-for-trading instruments are recorded in Financial Charges and in Interest Income and Other, respectively. The Company had not designated any financial assets or liabilities as held for trading at December 31, 2007. The available-for-sale classification includes non-derivative financial assets that are designated as available for sale or are not included in the other three classifications. TransCanada’s available-for-sale financial instruments include fixed-income securities held for self-insurance. These instruments are initially accounted for at their fair value and changes to fair value are recorded through Other Comprehensive Income. Income from the settlement of available-for-sale financial assets will be included in Interest Income and Other. Held-to-maturity financial assets are accounted for at their amortized cost using the effective interest method. The Company did not have any held-to-maturity financial assets at December 31, 2007. Trade receivables, loans and other receivables with fixed or determinable payments that are not quoted in an active market are classified as ‘‘loans and receivables’’ and are measured net of any impairment. Loans and receivables include primarily trade accounts receivable and non-interest-bearing third-party loans receivable. Interest and other income earned from these financial assets are recorded in Interest Income and Other. Other financial liabilities consist of liabilities not classified as held for trading. Interest expense is included in Financial Charges and in Financial Charges of Joint Ventures. Items in this financial instrument category are recognized at amortized cost using the effective interest method. All derivatives are recorded on the balance sheet at fair value, with the exception of those that were entered into and continue to be held for the purpose of receipt or delivery in accordance with the Company’s expected purchase, sale or usage requirements (normal purchase and normal sale exemption). Changes in the fair value of derivatives that are not designated in a hedging relationship are recorded in Net Income. Derivatives used in hedging relationships are discussed further under the heading Hedges in this section. Derivatives embedded in other financial instruments or contracts (the host instrument) are recorded as separate derivatives and are measured at fair value if the economic characteristics of the embedded derivative are not closely Attachment 1 CAPP 11 Page 70 of 142 66 MANAGEMENT’S DISCUSSION AND ANALYSIS

related to the host instrument, the terms of the embedded derivative are the same as those of a stand-alone derivative and the total contract is not held for trading or accounted for at fair value. Changes in the fair value of embedded derivates that are recorded separately are included in Revenues. The Company used January 1, 2003 as the transition date for embedded derivatives. Transaction costs are incremental costs that are directly attributable to the acquisition, issue or disposal of a financial instrument. Effective January 1, 2007, the Company began offsetting long-term debt transaction costs against the associated debt and began amortizing these costs using the effective interest method. Previously, these costs were amortized on a straight-line basis over the life of the debt. There was no material impact on the Company’s financial statements as a result of this change in policy. In 2007, the impact on Net Income for the amortization of transaction costs using the effective interest method was nominal. The Company records the fair values of material joint and several guarantees. These fair values cannot be readily obtained from an open market and therefore, the fair value of these guarantees is estimated by discounting the cash flows that would be incurred by the Company if letters of credit were used in place of the guarantees. Guarantees are recorded as an increase to an investment account, Property, Plant and Equipment or a charge to Net Income, and a corresponding liability in Deferred Amounts.

Hedges Section 3865 specifies the criteria that must be satisfied in order to apply hedge accounting and the accounting for each of the permitted hedging strategies, including: fair value hedges, cash flow hedges and hedges of foreign currency exposures of net investments in self-sustaining foreign operations. Hedge accounting is discontinued prospectively when the derivative no longer qualifies as an effective hedge or is terminated or sold, or upon the sale or early termination of the hedged item. Documentation must be prepared at the inception of the hedging arrangement in order to qualify for hedge accounting treatment. In addition, the Company must perform an assessment of effectiveness at inception of the contract and at each reporting date. In a fair value hedging relationship, the carrying value of the hedged item is adjusted for changes in fair value attributable to the hedged risk. The changes in fair value are recognized in Net Income. Changes in the fair value of the hedged item, to the extent that the hedging relationship is effective, are offset by changes in the fair value of the hedging item, which is also recorded in Net Income. Changes in the fair value of foreign exchange and interest rate hedges are recorded in Interest Income and Other and Financial Charges, respectively. When hedge accounting is discontinued, the carrying value of the hedged item is no longer adjusted and the cumulative fair value adjustments to the carrying value of the hedged item are amortized to Net Income over the remaining term of the original hedging relationship. In a cash flow hedging relationship, the effective portion of the change in the fair value of the hedging derivative is recognized in Other Comprehensive Income, while any ineffective portion is recognized in Net Income in the same financial category as the underlying transaction. When hedge accounting is discontinued, the amounts recognized previously in Accumulated Other Comprehensive Income are reclassified to Net Income during the periods when the variability in cash flows of the hedged item affects Net Income. Gains and losses on derivatives are reclassified immediately to Net Income when the hedged item is sold or terminated early, or when a hedged anticipated transaction is no longer expected to occur. The Company also enters into cash flow hedges and fair value hedges for activities subject to rate regulation. The gains and losses arising from the changes in fair value of these hedges can be recovered through the tolls charged by the Company. As a result, these gains and losses are deferred as rate-regulated assets or liabilities on behalf of the ratepayers. When the hedges are settled, the realized gains or losses are collected from or refunded to the ratepayers in subsequent years. Attachment 1 CAPP 11 Page 71 of 142 MANAGEMENT’S DISCUSSION AND ANALYSIS 67

In hedging the foreign currency exposure of a net investment in a self-sustaining foreign operation, the effective portion of foreign exchange gains and losses on the hedging instruments is recognized in Other Comprehensive Income and the ineffective portion is recognized in Net Income. The amounts recognized previously in Accumulated Other Comprehensive Income are recognized in Net Income in the event the Company settles or otherwise reduces its investment.

Net Effect of Accounting Policy Changes The net effect of the preceding accounting policy changes on the Company’s financial statements at January 1, 2007 was as follows:

Increases/(decreases) (millions of dollars) Other current assets (127) Other assets (203) Accounts payable (29) Deferred amounts (75) Future income taxes (42) Long-term debt (85) Long-term debt of joint ventures (7) Accumulated other comprehensive income (96) Retained earnings 4

The primary changes in 2007 to the Company’s accounting policies for financial instruments related to the requirements to record certain non-financial contracts at their fair value and to offset transaction costs against long-term debt.

Section 3862 Financial Instruments – Disclosures and Section 3863 Financial Instruments – Presentation CICA Handbook Sections 3862 ‘‘Financial Instruments – Disclosure’’ and 3863 ‘‘Financial Instruments – Presentation’’, which replaced Section 3861 ‘‘Financial Instruments – Disclosure and Presentation’’, are effective January 1, 2008. However, the Company chose to adopt these standards effective December 31, 2007. The Company’s December 31, 2007 financial statements provided the additional disclosure necessary to comply with these standards.

Section 1535 Capital Disclosures CICA Handbook Section 1535 ‘‘Capital Disclosures’’ is effective for fiscal years beginning on or after October 1, 2007, however, TransCanada chose to adopt this standard effective December 31, 2007. The Company has provided qualitative disclosure regarding objectives, policies and processes for managing capital as well as quantitative data of capital as of December 31, 2007 in the ‘‘Risk Management and Financial Instruments’’ section of this MD&A.

Proprietary Natural Gas Inventories and Revenue Recognition CICA Handbook Section 3031 ‘‘Inventories’’ is effective January 1, 2008. However, the Company chose to adopt this standard effective April 1, 2007, and began valuing its proprietary natural gas inventory held in storage at fair value, as measured by the one-month forward price for natural gas. To record inventory at fair value, TransCanada has designated its natural gas storage business as a broker/trader business that purchases and sells natural gas on a back-to-back basis. TransCanada did not have any proprietary natural gas inventory prior to April 1, 2007. The Company records its proprietary natural gas storage results in Revenues net of Commodity Purchases Resold. All changes in the fair value of the proprietary natural gas inventories are reflected in Inventories and Revenues. Attachment 1 CAPP 11 Page 72 of 142 68 MANAGEMENT’S DISCUSSION AND ANALYSIS

Future Accounting Changes

Rate-Regulated Operations Effective January 1, 2009, the temporary exemption from CICA Handbook Section 1100, ‘‘Generally Accepted Accounting Principles’’, which permits the recognition and measurement of assets and liabilities arising from rate regulation, will be withdrawn. In addition, Section 3465 ‘‘Income Taxes’’ was amended to require the recognition of future income tax liabilities and assets. As a result of the changes, TransCanada will be required to recognize future income tax liabilities and assets instead of using the taxes payable method, and will record an offsetting adjustment to regulatory assets and liabilities. If the liability method of accounting had been used at December 31, 2007, additional future income tax liabilities in the amount of $1,138 million would have been recorded and would have been recoverable from future revenue. These changes will be applied prospectively beginning January 1, 2009.

International Financial Reporting Standards The CICA’s Accounting Standards Board (AcSB) announced that Canadian publicly accountable enterprises will adopt International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB), effective January 1, 2011. IFRS will require increased financial statement disclosure. Although IFRS uses a conceptual framework similar to Canadian GAAP, differences in accounting policies will need to be addressed. TransCanada is currently assessing the impact of this AcSB announcement on its financial statements.

Intangible Assets The CICA Handbook implemented revisions to standards dealing with Intangible Assets effective for fiscal years beginning on or after October 1, 2008. The revisions are intended to align the definition of an Intangible Asset in Canadian GAAP with that in IFRS and U.S. GAAP. Section 1000 ‘‘Financial Statement Concepts’’ was revised to remove material that permitted the recognition of assets that might not otherwise meet the definition of an asset and to add guidance from the IASB’s ‘‘Framework for the Preparation and Presentation of Financial Statements’’ that will help distinguish assets from expenses. Section 3064 ‘‘Goodwill and Intangible Assets’’, which replaced Section 3062 ‘‘Goodwill and Other Intangible Assets’’, gives guidance on the recognition of intangible assets as well as the recognition and measurement of internally developed intangible assets. Section 3450 ‘‘Research and Development Costs’’ will be withdrawn from the Handbook. The Company does not expect these changes to have a material effect on its financial statements. Attachment 1 CAPP 11 Page 73 of 142 MANAGEMENT’S DISCUSSION AND ANALYSIS 69

SELECTED QUARTERLY CONSOLIDATED FINANCIAL DATA(1) 2007 (millions of dollars except per share amounts) Fourth Third Second First Revenues 2,189 2,187 2,208 2,244 Net Income Continuing operations 377 324 257 265 Discontinued operations –––– 377 324 257 265 Share Statistics Net income per share – Basic Continuing operations $0.70 $0.60 $0.48 $0.52 Discontinued operations –––– $0.70 $0.60 $0.48 $0.52 Net income per share – Diluted Continuing operations $0.70 $0.60 $0.48 $0.52 Discontinued operations –––– $0.70 $0.60 $0.48 $0.52 Dividend declared per common share $0.34 $0.34 $0.34 $0.34

2006 (millions of dollars except per share amounts) Fourth Third Second First Revenues 2,091 1,850 1,685 1,894 Net Income Continuing operations 269 293 244 245 Discontinued operations – – – 28 269 293 244 273 Share Statistics Net income per share – Basic Continuing operations $0.55 $0.60 $0.50 $0.50 Discontinued operations – – – 0.06 $0.55 $0.60 $0.50 $0.56 Net income per share – Diluted Continuing operations $0.54 $0.60 $0.50 $0.50 Discontinued operations – – – 0.06 $0.54 $0.60 $0.50 $0.56 Dividend declared per common share $0.32 $0.32 $0.32 $0.32

(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. Attachment 1 CAPP 11 Page 74 of 142 70 MANAGEMENT’S DISCUSSION AND ANALYSIS

Factors Impacting Quarterly Financial Information In Pipelines, which consists primarily of the Company’s investments in regulated pipelines and regulated natural gas storage facilities, 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 resulting from adjustments being recorded due to regulatory decisions and negotiated settlements with shippers, seasonal fluctuations in short-term throughput volumes on U.S. pipelines, acquisitions and divestitures, and developments outside of the normal course of operations. In Energy, which consists primarily of the Company’s investments in electrical power generation plants and non-regulated 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, acquisitions and divestitures, and developments outside of the normal course of operations. Significant developments that affected quarterly net earnings in 2007 and 2006 were as follow: • First-quarter 2006 net earnings included proceeds of $18-million after tax ($29-million pre-tax) from a bankruptcy settlement with a former shipper on the GTN System. • Second-quarter 2006 net earnings included $33 million of future income tax benefits as a result of reductions in Canadian federal and provincial corporate income tax rates. Net earnings also included a $13-million after-tax gain related to the sale of the Company’s interest in Northern Border Partners, L.P. • Third-quarter 2006 net earnings included an income tax benefit of approximately $50 million as a result of the resolution of certain income tax matters with taxation authorities and changes in estimates. • Fourth-quarter 2006 net earnings included approximately $12 million related to income tax refunds and related interest. • First-quarter 2007 net earnings included $15 million related to positive income tax adjustments. In addition, Pipelines’ net earnings included contributions from the February 22, 2007, acquisition of ANR and an additional ownership interest in Great Lakes. Energy’s net earnings included earnings from the Edson natural gas facility, which was placed in service on December 31, 2006. • Second-quarter 2007 net earnings included $16 million ($4 million in Energy and $12 million in Corporate) related to positive income tax adjustments resulting from reductions in Canadian federal income tax rates. Pipeline’s net earnings increased as a result of a settlement reached on the Canadian Mainline, which was approved by the NEB in May 2007. • Third-quarter 2007 net earnings included $15 million of favourable income tax reassessments and associated interest income relating to prior years. • Fourth-quarter 2007 net earnings included $56 million ($30 million in Energy and $26 million in Corporate) of favourable income tax adjustments resulting from reductions in Canadian federal income tax rates and other legislative changes, and a $14-million ($16 million pre-tax) gain on sale of land previously held for development. Pipelines’ net earnings increased as a result of recording incremental earnings related to the rate case settlement reached for the GTN System, effective January 1, 2007. Attachment 1 CAPP 11 Page 75 of 142 MANAGEMENT’S DISCUSSION AND ANALYSIS 71

FOURTH-QUARTER 2007 HIGHLIGHTS

CONSOLIDATED RESULTS OF OPERATIONS Reconciliation of Comparable Earnings to Net Income (millions of dollars except per share amounts) 2007 2006 Pipelines Net Earnings 202 126

Energy Net Earnings Comparable earnings(1) 114 132 Specific items: Income tax reassessments and adjustments 30 – Gain on sale of land 14 – Net earnings 158 132

Corporate Net Earnings Comparable earnings(1) (9) (1) Specific item: Income tax reassessments and adjustments 26 12 Net earnings 17 11 Net Income 377 269

Net Income per Share Basic $0.70 $0.55 Diluted $0.70 $0.54

Comparable Earnings(1) 307 257 Specific items (net of tax, where applicable): Income tax reassessments and adjustments 56 12 Gain on sale of land 14 – Net Income 377 269

Comparable Earnings per Share(1) $0.57 $0.53 Specific items – per share: Income tax reassessments and adjustments 0.10 0.02 Gain on sale of land 0.03 – Net Income per Share $0.70 $0.55

(1) Refer to the ‘‘Non-GAAP Measures’’ section of this MD&A for further discussion of comparable earnings and comparable earnings per share.

TransCanada’s net income and net earnings in fourth-quarter 2007 were $377 million or $0.70 per share compared to $269 million or $0.55 per share in fourth-quarter 2006, an increase of $108 million or $0.15 per share. The increase reflected the impact of favourable income tax adjustments of $56 million in fourth-quarter 2007 as a result of changes in Canadian federal income tax legislation compared to income tax refunds and related interest of $12 million in fourth-quarter 2006. The increase was also due to additional earnings from the acquisition of ANR in February 2007 and the start-up of the Edson facility in December 2006, the positive impact of the rate case settlements on both the GTN System and the Canadian Mainline, a $14-million after-tax ($16 million pre-tax) gain on the sale of land and lower Attachment 1 CAPP 11 Page 76 of 142 72 MANAGEMENT’S DISCUSSION AND ANALYSIS

operating costs on the Alberta System. Lower realized power prices in Alberta and a lower contribution from Bruce Power partially offset these increases to net earnings in fourth-quarter 2007 compared to fourth-quarter 2006. The per-share net income increase of $0.15 in fourth-quarter 2007 was achieved despite an increased number of shares outstanding following the Company’s share issuances in 2007. Comparable earnings in fourth-quarter 2007 were $307 million or $0.57 per share, compared to $257 million or $0.53 per share in the same period in 2006. Comparable earnings excluded the $56-million and $12-million positive income tax adjustments in fourth-quarter 2007 and fourth-quarter 2006, respectively, as well as the $14-million gain on sale of land in fourth-quarter 2007. In Pipelines, net earnings were $202 million in fourth-quarter 2007, an increase of $76 million from $126 million in the same period in 2006. Additional income from the acquisition of ANR, the positive impact of the rate case settlements on both the Canadian Mainline and the GTN System, and lower operating costs on the Alberta System contributed to higher earnings. Canadian Mainline’s net earnings in fourth-quarter 2007 were $72 million, an increase of $12 million from the corresponding period in 2006. The increase reflected the impact of the five-year rate case settlement on the Canadian Mainline, effective January 1, 2007 to December 31, 2011. Canadian Mainline’s net earnings increased due to certain performance-based incentive arrangements and OM&A cost savings in addition to the positive impact of the increase in deemed common equity ratio in the settlement. Partially offsetting these increases were the negative impacts of a lower allowed ROE of 8.46 per cent in 2007 (2006 – 8.88 per cent) and a lower average investment base. Alberta System’s net earnings in fourth-quarter 2007 were $41 million, an increase of $7 million from the same quarter of 2006. The increase was due mainly to OM&A cost savings, partially offset by a lower investment base as well as a lower allowed ROE in 2007. Earnings in 2007 reflected an ROE of 8.51 per cent compared to 8.93 per cent in 2006, both on deemed common equity of 35 per cent. GTN’s comparable earnings in fourth-quarter 2007 were $32 million, an increase of $25 million from the same period in 2006 due primarily to the positive impact of the rate case settlement. GTN recorded the full-year impact of the rate case settlement in fourth-quarter 2007 upon receipt of FERC approval in January 2008. The positive impact of the rate case settlement on net earnings was partially offset by the impacts of lower long-term firm contracted volumes and a weaker U.S. dollar in 2007 as well as a higher provision taken in 2007 for non-payment of contract revenues from a subsidiary of Calpine that filed for bankruptcy protection. In Energy, fourth-quarter 2007 net earnings were $158 million, an increase of $26 million from $132 million in the same period in 2006. Net earnings in fourth-quarter 2007 included $30 million of positive income tax reassessments and adjustments, a $14-million after-tax ($16 million pre-tax) gain on sale of land, higher prices and volumes at Bruce B, and revenue from the Edson facility, which commenced operation in December 2006. These gains were partially offset by lower overall realized power prices in Western Power as well as lower volumes and increased outage days and related costs at Bruce A. Western Power’s operating income in fourth-quarter 2007 was $58 million, a decrease of $51 million from fourth-quarter 2006. This decrease was due primarily to lower overall realized power prices and lower market heat rates on higher uncontracted volumes of power sold, partially offset by lower PPA costs. Average spot market power prices in Alberta decreased 47 per cent, or $55 per MWh, in fourth-quarter 2007 compared to fourth-quarter 2006. The power price decrease was also the main contributor to a decrease of approximately 43 per cent in market heat rates, partially offset by an 11 per cent, or $0.73 per GJ, decrease in average spot market natural gas prices in Alberta in fourth-quarter 2007 compared to the same quarter in 2006. Eastern Power’s operating income in fourth-quarter 2007 was $66 million, an increase of $11 million from the same period in 2006. The increase was due primarily to payments received under the newly-designed FCM in New England and increased earnings from higher sales volumes to commercial and industrial customers. These positive impacts were Attachment 1 CAPP 11 Page 77 of 142 MANAGEMENT’S DISCUSSION AND ANALYSIS 73

partially offset by decreased power generation from the TC Hydro facilities compared with fourth-quarter 2006 when water flows were above normal. Operating income from Bruce Power in fourth-quarter 2007 was $43 million, a decrease of $16 million from fourth- quarter 2006. The decrease was due to lower power generation volumes and higher operating costs related to the significant increase in planned outage days at Bruce A as well as higher post-employment benefit costs and lower positive purchase price amortizations related to the expiry of power sales agreements. These negative impacts were partially offset by higher realized prices, higher power generation volumes and lower operating costs as a result of fewer planned outage days at Bruce B. Natural Gas Storage operating income in fourth-quarter 2007 was $57 million, an increase of $27 million from fourth-quarter 2006 due primarily to income earned from the Edson facility, which commenced operation in December 2006. Operating income in fourth-quarter 2007 included a $15-million net unrealized gain from the changes in fair value of proprietary natural gas inventory, forward purchase contracts and forward sale contracts. Corporate net earnings in fourth-quarter 2007 were $17 million compared to $11 million in the same period in 2006. The increase was due primarily to $26 million of favourable income tax adjustments arising from legislated Canadian corporate income tax changes in fourth-quarter 2007, compared to $12 million in income tax refunds and related interest in the same period in 2006. Gains on derivatives used to manage the Company’s exposure to foreign exchange rate fluctuations and the impact of positive tax rate differentials also contributed to higher net earnings. However, these gains were more than offset by higher financial charges, resulting primarily from financing the acquisitions of ANR and additional interest in Great Lakes. Corporate’s comparable expenses were $9 million in fourth-quarter 2007 compared with $1 million in the same period in 2006, excluding the favourable income tax adjustments in the two periods.

SHARE INFORMATION

At February 25, 2008, TransCanada had 541.4 million issued and outstanding common shares. In addition, there were 9.2 million outstanding options to purchase common shares, of which 6.2 million were exercisable as at February 25, 2008.

OTHER INFORMATION

Additional information relating to TransCanada, including the Company’s Annual Information Form and other continuous disclosure documents, is available on SEDAR at www.sedar.com under TransCanada Corporation. Other selected consolidated financial information for the years 2000 to 2007 is found under the heading ‘‘Eight-Year Financial Highlights’’ in the Supplementary Information section of the Company’s Annual Report. Attachment 1 CAPP 11 Page 78 of 142 74 MANAGEMENT’S DISCUSSION AND ANALYSIS

GLOSSARY OF TERMS

AGIA Alaska Gasline Inducement Act Keystone U.S. TransCanada Keystone Pipeline LP ANR American Natural Resources Company km Kilometres and ANR Storage Company, collectively LIBOR London Interbank Offered Rate ANR Pipeline ANR Pipeline Company LNG Liquefied natural gas APG Aboriginal Pipeline Group MD&A Management’s Discussion and Analysis AUC Alberta Utilities Commission MGP Mackenzie Gas Pipeline B.C. British Columbia Mirant Mirant Corporation and certain of its Bbl/d Barrels per day subsidiaries Bcf Billion cubic feet mmcf/d Million cubic feet per day Bcf/d Billion cubic feet per day Moody’s Moody’s Investors Service BPC BPC Generation Infrastructure Trust MW Megawatt Broadwater Broadwater LNG project MWh Megawatt hours Bruce A Bruce Power A L.P. NEB National Energy Board Bruce B Bruce Power L.P. Net earnings Net income from continuing operations Bruce Power Bruce A and Bruce B, collectively NGL Natural gas liquid Cacouna Cacouna LNG project NGTL NOVA Gas Transmission Ltd. Calpine Calpine Corporation Cameco Cameco Corporation Northern Border Northern Border Pipeline Company CAPLA Canadian Alliance of Pipeline NPA Northern Pipeline Act of Canada Landowners’ Associations NW Natural Northwest Natural Gas Company CPUC California Public Utilities Commision OM&A Operating, maintenance and CrossAlta CrossAlta Gas Storage & Services Ltd. administration DRP Dividend Reinvestment and Share OPA Ontario Power Authority Purchase Plan OSP Ocean State Power EPCOR EPCOR Utilities Inc. Paiton Energy P.T. Paiton Energy Company EUB Alberta Energy and Utilities Board Palomar Palomar Gas Transmission LLC FCM Forward Capacity Market PG&E Pacific Gas & Electric Company FEIS Final Environmental Impact Statement PipeLines LP TC PipeLines, LP FERC Federal Energy Regulatory Commission Portland Portland Natural Gas Transmission Foothills Foothills Pipe Lines Ltd. System FT Firm transportation Portlands Energy Portlands Energy Centre L.P. GAAP Generally accepted accounting principles Power LP TransCanada Power, L.P. Gas Pacifico Gasoducto del Pacifico S.A. PPA Power purchase arrangement GJ Gigajoule ROE Rate of return on common equity GRA General Rate Application SEC U.S. Securities and Exchange Great Lakes Great Lakes Gas Transmission Limited Commission Partnership TCPL TransCanada PipeLines Limited GTN GTN System and North Baja, collectively TCPM TransCanada Power Marketing Ltd. GTNC Gas Transmission Northwest Corporation TQM Trans Quebec´ & Maritimes System GWh Gigawatt hours TransCanada or TransCanada Corporation the Company Halton Hills Halton Hills Generating Station TransGas TransGas de Occidente S.A. INNERGY INNERGY Holdings S.A. Tuscarora Tuscarora Gas Transmission Company Iroquois Iroquois Gas Transmission System, L.P. Keystone Keystone Canada and Keystone U.S., U.S. United States collectively Ventures LP TransCanada Pipeline Ventures Limited Keystone TransCanada Keystone Pipeline Limited Partnership Canada Partnership WCSB Western Canada Sedimentary Basin Attachment 1 CAPP 11 Page 79 of 142 TRANSCANADA CORPORATION 75

The consolidated financial statements included in this Annual Report are the responsibility of TransCanada Corporation’s management and have been approved by the Board of Directors of the Company. These consolidated financial statements have been prepared by management in accordance with generally accepted accounting principles (GAAP) in Canada Report of and include amounts that are based on estimates and judgments. Financial information contained elsewhere in this Annual Report is consistent with the consolidated financial Management statements. Management’s Discussion and Analysis in this Annual Report has been prepared by management based on the Company’s financial results prepared in accordance with Canadian GAAP. It compares the Company’s financial performance in 2007 to that in 2006 and should be read in conjunction with the consolidated financial statements and accompanying notes. In addition, it highlights significant changes between 2006 and 2005. Management has designed and maintains a system of internal accounting controls, including a program of internal audits. Management believes that these controls provide reasonable assurance that financial records are reliable and form a proper basis for preparation of financial statements. The internal accounting control process includes management’s communication to employees of policies that govern ethical business conduct. Under the supervision and with the participation of the President and Chief Executive Officer and the Chief Financial Officer, management conducted an evaluation of the effectiveness of its internal control over financial reporting based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. TransCanada acquired American Natural Resources Company and ANR Storage Company (collectively, ANR) in 2007 and began consolidating the operations of ANR into the Company. Management has excluded this business from its evaluation of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2007. The net income attributable to this business represented approximately nine per cent of the Company’s consolidated net income for the year ended December 31, 2007, and their aggregate total assets represented approximately 12 per cent of the Company’s consolidated total assets as at December 31, 2007. Based on their evaluation, management concluded that internal control over financial reporting is effective as of December 31, 2007 to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external reporting purposes. The Board of Directors has appointed an Audit Committee consisting of unrelated, non-management directors. The Audit Committee meets at least six times a year with management and meets independently with each of the internal and external auditors and as a group to review any significant accounting, internal control and auditing matters in accordance with the terms of the charter of the Audit Committee as set out in the Annual Information Form. The Audit Committee reviews the Annual Report, including the consolidated financial statements, before the consolidated financial statements are submitted to the Board of Directors for approval. The internal and external auditors have free access to the Audit Committee without obtaining prior management approval. The Audit Committee approves the terms of engagement of the independent external auditors and reviews the annual audit plan, the Auditors’ Report and results of the audit. It also recommends to the Board of Directors the firm of external auditors to be appointed by the shareholders. The shareholders have appointed KPMG LLP as independent external auditors to express an opinion as to whether the consolidated financial statements present fairly, in all material respects, the Company’s consolidated financial position, results of operations and cash flows in accordance with Canadian GAAP. The report of KPMG LLP outlines the scope of its examination and its opinion on the consolidated financial statements.

Harold N. Kvisle Gregory A. Lohnes President and Executive Vice-President and Chief Executive Officer Chief Financial Officer February 25, 2008 Attachment 1 CAPP 11 Page 80 of 142 76 CONSOLIDATED FINANCIAL STATEMENTS

To the Shareholders of TransCanada Corporation We have audited the consolidated balance sheets of TransCanada Corporation as at December 31, 2007 and 2006, and the consolidated statements of income, comprehensive Auditors’ income, accumulated other comprehensive income, shareholders’ equity and cash flows for each of the years in the three-year period ended December 31, 2007. These financial Report statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards. With respect to the consolidated financial statements for the years ended December 31, 2007 and 2006, we also conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 2007 and 2006 and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2007 in accordance with Canadian generally accepted accounting principles.

Chartered Accountants Calgary, Canada

February 25, 2008 Attachment 1 CAPP 11 Page 81 of 142 CONSOLIDATED FINANCIAL STATEMENTS 77

TRANSCANADA CORPORATION CONSOLIDATED INCOME

Year ended December 31 (millions of dollars except per share amounts) 2007 2006 2005 Revenues 8,828 7,520 6,124 Operating Expenses Plant operating costs and other 3,030 2,411 1,825 Commodity purchases resold 1,959 1,707 1,232 Depreciation 1,179 1,059 1,017 6,168 5,177 4,074 2,660 2,343 2,050

Other Expenses/(Income) Financial charges (Note 9) 943 825 836 Financial charges of joint ventures (Note 10) 75 92 66 Income from equity investments (Note 7) (17) (33) (247) Interest income and other (135) (123) (63) Gains on sales of assets (Note 8) (16) (23) (445) 850 738 147

Income from Continuing Operations before Income Taxes and Non-Controlling Interests 1,810 1,605 1,903

Income Taxes (Note 18) Current 432 301 550 Future 58 175 60 490 476 610 Non-Controlling Interests (Note 15) 97 78 84 Net Income from Continuing Operations 1,223 1,051 1,209 Net Income from Discontinued Operations (Note 24) – 28 – Net Income 1,223 1,079 1,209

Net Income per Share (Note 16) Basic Continuing operations $2.31 $2.15 $2.49 Discontinued operations – 0.06 – $2.31 $2.21 $2.49 Diluted Continuing operations $2.30 $2.14 $2.47 Discontinued operations – 0.06 – $2.30 $2.20 $2.47

The accompanying notes to the consolidated financial statements are an integral part of these statements. Attachment 1 CAPP 11 Page 82 of 142 78 CONSOLIDATED FINANCIAL STATEMENTS

TRANSCANADA CORPORATION CONSOLIDATED CASH FLOWS

Year ended December 31 (millions of dollars) 2007 2006 2005 Cash Generated from Operations Net income 1,223 1,079 1,209 Depreciation 1,179 1,059 1,017 Income from equity investments in excess of distributions received (Note 7) (1) (9) (71) Future income taxes (Note 18) 58 175 60 Non-controlling interests (Note 15) 97 78 84 Employee future benefits funding lower than/(in excess of) expense (Note 21) 43 (31) (9) Gains on sales of assets, net of current income taxes (Note 8) (14) (11) (318) Other 36 38 (21) 2,621 2,378 1,951 Decrease/(increase) in operating working capital (Note 22) 215 (303) (49) Net cash provided by operations 2,836 2,075 1,902 Investing Activities Capital expenditures (1,651) (1,572) (754) Acquisitions, net of cash acquired (Note 8) (4,223) (470) (1,317) Disposition of assets, net of current income taxes (Note 8) 35 23 671 Deferred amounts and other (368) (97) 64 Net cash used in investing activities (6,207) (2,116) (1,336) Financing Activities Dividends on common shares (Note 16) (546) (617) (586) Distributions paid to non-controlling interests (88) (72) (74) Notes payable (repaid)/issued, net (46) (495) 416 Long-term debt issued 2,631 2,107 799 Reduction of long-term debt (1,088) (729) (1,113) Long-term debt of joint ventures issued 142 56 38 Reduction of long-term debt of joint ventures (157) (70) (80) Junior subordinated notes issued 1,107 – – Preferred securities redeemed (488) – – Common shares issued, net of issue costs (Note 16) 1,711 39 44 Partnership units of subsidiary issued (Note 8) 348 – – Net cash provided by/(used in) financing activities 3,526 219 (556) Effect of Foreign Exchange Rate Changes on Cash and Cash Equivalents (50) 911 Increase in Cash and Cash Equivalents 105 187 21 Cash and Cash Equivalents Beginning of year 399 212 191 Cash and Cash Equivalents End of year 504 399 212

The accompanying notes to the consolidated financial statements are an integral part of these statements. Attachment 1 CAPP 11 Page 83 of 142 CONSOLIDATED FINANCIAL STATEMENTS 79

TRANSCANADA CORPORATION CONSOLIDATED BALANCE SHEET December 31 (millions of dollars) 2007 2006 ASSETS Current Assets Cash and cash equivalents 504 399 Accounts receivable 1,116 1,004 Inventories 497 392 Other 188 297 2,305 2,092 Long-Term Investments (Note 7) 63 71 Plant, Property and Equipment (Note 4) 23,452 21,487 Goodwill 2,633 281 Other Assets (Note 5) 1,877 1,978 30,330 25,909 LIABILITIES AND SHAREHOLDERS’ EQUITY Current Liabilities Notes payable (Note 19) 421 467 Accounts payable 1,767 1,500 Accrued interest 261 264 Current portion of long-term debt (Note 9) 556 616 Current portion of long-term debt of joint ventures (Note 10) 30 142 3,035 2,989 Deferred Amounts (Note 12) 1,107 1,029 Future Income Taxes (Note 18) 1,179 876 Long-Term Debt (Note 9) 12,377 10,887 Long-Term Debt of Joint Ventures (Note 10) 873 1,136 Junior Subordinated Notes (Note 11) 975 Preferred Securities (Note 14) – 536 19,546 17,453 Non-Controlling Interests (Note 15) 999 755 Shareholders’ Equity Common shares (Note 16) 6,662 4,794 Contributed surplus 276 273 Retained earnings 3,220 2,724 Accumulated other comprehensive income (373) (90) 2,847 2,634 9,785 7,701 Commitments, Contingencies and Guarantees (Note 23) Subsequent Events (Note 25) 30,330 25,909

The accompanying notes to the consolidated financial statements are an integral part of these statements.

On behalf of the Board:

Harold N. Kvisle Kevin E. Benson Director Director Attachment 1 CAPP 11 Page 84 of 142 80 CONSOLIDATED FINANCIAL STATEMENTS

TRANSCANADA CORPORATION CONSOLIDATED COMPREHENSIVE INCOME

Year ended December 31 (millions of dollars) 2007 2006 2005 Net Income 1,223 1,079 1,209

Other Comprehensive Income/(Loss), net of income taxes Change in foreign currency translation gains and losses on investments in foreign operations(1) (350) 6 (34) Change in gains and losses on hedges of investments in foreign operations(2) 79 (6) 15 Change in gains and losses on derivative instruments designated as cash flow hedges(3) 42 –– Reclassification to net income of gains and losses on derivative instruments designated as cash flow hedges pertaining to prior periods(4) 42 –– Other comprehensive income/(loss) (187) – (19) Comprehensive Income 1,036 1,079 1,190

(1) Net of income tax expense of $101 million in 2007 (2006 – $3-million expense; 2005 – $13-million expense). (2) Net of income tax expense of $41 million in 2007 (2006 – $3-million recovery; 2005 – $8-million expense). (3) Net of income tax expense of $27 million in 2007. (4) Net of income tax expense of $23 million in 2007.

The accompanying notes to the consolidated financial statements are an integral part of these statements. Attachment 1 CAPP 11 Page 85 of 142 CONSOLIDATED FINANCIAL STATEMENTS 81

TRANSCANADA CORPORATION CONSOLIDATED ACCUMULATED OTHER COMPREHENSIVE INCOME

Currency Translation Cash Flow (millions of dollars) Adjustment Hedges Total Balance at December 31, 2004 (71) – (71) Change in foreign currency translation gains and losses on investments in foreign operations(1) (34) – (34) Change in gains and losses on hedges of investments in foreign operations(2) 15 – 15 Balance at December 31, 2005 (90) – (90) Change in foreign currency translation gains and losses on investments in foreign operations(1) 6–6 Change in gains and losses on hedges of investments in foreign operations(2) (6) – (6) Balance at December 31, 2006 (90) – (90) Transition adjustment resulting from adopting new financial instruments standards(3) – (96) (96) Change in foreign currency translation gains and losses on investments in foreign operations(1) (350) – (350) Change in gains and losses on hedges of investments in foreign operations(2) 79 – 79 Change in gains and losses on derivative instruments designated as cash flow hedges(4) –4242 Reclassification to net income of gains and losses on derivative instruments designated as cash flow hedges pertaining to prior periods(5)(6) –4242 Balance at December 31, 2007 (361) (12) (373)

(1) Net of income tax expense of $101 million in 2007 (2006 – $3-million expense; 2005 – $13-million expense). (2) Net of income tax expense of $41 million in 2007 (2006 – $3-million recovery; 2005 – $8-million expense). (3) Net of income tax expense of $44 million in 2007. (4) Net of income tax expense of $27 million in 2007. (5) Net of income tax expense of $23 million in 2007. (6) The amount of gains and losses related to cash flow hedges reported in accumulated other comprehensive income that will be reclassified to net income in 2008 is not expected to be significant.

The accompanying notes to the consolidated financial statements are an integral part of these statements. Attachment 1 CAPP 11 Page 86 of 142 82 CONSOLIDATED FINANCIAL STATEMENTS

TRANSCANADA CORPORATION CONSOLIDATED SHAREHOLDERS’ EQUITY

Year ended December 31 (millions of dollars) 2007 2006 2005 Common Shares Balance at beginning of year4,794 4,755 4,711 Proceeds from shares issued under public offering (Note 16) 1,683 –– Shares issued under dividend reinvestment plan (Note 16)157 – – Proceeds from shares issued on exercise of stock options (Note 16) 28 39 44 Balance at end of year6,662 4,794 4,755

Contributed Surplus Balance at beginning of year273 272 270 Issuance of stock options (Note 16)3 1 2 Balance at end of year276 273 272

Retained Earnings Balance at beginning of year2,724 2,269 1,655 Transition adjustment resulting from adopting new financial instruments accounting standards (Note 2) 4 Net income 1,223 1,079 1,209 Common share dividends (731) (624) (595) Balance at end of year 3,220 2,724 2,269

Accumulated Other Comprehensive Income, Net of Income Taxes Balance at beginning of year (90) (90) (71) Transition adjustment resulting from adopting new financial instruments accounting standards (Note 2) (96) Other comprehensive income/(loss) (187) – (19) Balance at end of year (373) (90) (90) Total Shareholders’ Equity 9,785 7,701 7,206

The accompanying notes to the consolidated financial statements are an integral part of these statements. Attachment 1 CAPP 11 Page 87 of 142 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 83

TRANSCANADA CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

TransCanada Corporation (the Company or TransCanada) is a leading North American energy company. TransCanada operates in two business segments, Pipelines and Energy, each of which offers different products and services.

Pipelines The Pipelines segment owns and operates the following: • a natural gas transmission system extending from the Alberta border east into Quebec´ (Canadian Mainline); • a natural gas transmission system in Alberta (Alberta System); • a natural gas transmission system extending from producing fields located primarily in Oklahoma, Texas, Louisiana and the Gulf of Mexico to markets located primarily in Wisconsin, Michigan, Illinois, Ohio and Indiana, and regulated natural gas storage facilities in Michigan (ANR); • a natural gas transmission system extending from the British Columbia/Idaho border to the Oregon/California border, traversing Idaho, Washington and Oregon (GTN System); • a natural gas transmission system extending from central Alberta to the British Columbia (B.C.)/United States border and to the Saskatchewan/U.S. border, and from the Alberta border west into southeastern B.C. (Foothills); • a natural gas transmission system extending from a point near Ehrenberg, Arizona to the Baja California, Mexico/California border (North Baja); • natural gas transmission systems in Alberta that supply natural gas to the oilsands region of northern Alberta and to a petrochemical complex at Joffre, Alberta (Ventures LP); • a natural gas transmission system in Mexico extending from Naranjos, Veracruz to Tamazunchale, San Luis Potosi (Tamazunchale); • a 53.6 per cent interest in a natural gas transmission system that connects to the Canadian Mainline and serves markets in Eastern Canada and northeastern and midwestern U.S. (Great Lakes); • a 50 per cent interest in a natural gas transmission system that connects with the Canadian Mainline and transports natural gas in Quebec,´ from Montreal to the Portland system and to Quebec´ City (TQM); and • a 61.7 per cent interest in a natural gas transmission system that extends from a point near East Hereford, Quebec,´ to the northeastern U.S. (Portland). • a 32.1 per cent interest in TC PipeLines, LP (PipeLines LP), which owns the following: • a 46.4 per cent interest in Great Lakes, in which TransCanada has a 68.5 per cent effective ownership through PipeLines LP and direct interests; • a 50 per cent interest in a natural gas transmission system extending from a point near Monchy, Saskatchewan, to the U.S. Midwest (Northern Border), which TransCanada began operating in April 2007 and in which it has a 16.1 per cent effective ownership interest through PipeLines LP; and • 100 per cent of a natural gas transmission system extending from Malin, Oregon to Wadsworth, Nevada, (Tuscarora), which TransCanada operates and in which it has a 32.1 per cent effective ownership interest through PipeLines LP.

Pipelines also holds the Company’s investments in other pipelines and pipeline projects including the following: • a 44.5 per cent interest in a natural gas transmission system that connects with the Canadian Mainline near Waddington, New York, and delivers natural gas to customers in the northeastern U.S. (Iroquois); • a 46.5 per cent interest in a natural gas transmission system, which extends from Mariquita in the central region of Colombia to Cali in the southwest of Colombia (TransGas); • a 30 per cent interest in a natural gas transmission system extending from Loma de la Lata, Argentina to Concepcion,´ Chile (Gas Pacifico), and in an industrial natural gas marketing company based in Concepcion´ (INNERGY); and • a 50 per cent interest in a pipeline under construction that will transport crude oil from Hardisty, Alberta, to U.S. Midwest markets at Wood River and Patoka in Illinois, and to Cushing, Oklahoma (Keystone). Attachment 1 CAPP 11 Page 88 of 142 84 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Energy The Energy segment builds, owns and operates electrical power generation plants, and sells electricity. Energy also holds investments in other electrical power generation plants, non-regulated natural gas storage facilities and interests in liquefied natural gas (LNG) regasification projects in North America. This business operates in Canada and the U.S. as follows:

Through its Energy segment, TransCanada owns and operates: • hydroelectric generation assets located in New Hampshire, Vermont and Massachusetts (TC Hydro); • a natural gas-fired, combined-cycle plant in Burrillville, Rhode Island (Ocean State Power); • natural gas-fired cogeneration plants in Alberta at Carseland, Redwater, Bear Creek and MacKay River; • a natural gas-fired cogeneration plant near Saint John, New Brunswick (Grandview); • a waste-heat fuelled power plant at the Cancarb facility in Medicine Hat, Alberta (Cancarb); • a natural gas-fired cogeneration plant near Trois-Rivieres,` Quebec´ (Becancour);´ and • a natural gas storage facility near Edson, Alberta (Edson).

TransCanada owns but does not operate: • a 48.7 per cent partnership interest and a 31.6 per cent partnership interest in the nuclear power generation facilities of Bruce Power A L.P. (Bruce A) and Bruce Power L.P. (Bruce B) (collectively Bruce Power), respectively, located near Lake Huron, Ontario; • a 60 per cent interest in an underground natural gas storage facility near Crossfield, Alberta (CrossAlta); and • a 62 per cent interest in the Baie-des-Sables and Anse-a-Valleau` wind farms, two of six wind farms in Gaspe,´ Quebec´ (Cartier Wind).

TransCanada also has long-term power purchase arrangements (PPA) in place for: • 100 per cent of the production of the Sundance A power facilities and, through a partnership, 50 per cent of the production of the Sundance B power facilities near Wabamun, Alberta; and • 756 megawatts (MW) of the generating capacity from the Sheerness power facility near Hanna, Alberta.

TransCanada has interests in projects under construction as follow: • a 62 per cent interest in Carleton, the third of the six wind farms in the Cartier Wind project; • a 50 per cent interest in a combined-cycle natural gas cogeneration plant near downtown Toronto, Ontario (Portlands Energy); and • a natural gas-fired, combined-cycle power plant near Toronto (Halton Hills).

NOTE 1 ACCOUNTING POLICIES

The consolidated financial statements of the Company have been prepared by Management in accordance with Canadian GAAP. Amounts are stated in Canadian dollars unless otherwise indicated. Certain comparative figures have been reclassified to conform with the current year’s presentation.

In preparing these financial statements, TransCanada is required to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be dependent on future events. The Company uses the most current information available and exercises careful judgment in making these estimates. In the opinion of management, these consolidated financial statements have been properly prepared within reasonable limits of materiality and within the framework of the significant accounting policies summarized below.

Basis of Presentation The consolidated financial statements include the accounts of TransCanada and its subsidiaries as well as its proportionate share of the accounts of its joint ventures. TransCanada uses the equity method of accounting for investments over which the Company is able to exercise significant influence. The Company consolidates its 32.1 per cent ownership interest in PipeLines LP and its 61.7 per cent interest in Portland Natural Gas Transmission System (Portland), with the other partners’ interests included in Non-Controlling Interests.

Regulation The Canadian Mainline, Foothills Pipe Lines Ltd. (Foothills), including the BC System effective April 1, 2007, and Trans Quebec´ Maritimes System (TQM) are subject to the authority of the National Energy Board (NEB). Effective January 1, 2008, the Alberta System is regulated by the Alberta Utilities Commission (AUC), a new regulatory body created as a result of the reorganization of the Alberta Energy and Utilities Attachment 1 CAPP 11 Page 89 of 142 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 85

Board (EUB). The Alberta System was regulated by the EUB prior to this date. The GTN System and North Baja (collectively, GTN), ANR and the other natural gas pipelines in the U.S. are subject to the authority of the Federal Energy Regulatory Commission (FERC). These natural gas transmission operations are regulated with respect to the determination of revenues, tolls, construction and operations. The timing of recognition of certain revenues and expenses in these regulated businesses may differ from that otherwise expected under GAAP to appropriately reflect the economic impact of the regulators’ decisions regarding the Company’s revenues and tolls, and to thereby achieve a proper matching of revenues and expenses. The impact of rate regulation on TransCanada is provided in Note 13 of these financial statements.

Revenue Recognition

Pipelines In the Pipelines segment, revenues from Canadian operations subject to rate regulation are recognized in accordance with decisions made by the NEB and AUC. Revenues from U.S. operations subject to rate regulation are recorded in accordance with FERC rules and regulations. Revenues from non-regulated operations are recorded when products have been delivered or services have been performed.

Energy i) Power The majority of revenues from the Power business are derived from the sale of electricity from energy marketing activities and from the sale of unutilized natural gas fuel, which are recorded in the month of delivery. Revenues also include the impact of energy derivative contracts, the accounting for which is described in Note 2. ii) Natural Gas Storage The majority of the revenues earned from natural gas storage are derived from providing storage services and are recognized in accordance with the terms of the gas storage contracts. Revenues earned on the sale of proprietary natural gas are recorded in the month of delivery. Forward contracts for the purchase or sale of natural gas, as well as proprietary natural gas inventory, are recorded at fair value with changes in fair value recorded in Net Income.

Dilution Gains Dilution gains resulting from the sale of units by partnerships in which TransCanada has an ownership interest are recognized immediately in net income.

Cash and Cash Equivalents The Company’s short-term investments with original maturities of three months or less are considered to be cash equivalents and are recorded at cost, which approximates market value.

Inventories Inventories consisting of uranium and materials and supplies including spare parts, are carried at the lower of average cost or net realizable value. As a result of adopting the new Canadian Institute of Chartered Accountants (CICA) Handbook accounting requirements for Section 3031 ‘‘Inventories’’, effective April 1, 2007, TransCanada began valuing its proprietary natural gas inventory held in storage at its fair value, as measured by the one-month forward price for natural gas.

Plant, Property and Equipment

Pipelines Plant, property and equipment of the Pipelines segment are carried at cost. Depreciation is calculated on a straight-line basis. Pipeline and compression equipment are depreciated at annual rates ranging from two to six per cent and metering and other plant equipment are depreciated at various rates. An allowance for funds used during construction is capitalized based on the rate of return on rate base approved by regulators and included in the cost of gas transmission plant. Interest is capitalized during construction on non-regulated pipelines.

Energy Major power generation and natural gas storage plant, equipment and structures in the Energy segment are recorded at cost and depreciated on a straight-line basis over estimated service lives at average annual rates ranging from two to ten per cent. Nuclear power generation assets under capital lease are initially recorded at the present value of minimum lease payments at the inception of the lease and amortized on a straight-line basis over the shorter of their useful life or remaining lease term. Other equipment is depreciated at various rates. The cost of Attachment 1 CAPP 11 Page 90 of 142 86 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

major overhauls of equipment is capitalized and depreciated over the estimated service lives. Interest is capitalized on plants under construction.

Corporate Corporate plant, property and equipment are recorded at cost and depreciated on a straight-line basis over estimated useful lives at average annual rates ranging from three to 20 per cent.

Acquisitions and Goodwill The Company accounts for business acquisitions using the purchase method of accounting and, accordingly, the assets and liabilities of the acquired entities are recorded at their estimated fair values at the date of acquisition. Goodwill is not amortized and is tested for impairment annually, or more frequently if events or changes in circumstances indicate that the asset might be impaired. Currently, all goodwill relates to U.S. Pipelines acquisitions.

Power Purchase Arrangements A PPA is a long-term contract for the purchase or sale of power on a predetermined basis. The initial payments for a PPA are deferred and amortized on a straight-line basis over the term of the contract, which ranges from nine to 12 years. PPAs, under which TransCanada sells power, are accounted for as operating leases. A portion of these PPAs have been subleased to third parties under similar terms and conditions.

Stock Options TransCanada’s Stock Option Plan permits options to be awarded to certain employees, including officers, to purchase the Company’s common shares. The contractual life of options granted after 2002 and options granted prior to 2003 is seven years and ten years, respectively. Options may be exercised at a price determined at the time the option is awarded and vest 33.3 per cent on each of the three following award date anniversaries. The Company records compensation expense over the three-year vesting period. This charge is reflected in the Pipelines and Energy segments. Upon exercise of stock options, amounts originally recorded against Contributed Surplus are reclassified to Common Shares.

Income Taxes The taxes payable method of accounting for income taxes is used for tollmaking purposes in Canadian regulated natural gas transmission operations, as prescribed by regulators. It is not necessary to provide for future income taxes under the taxes payable method. As permitted by Canadian GAAP, this method is also used for accounting purposes, since there is reasonable expectation that future taxes payable will be included in future costs of service and recorded in revenues at that time. The liability method of accounting for income taxes is used for the remainder of the Company’s operations. Under the liability method, future tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Future income tax assets and liabilities are measured using enacted or substantively enacted tax rates anticipated to apply to taxable income in the years in which temporary differences are anticipated to be recovered or settled. Changes to these balances are recognized in income in the period in which they occur.

Canadian income taxes are not provided on the unremitted earnings of foreign investments that the Company does not intend to repatriate in the foreseeable future.

Foreign Currency Translation The Company’s foreign operations are self-sustaining and are translated into Canadian dollars using the current rate method. Under this method, assets and liabilities are translated at period-end exchange rates and items included in the consolidated statements of income, shareholders’ equity, comprehensive income, accumulated other comprehensive income and cash flows are translated at the exchange rates in effect at the time of the transaction. Translation adjustments are reflected in Other Comprehensive Income.

Exchange gains or losses on the principal amounts of foreign currency debt related to the Alberta System, Foothills and Canadian Mainline are deferred until they are refunded or recovered in tolls.

Derivative Financial Instruments and Hedging Activities The Company uses derivative and other financial instruments to manage its exposure to changes in foreign currency exchange rates, interest rates and energy commodity prices. The Company also uses a combination of derivatives and U.S. dollar-denominated debt to manage the foreign currency exposure of its foreign operations. The methods the Company uses to account for its derivative and other financial instruments are described in Notes 2 and 17. Attachment 1 CAPP 11 Page 91 of 142 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 87

The recognition of gains and losses on the derivatives for the Canadian Mainline, Alberta System and Foothills exposures is determined through the regulatory process. The gains and losses on derivatives accounted for as part of rate-regulated accounting are deferred in regulatory assets or regulatory liabilities.

Asset Retirement Obligations The Company recognizes the fair value of a liability for an asset retirement obligation in the period in which it is incurred, when a legal obligation exists and if a reasonable estimate of fair value can be made. The fair value is added to the carrying amount of the associated asset and the liability is accreted at the end of each period through charges to operating expenses.

It is not possible to determine the scope and timing of asset retirements related to regulated natural gas transmission pipelines and, therefore, not possible to make a reasonable estimate of the fair value of the associated liability. As a result, the Company has not recorded an amount for asset retirement obligations related to these assets, with the exception of abandoned facilities. Management believes it is reasonable to assume that all retirement costs associated with its regulated pipelines will be recovered through tolls in future periods.

Similarly, it is not possible to determine the scope and timing of asset retirements related to hydroelectric power plants and, therefore, not possible to make a reasonable estimate of the fair value of the associated liability. As a result, the Company has not recorded an amount for asset retirement obligations related to hydroelectric power plant assets. With respect to the nuclear assets leased by Bruce Power, the Company has not recorded an amount for asset retirement obligations, as the lessor is responsible for decommissioning liabilities under the lease agreement.

Employee Benefit and Other Plans The Company sponsors defined benefit pension plans (DB Plans), defined contributions plans (DC Plans) and other post-employment plans. Contributions made by the Company to the DC Plans are expensed as incurred. The cost of the DB Plans and other post-employment benefits earned by employees is actuarially determined using the projected benefit method pro-rated based on service and management’s best estimate of expected plan investment performance, salary escalation, retirement ages of employees and expected health care costs.

The DB Plans’ assets are measured at fair value. The expected return on the DB Plans’ assets is determined using market-related values based on a five-year moving average value for all plan assets. Past service costs are amortized over the expected average remaining service life of the employees. Adjustments arising from plan amendments are amortized on a straight-line basis over the average remaining service period of employees active at the date of amendment. The excess of net actuarial gains or losses over 10 per cent of the greater of the benefit obligation and the fair value of the DB Plans’ assets is amortized over the average remaining service period of the active employees. When the restructuring of a benefit plan gives rise to both a curtailment and a settlement, the curtailment is accounted for prior to the settlement.

The Company has broad-based, medium-term employee incentive plans, which grant units to each eligible employee and are payable in cash. The expense related to these incentive plans is accounted for on an accrual basis. Under these plans, units vest when certain conditions are met, including the employees’ continued employment during a specified period and achievement of specified corporate performance targets.

Certain of the Company’s joint ventures sponsor DB Plans. The Company records its proportionate share of expenses, funding contributions and accrued benefit assets and liabilities related to these plans.

NOTE 2 ACCOUNTING CHANGES

Changes in Accounting Policies for 2007 Effective January 1, 2007, the Company adopted the accounting requirements for CICA Handbook Sections 1506 ‘‘Accounting Changes’’, 1530 ‘‘Comprehensive Income’’, 3251 ‘‘Equity’’, 3855 ‘‘Financial Instruments – Recognition and Measurement’’, and 3865 ‘‘Hedges’’. In addition, the Company chose to adopt the accounting requirements for Sections 3862 ‘‘Financial Instruments – Disclosure’’, 3863 ‘‘Financial Instruments – Presentation’’, and 1535 ‘‘Capital Disclosures’’ effective December 31, 2007, as well as the accounting requirements for Section 3031 ‘‘Inventories’’ effective April 1, 2007. Adjustments to the consolidated financial statements for 2007 have been made in accordance with the transitional provisions for these new standards.

Comprehensive Income and Equity The Company’s financial statements include statements of Consolidated Comprehensive Income and Consolidated Accumulated Other Comprehensive Income. In addition, as required in CICA Handbook Section 3251, the Company now presents separately, in the Consolidated Shareholders’ Equity statement, the changes for each of its components of Shareholders’ Equity, including Accumulated Other Comprehensive Income. Attachment 1 CAPP 11 Page 92 of 142 88 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Financial Instruments All financial instruments must initially be included on the balance sheet at their fair value. Subsequent measurement of the financial instruments is based on their classification. Financial assets are classified into the following categories: held for trading, available for sale, held-to-maturity investments and loans and receivables. Financial liabilities are classified as held for trading or other financial liabilities.

Held-for-trading financial assets and liabilities consist of swaps, options, forwards and futures, and are entered into with the intention of generating a profit. A financial asset or liability that does not meet this criterion may also be designated as held for trading. Power and natural gas held-for-trading instruments are initially recorded at their fair value and changes to fair value are included in Revenues. Changes in the fair value of interest rate and foreign exchange held-for-trading instruments are recorded in Financial Charges and in Interest Income and Other, respectively. The Company had not designated any financial assets or liabilities as held for trading at December 31, 2007.

The available-for-sale classification includes non-derivative financial assets that are designated as available for sale or are not included in the other three classifications. TransCanada’s available-for-sale financial instruments include fixed-income securities held for self-insurance. These instruments are initially accounted for at their fair value and changes to fair value are recorded through Other Comprehensive Income. Income from the settlement of available-for-sale financial assets will be included in Interest Income and Other.

Held-to-maturity financial assets are accounted for at their amortized cost using the effective interest method. The Company did not have any held-to-maturity financial assets at December 31, 2007.

Trade receivables, loans and other receivables with fixed or determinable payments that are not quoted in an active market are classified as ‘‘loans and receivables’’ and are measured net of any impairment. Loans and receivables include primarily trade accounts receivable and non-interest-bearing third-party loans receivable. Interest and other income earned from these financial assets are recorded in Interest Income and Other.

Other financial liabilities consist of liabilities not classified as held for trading. Interest expense is included in Financial Charges and in Financial Charges of Joint Ventures. Items in this financial instrument category are recognized at amortized cost using the effective interest method.

All derivatives are recorded on the balance sheet at fair value, with the exception of those that were entered into and continue to be held for the purpose of receipt or delivery in accordance with the Company’s expected purchase, sale or usage requirements (normal purchase and normal sale exemption). Changes in the fair value of derivatives that are not designated in a hedging relationship are recorded in Net Income. Derivatives used in hedging relationships are discussed further under the heading Hedges in this Note.

Derivatives embedded in other financial instruments or contracts (the host instrument) are recorded as separate derivatives and are measured at fair value if the economic characteristics of the embedded derivative are not closely related to the host instrument, the terms of the embedded derivative are the same as those of a stand-alone derivative and the total contract is not held for trading or accounted for at fair value. Changes in the fair value of embedded derivates that are recorded separately are included in Revenues. The Company used January 1, 2003 as the transition date for embedded derivatives.

Transaction costs are incremental costs that are directly attributable to the acquisition, issue or disposal of a financial instrument. Effective January 1, 2007, the Company began offsetting long-term debt transaction costs against the associated debt and began amortizing these costs using the effective interest method. Previously, these costs were amortized on a straight-line basis over the life of the debt. There was no material impact on the Company’s financial statements as a result of this change in policy. In 2007, the impact on Net Income for the amortization of transaction costs using the effective interest method was nominal.

The Company records the fair values of material joint and several guarantees. These fair values cannot be readily obtained from an open market and therefore, the fair value of these guarantees is estimated by discounting the cash flows that would be incurred by the Company if letters of credit were used in place of the guarantees. Guarantees are recorded as an increase to an investment account, Property, Plant and Equipment or a charge to Net Income, and a corresponding liability in Deferred Amounts.

Hedges CICA Handbook Section 3865 specifies the criteria that must be satisfied in order to apply hedge accounting and the accounting for each of the permitted hedging strategies, including: fair value hedges, cash flow hedges and hedges of foreign currency exposures of net investments in self-sustaining foreign operations. Hedge accounting is discontinued prospectively when the derivative no longer qualifies as an effective hedge or is terminated or sold, or upon the sale or early termination of the hedged item.

Documentation must be prepared at the inception of the hedging arrangement in order to qualify for hedge accounting treatment. In addition, the Company must perform an assessment of effectiveness at inception of the contract and at each reporting date.

In a fair value hedging relationship, the carrying value of the hedged item is adjusted for changes in fair value attributable to the hedged risk. The changes in fair value are recognized in Net Income. Changes in the fair value of the hedged item, to the extent that the hedging relationship is effective, are offset by changes in the fair value of the hedging item, which is also recorded in Net Income. Changes in the fair value of foreign exchange and interest rate hedges are recorded in Interest Income and Other and Financial Charges, respectively. When hedge Attachment 1 CAPP 11 Page 93 of 142 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 89

accounting is discontinued, the carrying value of the hedged item is no longer adjusted and the cumulative fair value adjustments to the carrying value of the hedged item are amortized to Net Income over the remaining term of the original hedging relationship.

In a cash flow hedging relationship, the effective portion of the change in the fair value of the hedging derivative is recognized in Other Comprehensive Income, while any ineffective portion is recognized in Net Income in the same financial category as the underlying transaction. When hedge accounting is discontinued, the amounts recognized previously in Accumulated Other Comprehensive Income are reclassified to Net Income during the periods when the variability in cash flows of the hedged item affects Net Income. Gains and losses on derivatives are reclassified immediately to Net Income when the hedged item is sold or terminated early, or when a hedged anticipated transaction is no longer expected to occur.

The Company also enters into cash flow hedges and fair value hedges for activities subject to rate regulation. The gains and losses arising from the changes in fair value of these hedges can be recovered through the tolls charged by the Company. As a result, these gains and losses are deferred as rate-regulated assets or liabilities on behalf of the ratepayers. When the hedges are settled, the realized gains or losses are collected from or refunded to the ratepayers in subsequent years.

In hedging the foreign currency exposure of a net investment in a self-sustaining foreign operation, the effective portion of foreign exchange gains and losses on the hedging instruments is recognized in Other Comprehensive Income and the ineffective portion is recognized in Net Income. The amounts recognized previously in Accumulated Other Comprehensive Income are recognized in Net Income in the event the Company settles or otherwise reduces its investment.

Net Effect of Accounting Policy Changes The net effect of the preceding accounting policy changes on the Company’s financial statements at January 1, 2007, was as follows:

Increases/(decreases) (millions of dollars) Other current assets (127) Other assets (203) Accounts payable (29) Deferred amounts (75) Future income taxes (42) Long-term debt (85) Long-term debt of joint ventures (7) Accumulated other comprehensive income (96) Retained earnings 4

The primary changes in 2007 to the Company’s accounting policies for financial instruments related to the requirements to record certain non-financial contracts at their fair value and to offset transaction costs against long-term debt.

Section 3862 Financial Instruments – Disclosures and Section 3863 Financial Instruments – Presentation CICA Handbook Sections 3862 ‘‘Financial Instruments – Disclosure’’ and 3863 ‘‘Financial Instruments – Presentation’’, which replaced Section 3861 ‘‘Financial Instruments – Disclosure and Presentation’’, are effective January 1, 2008. However, the Company chose to adopt these standards effective December 31, 2007. The additional disclosure necessary to comply with these standards is provided in these consolidated financial statements. Certain information related to comparative years is not prescribed by these standards and accordingly has not been presented.

Section 1535 Capital Disclosures CICA Handbook Section 1535 ‘‘Capital Disclosures’’ is effective for fiscal years beginning on or after October 1, 2007, however, TransCanada chose to adopt this standard effective December 31, 2007. Note 17 in these consolidated financial statements provides qualitative disclosure regarding objectives, policies and processes for managing capital as well as quantitative data on capital as of December 31, 2007.

Proprietary Natural Gas Inventories and Revenue Recognition CICA Handbook Section 3031 ‘‘Inventories’’ is effective January 1, 2008. However, the Company chose to adopt this standard effective April 1, 2007, and began valuing its proprietary natural gas inventory held in storage at fair value, as measured by the one-month forward price for natural gas. To record inventory at fair value, TransCanada has designated its natural gas storage business as a broker/trader business that purchases and sells natural gas on a back-to-back basis. TransCanada did not have any proprietary natural gas inventory prior to April 1, 2007. Attachment 1 CAPP 11 Page 94 of 142 90 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Company records its proprietary natural gas storage results in Revenues net of Commodity Purchases Resold. All changes in the fair value of the proprietary natural gas inventories are reflected in Inventories and Revenues.

Future Accounting Changes

Rate-Regulated Operations Effective January 1, 2009, the temporary exemption from CICA Handbook Section 1100, ‘‘Generally Accepted Accounting Principles’’, which permits the recognition and measurement of assets and liabilities arising from rate regulation, will be withdrawn. In addition, Section 3465 ‘‘Income Taxes’’ was amended to require the recognition of future income tax liabilities and assets. As a result of the changes, TransCanada will be required to recognize future income tax liabilities and assets instead of using the taxes payable method, and will record an offsetting adjustment to regulatory assets and liabilities. If the liability method of accounting had been used at December 31, 2007, additional future income tax liabilities in the amount of $1,138 million would have been recorded and would have been recoverable from future revenue. These changes will be applied prospectively beginning January 1, 2009.

International Financial Reporting Standards The CICA’s Accounting Standards Board (AcSB) announced that Canadian publicly accountable enterprises will adopt International Financial Reporting Standards (IFRS), as issued by the International Accounting Standards Board (IASB), effective January 1, 2011. IFRS will require increased financial statement disclosure. Although IFRS uses a conceptual framework similar to Canadian GAAP, differences in accounting policies will need to be addressed. TransCanada is currently assessing the impact of this AcSB announcement on its financial statements.

Intangible Assets The CICA Handbook implemented revisions to standards dealing with Intangible Assets effective for fiscal years beginning on or after October 1, 2008. The revisions are intended to align the definition of an Intangible Asset in Canadian GAAP with that in IFRS and U.S. GAAP. Section 1000 ‘‘Financial Statement Concepts’’ was revised to remove material that permitted the recognition of assets that might not otherwise meet the definition of an asset and to add guidance from the IASB’s ‘‘Framework for the Preparation and Presentation of Financial Statements’’ that will help distinguish assets from expenses. Section 3064 ‘‘Goodwill and Intangible Assets’’, which replaced Section 3062 ‘‘Goodwill and Other Intangible Assets’’, gives guidance on the recognition of intangible assets as well as the recognition and measurement of internally developed intangible assets. Section 3450 ‘‘Research and Development Costs’’ will be withdrawn from the Handbook. The Company does not expect these changes to have a material effect on its financial statements. Attachment 1 CAPP 11 Page 95 of 142 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 91

NOTE 3 SEGMENTED INFORMATION

NET INCOME/(LOSS)(1)

Year ended December 31, 2007 (millions of dollars) Pipelines Energy Corporate Total Revenues 4,712 4,116 – 8,828 Plant operating costs and other (1,670) (1,353) (7) (3,030) Commodity purchases resold (72) (1,887) – (1,959) Depreciation (1,021) (158) – (1,179) 1,949 718 (7) 2,660 Financial charges and non-controlling interests (793) 1 (248) (1,040) Financial charges of joint ventures (52) (23) – (75) Income from equity investments 17 – – 17 Interest income and other 35 10 90 135 Gain on sale of assets –16 –16 Income taxes (470) (208) 188 (490) Net Income 686 514 23 1,223

Year ended December 31, 2006 (millions of dollars) Revenues 3,990 3,530 – 7,520 Plant operating costs and other (1,380) (1,024) (7) (2,411) Commodity purchases resold – (1,707) – (1,707) Depreciation (927) (131) (1) (1,059) 1,683 668 (8) 2,343 Financial charges and non-controlling interests (767) – (136) (903) Financial charges of joint ventures (69) (23) – (92) Income from equity investments 33 – – 33 Interest income and other 67 5 51 123 Gain on sale of assets 23 – – 23 Income taxes (410) (198) 132 (476) Net income from continuing operations 560 452 39 1,051 Net income from discontinued operations 28 Net Income 1,079

Year ended December 31, 2005 (millions of dollars) Revenues 3,993 2,131 – 6,124 Plant operating costs and other (1,226) (595) (4) (1,825) Commodity purchases resold – (1,232) – (1,232) Depreciation (932) (85) – (1,017) 1,835 219 (4) 2,050 Financial charges and non-controlling interests (788) (2) (130) (920) Financial charges of joint ventures (57) (9) – (66) Income from equity investments 79 168 – 247 Interest income and other 25 5 33 63 Gains on sales of assets 82 363 – 445 Income taxes (497) (178) 65 (610) Net Income 679 566 (36) 1,209

(1) Certain expenses such as indirect financial charges and related income taxes are not allocated to business segments when determining their net income. Attachment 1 CAPP 11 Page 96 of 142 92 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

TOTAL ASSETS

December 31 (millions of dollars) 2007 2006 Pipelines 22,024 18,320 Energy 7,037 6,500 Corporate 1,269 1,089 30,330 25,909

GEOGRAPHIC INFORMATION

Year ended December 31 (millions of dollars) 2007 2006 2005 Revenues(1) Canada – domestic 5,019 4,956 3,499 Canada – export 1,006 972 1,160 United States and other 2,803 1,592 1,465 8,828 7,520 6,124

(1) Revenues are attributed based on the country where the product or service originated.

December 31 (millions of dollars) 2007 2006 Plant, Property and Equipment Canada 16,741 16,204 United States 6,564 5,109 Mexico 147 174 23,452 21,487

CAPITAL EXPENDITURES

Year ended December 31 (millions of dollars) 2007 2006 2005 Pipelines 564 560 244 Energy 1,079 976 506 Corporate 8 36 4 1,651 1,572 754 Attachment 1 CAPP 11 Page 97 of 142 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 93

NOTE 4 PLANT, PROPERTY AND EQUIPMENT

2007 2006 Accumulated Net Accumulated Net December 31 (millions of dollars) Cost Depreciation Book Value Cost Depreciation Book Value Pipelines Canadian Mainline Pipeline 8,889 4,149 4,740 8,850 3,911 4,939 Compression 3,371 1,303 2,068 3,343 1,181 2,162 Metering and other 345 140 205 346 136 210 12,605 5,592 7,013 12,539 5,228 7,311 Under construction 28 – 28 23 – 23 12,633 5,592 7,041 12,562 5,228 7,334 Alberta System Pipeline 5,258 2,504 2,754 5,120 2,352 2,768 Compression 1,522 842 680 1,510 760 750 Metering and other 831 297 534 806 271 535 7,611 3,643 3,968 7,436 3,383 4,053 Under construction 120 – 120 98 – 98 7,731 3,643 4,088 7,534 3,383 4,151 ANR(1) Pipeline 772 25 747 Compression 424 32 392 Metering and other 483 6 477 1,679 63 1,616 Under construction 69 – 69 1,748 63 1,685 GTN Pipeline 1,181 134 1,047 1,386 111 1,275 Compression 436 39 397 512 32 480 Metering and other 81 3 78 89 – 89 1,698 176 1,522 1,987 143 1,844 Under construction 31 – 31 17 – 17 1,729 176 1,553 2,004 143 1,861 Great Lakes(2) Pipeline 977 427 550 806 463 343 Compression 359 75 284 255 85 170 Metering and other 165 50 115 122 52 70 1,501 552 949 1,183 600 583 Under construction 8–84–4 1,509 552 957 1,187 600 587 Foothills Pipeline 903 476 427 815 405 410 Compression 632 286 346 377 141 236 Metering and other 112 57 55 72 35 37 1,647 819 828 1,264 581 683 Joint Ventures and Other Northern Border(3) 1,232 528 704 1,451 585 866 Other 1,863 439 1,424 2,274 615 1,659 3,095 967 2,128 3,725 1,200 2,525 30,092 11,812 18,280 28,276 11,135 17,141 Energy(4) Nuclear(5) 1,479 286 1,193 1,349 214 1,135 Natural gas 1,570 383 1,187 1,636 383 1,253 Hydro 503 28 475 592 21 571 Natural gas storage 358 33 325 344 22 322 Wind 288 6 282 131 – 131 Other 137 78 59 153 72 81 4,335 814 3,521 4,205 712 3,493 Under construction 1,606 – 1,606 809 – 809 5,941 814 5,127 5,014 712 4,302 Corporate 60 15 45 65 21 44 36,093 12,641 23,452 33,355 11,868 21,487 Attachment 1 CAPP 11 Page 98 of 142 94 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) TransCanada acquired ANR on February 22, 2007. (2) In February 2007, PipeLines LP acquired a 46.4 per cent general partnership interest in Great Lakes and TransCanada increased its ownership interest in Great Lakes by 3.6 per cent, bringing the Company’s direct ownership to 53.6 per cent (December 31, 2006 – 50 per cent) and making Great Lakes a controlled entity. The Company commenced consolidating its investment in Great Lakes on a prospective basis. Prior to this, Great Lakes was being proportionately consolidated. TransCanada’s 32.1 per cent ownership interest in PipeLines LP brought its effective ownership of Great Lakes, net of non-controlling interests, to 68.5 per cent at December 31, 2007. (3) In April 2006, PipeLines LP acquired an additional 20 per cent general partnership interest in Northern Border, bringing its total general partnership interest to 50 per cent. Through TransCanada’s ownership interest in PipeLines LP, Northern Border became a jointly controlled entity and TransCanada commenced proportionately consolidating its investment in Northern Border on a prospective basis. TransCanada’s effective ownership of Northern Border, net of non-controlling interests, was 16.1 per cent at December 31, 2007 (2006 – 6.7 per cent). (4) Certain power generation facilities with long-term PPAs are accounted for as assets under operating leases. The net book value of these facilities was $78 million at December 31, 2007 (2006 – $81 million). Revenues of $16 million were recognized in 2007 (2006 – $13 million) through the sale of electricity under the related PPAs. (5) Includes assets under capital lease relating to Bruce Power.

NOTE 5 OTHER ASSETS

December 31 (millions of dollars) 2007 2006 PPAs(1) 709 767 Regulatory assets 336 178 Pension and other benefit plans 234 268 Fair value of derivative contracts 204 144 Loans and advances(2) 141 121 Deferred project development costs(3) 40 70 Hedging deferrals(4) – 152 Debt issue costs(5) – 77 Other 213 201 1,877 1,978

(1) The following amounts related to the PPAs are included in the consolidated financial statements. 2007 2006 December 31 Accumulated Net Accumulated Net (millions of dollars) Cost Amortization Book Value Cost Amortization Book Value PPAs 915 206 709 915 148 767

The amortization expense for the PPAs was $58 million for the year ended December 31, 2007 (2006 – $58 million; 2005 – $24 million). The expected annual amortization expense in each of the next five years is: 2008 – $58 million; 2009 – $58 million; 2010 – $58 million; 2011 – $57 million; and 2012 – $57 million. (2) The balance at December 31, 2007 included a $137-million loan (2006 – $118 million) to the Aboriginal Pipeline Group (APG) to finance the APG for its one-third share of project development costs related to the Mackenzie Gas Pipeline project. The ability to recover this investment remains dependent upon the successful outcome of the project. (3) The balance at December 31, 2007 included $40 million (2006 – $31 million) related to the Broadwater LNG project. The balance at December 31, 2006 included $39 million related to Keystone. (4) Changes in GAAP required the Company to record the effective portion and the changes in fair value of cash flow and fair value hedges in Other Comprehensive Income and Net Income, respectively, effective January 1, 2007. Prior to this date, the fair value of certain hedges was deferred and recognized in income when the instrument had settled. (5) Changes in GAAP required the Company to offset long-term debt transaction costs against the associated debt, effective January 1, 2007. Attachment 1 CAPP 11 Page 99 of 142 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 95

NOTE 6 JOINT VENTURE INVESTMENTS

TransCanada’s Proportionate Share Income Before Income Taxes Net Assets Ownership Year ended December 31 December 31 (millions of dollars) Interest(1) 2007 2006 2005 2007 2006 Pipelines Northern Border (3) 63 47 – 542 634 Iroquois 44.5%(4) 25 25 29 163 194 Great Lakes (5) 13 69 73 – 370 TQM 50.0%11 11 1374 75 Keystone 50.0%(6) – ––207 – Other Various 13 6 10 48 –

Energy Bruce A 48.7%(7) 8 75 19 1,640 916 Bruce B 31.6%(7) 140 140 5 325 425 CrossAlta(2) 60.0% 59 64 31 38 36 Cartier Wind 62.0%(8) 10 2 – 275 172 TC Turbines 50.0% 525 5 926 Portlands Energy 50.0% – – – 269 90 ASTC Power Partnership 50.0%(9) –7––682 Power LP (10) –––25 – 347 444 210 3,686 3,020

(1) All ownership interests are as at December 31, 2007. (2) CrossAlta Gas Storage & Services Ltd. (CrossAlta). (3) PipeLines LP acquired an additional 20 per cent general partnership interest in Northern Border in April 2006, increasing its general partnership interest to 50 per cent. Through TransCanada’s 32.1 per cent ownership interest in PipeLines LP, Northern Border became a jointly controlled entity and TransCanada commenced proportionately consolidating its investment in Northern Border on a prospective basis. The Company’s effective ownership of Northern Border, net of non-controlling interests, was 16.1 per cent at December 31, 2007 (2006 – 6.7 per cent). (4) The Company acquired an additional 3.5 per cent ownership interest in Iroquois Gas Transmission System, L.P. (Iroquois) in June 2005. (5) In February 2007, TransCanada acquired an additional 3.6 per cent interest in Great Lakes, bringing its direct ownership interest to 53.6 per cent, and PipeLines LP acquired a 46.4 per cent interest in Great Lakes, giving TransCanada an indirect 14.9 per cent interest in Great Lakes. As a result of these transactions the Company’s effective ownership of Great Lakes, net of non-controlling interests, was 68.5 per cent at December 31, 2007 (2006 – 50 per cent). TransCanada commenced consolidating its investment in Great Lakes, on a prospective basis, effective February 22, 2007. (6) In December 2007, ConocoPhillips exercised its option to become a 50 per cent partner with TransCanada in Keystone. As a result, TransCanada transferred $207 million of net assets and ConocoPhillips contributed $207 million of cash to each become a 50 per cent joint venture partner in Keystone. (7) TransCanada acquired a 47.4 per cent ownership interest in Bruce A on October 31, 2005. The Company’s ownership interest in Bruce A was 48.7 per cent at December 31, 2007 (2006 – 48.7 per cent). The Company proportionately consolidated its investments in Bruce A and Bruce B on a prospective basis, effective October 31, 2005. (8) TransCanada proportionately consolidates 62 per cent of the Cartier Wind assets. The first two phases of the six-phase Cartier Wind project, Baie-des-Sables and Anse-a-Valleau,` began operating in November 2006 and 2007, respectively. (9) The Company has a 50 per cent ownership interest in ASTC Power Partnership, which is located in Alberta and holds the Sundance B PPA. The underlying power volumes related to this ownership interest are effectively transferred to TransCanada. (10) In August 2005, the Company sold its 30.6 per cent interest in TransCanada Power, L.P. Attachment 1 CAPP 11 Page 100 of 142 96 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Summarized Financial Information of Joint Ventures

Year ended December 31 (millions of dollars) 2007 2006 2005 Income Revenues 1,224 1,379 687 Plant operating costs and other (659) (689) (328) Depreciation (150) (162) (93) Financial charges and other (68) (84) (56) Proportionate share of joint venture income before income taxes 347 444 210

Year ended December 31 (millions of dollars) 2007 2006 2005 Cash Flows Operating activities 420 645 346 Investing activities (761) (641) (133) Financing activities(1) 409 (31) (152) Effect of foreign exchange rate changes on cash and cash equivalents (8) 9 (1) Proportionate share of increase/(decrease) in cash and cash equivalents of joint ventures 60 (18) 60

(1) Financing activities included cash outflows resulting from distributions paid to TransCanada of $361 million in 2007 (2006 – $470 million; 2005 – $201 million) and cash inflows resulting from capital contributions paid by TransCanada of $771 million in 2007 (2006 – $452 million; 2005 – $92 million).

December 31 (millions of dollars) 2007 2006 Balance Sheet Cash and cash equivalents 170 127 Other current assets 314 304 Plant, property and equipment 4,283 4,110 Other assets 44 78 Current liabilities (250) (443) Long-term debt (873) (1,136) Future income taxes (2) (20) Proportionate share of net assets of joint ventures3,686 3,020 Attachment 1 CAPP 11 Page 101 of 142 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 97

NOTE 7 LONG-TERM INVESTMENTS

TransCanada’s Share Distributions Income from from Equity Investments Equity Investments Equity Investments Ownership Year ended December 31 Year ended December 31 December 31 (millions of dollars) Interest 20072006 2005 20072006 2005 2007 2006 Pipelines TransGas 46.5% 814637 6 11 11 66 Northern Border (1) –––13 76 13 61 – Other Various 83–4 10 9 7 5

Energy Bruce B 31.6%(2) –––– 84 – 168 – 1624 176 1733 247 63 71

(1) PipeLines LP acquired an additional 20 per cent general partnership interest in Northern Border in April 2006, bringing its general partnership interest to 50 per cent. Through TransCanada’s 32.1 per cent ownership interest in PipeLines LP, Northern Border became a jointly controlled entity and TransCanada commenced proportionately consolidating its investment in Northern Border on a prospective basis. (2) The Company commenced proportionately consolidating its 31.6 per cent ownership interest in Bruce B on a prospective basis, effective October 31, 2005.

NOTE 8 ACQUISITIONS AND DISPOSITIONS

Acquisitions

Pipelines

ANR and Great Lakes On February 22, 2007, TransCanada acquired from El Paso Corporation 100 per cent of ANR and an additional 3.6 per cent interest in Great Lakes Gas Transmission Limited Partnership (Great Lakes) for a total of US$3.4 billion, subject to certain post-closing adjustments, including US$491 million of assumed long-term debt. The acquisitions were accounted for using the purchase method of accounting. TransCanada began consolidating ANR and Great Lakes in the Pipelines segment after the acquisition date. The preliminary allocation of the purchase price at December 31, 2007, was as follows.

Purchase Price Allocation

(millions of US dollars) ANR Great Lakes Total Current assets 250 4 254 Plant, property and equipment 1,617 35 1,652 Other non-current assets 83 – 83 Goodwill 1,914 32 1,946 Current liabilities (179) (3) (182) Long-term debt (475) (16) (491) Other non-current liabilities (326) (19) (345) 2,884 33 2,917

TC PipeLines, LP Acquisition of Interest in Great Lakes On February 22, 2007, PipeLines LP acquired from El Paso Corporation a 46.4 per cent interest in Great Lakes for US$942 million, subject to certain post-closing adjustments, including US$209 million of assumed long-term debt. The acquisition was accounted for using the purchase method of accounting. TransCanada began consolidating Great Lakes in the Pipelines segment after the acquisition date. The preliminary allocation of the purchase price at December 31, 2007, was as follows. Attachment 1 CAPP 11 Page 102 of 142 98 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Purchase Price Allocation

(millions of US dollars) Current assets 42 Plant, property and equipment 465 Other non-current assets 1 Goodwill 457 Current liabilities (23) Long-term debt (209) 733

The preliminary allocation of the purchase price for these transactions was made using the fair value of the net assets at the date of acquisition. Tolls charged by ANR and Great Lakes are subject to rate regulation based on historical costs. As a result, the regulated net assets, other than ANR’s gas held for sale, were determined to have a fair value equal to their rate-regulated values.

Factors that contributed to goodwill included the opportunity to expand in the U.S. market and to gain a stronger competitive position in the North American gas transmission business. Goodwill related to TransCanada’s ANR and Great Lakes transactions is not amortizable for tax purposes. Goodwill related to PipeLines LP’s Great Lakes transaction is amortizable for tax purposes.

TC PipeLines, LP Private Placement Offering PipeLines LP completed a private placement offering of 17,356,086 common units at a price of US$34.57 per unit in February 2007. TransCanada acquired 50 per cent of the units for US$300 million. TransCanada also invested an additional US$12 million to maintain its general partnership interest in PipeLines LP. As a result of these additional investments, TransCanada’s ownership in PipeLines LP increased to 32.1 per cent on February 22, 2007. The total private placement, together with TransCanada’s additional investment, resulted in gross proceeds to PipeLines LP of US$612 million, which were used to partially finance its acquisition of a 46.4-per-cent ownership interest in Great Lakes.

Tuscarora PipeLines LP exercised its option to purchase Sierra Pacific Resources’ remaining one per cent interest in Tuscarora Gas Transmission Company (Tuscarora) for US$2 million in December 2007. In addition, PipeLines LP purchased TransCanada’s one per cent interest in Tuscarora for US$2 million.

In December 2006, PipeLines LP acquired an additional 49 per cent controlling general partner interest in Tuscarora for US$100 million in addition to indirectly assuming US$37 million of debt. The purchase price was allocated US$79 million to Goodwill, US$37 million to long-term debt, and the balance primarily to Plant, Property and Equipment. Factors that contributed to goodwill included opportunities for expansion and a stronger competitive position. The goodwill recognized on this transaction is amortizable for tax purposes. PipeLines LP began consolidating its investment in Tuscarora in December 2006. TransCanada became the operator of Tuscarora in December 2006 as a result of this transaction.

PipeLines LP now owns 100 per cent of Tuscarora. At December 31, 2007, TransCanada’s 32.1 per cent ownership interest in PipeLines LP (December 31, 2006 – 13.4 per cent) gave it an effective ownership in Tuscarora of 32.1 per cent, net of non-controlling interests (December 31, 2006 – 14.3 per cent).

Northern Border In April 2006, PipeLines LP acquired an additional 20 per cent general partnership interest in Northern Border Pipeline Company (Northern Border) for US$307 million, in addition to indirectly assuming US$122 million of debt. The purchase price was allocated US$114 million to Goodwill, US$122 million to long-term debt and the balance primarily to Plant, Property and Equipment. Factors that contributed to goodwill included opportunities for expansion and a stronger competitive position. The goodwill recognized on this transaction is amortizable for tax purposes.

PipeLines LP now owns 50 per cent of Northern Border. At December 31, 2007, TransCanada’s 32.1 per cent ownership interest in PipeLines LP (2006 – 13.4 per cent) gave it an effective ownership in Northern Border of 16.1 per cent, net of non-controlling interests (2006 – 6.7 per cent). TransCanada proportionately consolidated its interest in Northern Border since the date of acquisition. TransCanada became the operator of Northern Border in April 2007 as a result of this transaction. Attachment 1 CAPP 11 Page 103 of 142 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 99

Energy

Sheerness PPA TransCanada obtained the 756 MW Sheerness PPA from the Alberta Balancing Pool for $585 million effective December 31, 2005. The PPA terminates in 2020.

Bruce Power In October 2005, TransCanada acquired an interest in Bruce A, a newly created partnership, as part of an agreement to restart Bruce A Units 1 and 2, which are currently idle. Under the Bruce A Sublease agreement, the new partnership subleased Units 1 to 4 from Bruce B and purchased certain other related assets. TransCanada incurred a net cash outlay of $100 million related to this transaction. As part of the reorganization, Bruce A and Bruce B became jointly controlled entities and TransCanada commenced proportionately consolidating its investment in both on a prospective basis effective October 31, 2005. At December 31, 2007 and 2006, the Company held a 48.7 per cent interest in Bruce A and a 31.6 per cent interest in Bruce B.

TC Hydro TransCanada acquired TC Hydro, the hydroelectric generation assets of USGen New England, Inc. for approximately US$503 million in April 2005. Substantially all of the purchase price was allocated to Plant, Property and Equipment.

Dispositions Pre-tax gains on sales of assets were as follow:

Year ended December 31 (millions of dollars) 2007 2006 2005 Gain on sale of land 16 –– Gain on sale of Northern Border Partners, LP interest– 23 – Gains related to Power LP – – 245 Gain on sale of Paiton Energy– – 118 Gain on sale of PipeLines LP units– – 82 16 23 445

Ontario Land Sale In November 2007, TransCanada’s Energy segment sold land in Ontario that had been previously held for development, generating net proceeds of $37 million and recognizing an after-tax gain of $14 million on the sale.

Northern Border Partners, LP Interest In April 2006, TransCanada sold its 17.5 per cent general partner interest in Northern Border Partners, LP, generating net proceeds of $33 million (US$30 million) and recognizing 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 on the transaction, including $12 million of current income tax expense.

Power LP In August 2005, TransCanada sold its ownership interest in TransCanada Power, L.P. (Power LP) to EPCOR Utilities Inc. (EPCOR), generating net proceeds of $523 million and realizing an after-tax gain of $193 million. The net gain was recorded in the Energy segment and the Company recorded a $52-million income tax charge on the transaction, including $79 million of current income tax expense. The sale resulted in disposal of Power LP assets and liabilities with a book value of $452 million and $174 million, respectively. EPCOR’s acquisition included 14.5 million limited partnership units of Power LP, representing 30.6 per cent of the outstanding units, 100 per cent ownership of the general partner of Power LP, and the management and operations agreements governing the ongoing operation of Power LP’s assets.

Paiton Energy In November 2005, TransCanada sold its ownership interest of approximately 11 per cent in PT Paiton Energy Company (Paiton Energy) to subsidiaries of The Tokyo Electric Power Company for gross proceeds of $122 million (US$103 million) and recognized an after-tax gain of $115 million. The net gain was recorded in the Energy segment and the Company recorded a $3-million income tax charge, including $3 million of current income tax recovery.

TC PipeLines, LP In March and April 2005, TransCanada sold a total of 3,574,200 common units of PipeLines LP for net proceeds of $153 million and recorded an after-tax gain of $49 million. The net gain was recorded in the Pipelines segment and the Company recorded a $33-million income tax charge on the transaction, including $51 million of current income tax expense. Attachment 1 CAPP 11 Page 104 of 142 100 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 9 LONG-TERM DEBT 2007 2006 Outstanding loan amounts (millions of Outstanding Interest Outstanding Interest dollars unless otherwise indicated) Maturity DatesDecember 31 Rate(1)(2) December 31 Rate(2)(3) TRANSCANADA PIPELINES LIMITED First Mortgage Pipe Line Bonds Pounds sterling (2006 – £25 million) – 57 16.5% Debentures Canadian dollars 2008 to 20201,351 10.9% 1,355 10.9% U.S. dollars (2007 and 2006 – US$600)(4) 2012 to 2021 594 9.5% 699 9.5% Medium-Term Notes Canadian dollars(5) 2008 to 2031 3,413 6.1% 3,848 6.0% Senior Unsecured Notes U.S. dollars (2007 – US$3,223; 2006 – US$2,223)(6) 2009 to 2037 3,161 6.0% 2,590 5.8% 8,519 8,549 NOVA GAS TRANSMISSION LTD. Debentures and Notes Canadian dollars 2008 to 2024 501 11.6% 564 11.6% U.S. dollars (2007 and 2006 – US$375) 2012 to 2023 368 8.2% 437 8.2% Medium-Term Notes Canadian dollars 2008 to 2030 607 7.2% 609 7.1% U.S. dollars (2007 and 2006 – US$33) 2026 32 7.5% 38 7.5% 1,508 1,648 TRANSCANADA PIPELINE USA LTD. Bank Loan U.S. dollars (2007 – US$860) 2012 850 5.7% ANR PIPELINE COMPANY Senior Unsecured Notes U.S. dollars (2007– US$444) 2010 to 2025 435 9.1% GAS TRANSMISSION NORTHWEST CORPORATION Senior Unsecured Notes U.S. Dollars (2007 and 2006 – US$400) 2010 to 2035 399 5.4% 466 5.3% TC PIPELINES, LP Unsecured Loan U.S. dollars (2007 – US$507; 2006 – US$397) 2011 499 6.2% 463 5.4% GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP(7) Senior Unsecured Notes U.S. dollars (2007– US$440) 2011 to 2030 434 7.8% TUSCARORA GAS TRANSMISSION COMPANY Senior Unsecured Notes U.S. dollars (2007 – US$69; 2006 – US$74) 2010 to 201267 7.4% 86 7.2% PORTLAND NATURAL GAS TRANSMISSION SYSTEM Senior Secured Notes U.S. dollars (2007 – US$211; 2006 – US$226) 2018205 6.1% 263 5.9% OTHER Senior Notes U.S. dollars (2007 – US$17; 2006 – US$24) 201117 7.3% 28 7.3% 12,933 11,503 Less: Current Portion of Long-Term Debt 556 616 12,377 10,887 Attachment 1 CAPP 11 Page 105 of 142 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 101

(1) Interest rates are the effective interest rates except for those pertaining to long-term debt issued for the Company’s regulated operations, in which case the weighted average interest rate is presented as required by the regulators. (2) Weighted average and effective interest rates are stated as at the respective outstanding dates. The effective weighted average interest rate resulting from swap agreements was six per cent in 2007 on TCPL’s U.S. dollar Medium-Term Notes (2006 – 5.8 per cent). (3) Interest rates are the weighted average interest rates. (4) Includes fair value adjustments for swap agreements on US$50 million of debt at December 31, 2007. (5) Includes fair value adjustments for swap agreements on $150 million of debt at December 31, 2007. (6) Includes fair value adjustments for swap agreements on US$150 million of debt at December 31, 2007. (7) TransCanada increased its effective ownership in Great Lakes to 68.5 per cent from 50.0 per cent on February 22, 2007. The Company commenced consolidation of Great Lakes on a prospective basis effective February 22, 2007.

Principal Repayments Principal repayments on the long-term debt of the Company are approximately as follow: 2008 – $556 million; 2009 – $1,002 million; 2010 – $617 million; 2011 – $805 million; and 2012 – $1,246 million.

Debt Shelf Programs In March 2007, the Company filed debt shelf prospectuses in Canada and the U.S. qualifying for issuance $1.5 billion of Medium-Term Notes and US$1.5 billion of debt securities, respectively. At December 31, 2007, the Company had issued no Medium-Term Notes under the Canadian prospectus. In September 2007, the Company replaced the March 2007 U.S. debt shelf prospectus with a US$2.5-billion U.S. debt shelf prospectus. US$1.5 billion remains available under the U.S. debt shelf at December 31, 2007.

TransCanada PipeLines Limited In October 2007, TransCanada PipeLines Limited (TCPL) issued US$1.0 billion of Senior Unsecured Notes under the U.S. debt shelf prospectus filed in September 2007. These notes mature on October 15, 2037 and bear interest at a rate of 6.20 per cent. The effective interest rate at issuance was 6.30 per cent.

NOVA Gas Transmission Ltd. Debentures issued by NOVA Gas Transmission Ltd. (NGTL) amount to $225 million and have retraction provisions that entitle the holders to require redemption of up to eight per cent of the then outstanding principal plus accrued and unpaid interest on specified repayment dates. No redemptions were made at December 31, 2007.

On January 31, 2008, NGTL retired $105 million of 6.0 per cent Medium-Term Notes.

TransCanada PipeLine USA Ltd.

In February 2007, TransCanada PipeLine USA Ltd. established a US$1.0 billion committed, unsecured credit facility, consisting of a US$700-million five-year term loan and a US$300-million five-year, extendible revolving facility. A floating interest rate based on the three- month London Interbank Offered Rate (LIBOR) plus 22.5 basis points is charged on the balance outstanding and a facility fee of 7.5 basis points is charged on the entire facility. US$1.0 billion from this facility and an additional US$100 million from an existing demand line were used to partially finance the acquisitions of ANR and additional interest in Great Lakes and the Company’s additional investment in PipeLines LP. There was an outstanding balance of US$860 million on the credit facility and nil on the demand line at December 31, 2007.

ANR Pipeline Company – Voluntary Withdrawal of Listing In March 2007, ANR Pipeline Company (ANR Pipeline) voluntarily withdrew, from the New York Stock Exchange, the listing of its 9.625 per cent Debentures due 2021, 7.375 per cent Debentures due 2024, and 7.0 per cent Debentures due 2025. With the delisting, which became effective April 12, 2007, ANR Pipeline deregistered these securities with the U.S. Securities and Exchange Commission.

TC PipeLines, LP In February 2007, PipeLines LP increased the size of its syndicated revolving credit and term loan facility in connection with its acquisition of a 46.4 per cent interest in Great Lakes. The amount available under the facility increased to US$950 million from US$410 million and consisted of a US$700-million senior term loan and a US$250-million senior revolving credit facility, with US$194 million of the senior term loan amount terminated upon closing of the Great Lakes acquisition. An additional US$18 million of the senior term loan was terminated due to a principal payment made in November 2007. A floating interest rate based on the three-month LIBOR plus 55 basis points is charged on the senior term Attachment 1 CAPP 11 Page 106 of 142 102 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

loan and a floating interest rate based on the one-month LIBOR plus 35 basis points is charged on the senior revolving credit facility. A facility fee of 10 basis points is charged on the US$250-million senior revolving credit facility.

Sensitivity A one per cent change in interest rates would have the following effects assuming all other variables were to remain constant:

(millions of dollars) Increase Decrease Effect on fair value of fixed interest rate debt (1,023) 1,185 Effect on interest expense of variable interest rate debt 7 (7)

Financial Charges

Year ended December 31 (millions of dollars) 2007 2006 2005 Interest on long-term debt 948 846 849 Interest on junior subordinated notes 43 Interest on short-term debt 48 23 23 Capitalized interest (68) (60) (24) Amortization and other financial charges(1) (28) 16 (12) 943 825 836

(1) Amortization and other financial charges in 2007 includes amortization of transaction costs and debt discounts calculated using the effective interest method.

The Company made interest payments of $966 million in 2007 (2006 – $771 million; 2005 – $838 million).

NOTE 10 LONG-TERM DEBT OF JOINT VENTURES 2007 2006 Outstanding loan amounts Outstanding Interest Outstanding Interest (millions of dollars) Maturity DatesDecember 31(1) Rate(2)(3) December 31(1) Rate(4) NORTHERN BORDER PIPELINE COMPANY Senior Unsecured Notes (2007 – US$232; 2006 – US$316) 2009 to 2021229 7.7% 368 6.9% Bank Facility (2007 – US$83) 2012 82 5.3% IROQUOIS GAS TRANSMISSION SYSTEM, L.P. Senior Unsecured Notes (2007 and 2006 – US$165) 2010 to 2027162 7.4% 192 7.5% Bank Loan (2007 – US$7; 2006 – US$15) 20087 7.4% 17 6.2% GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP(5) Senior Unsecured Notes (2006 – US$225) – 262 7.8% BRUCE POWER L.P. AND BRUCE POWER A L.P. Capital Lease Obligations 2018243 7.5% 250 7.5% TRANS QUEBEC´ & MARITIMES PIPELINE INC. Bonds 2009 to 2010137 6.0% 138 6.0% Term Loan 201128 4.6% 32 4.4% Other 2008 to 201315 4.5% 19 3.8% 903 1,278 Less: Current Portion of Long-Term Debt of Joint Ventures 30 142 873 1,136 Attachment 1 CAPP 11 Page 107 of 142 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 103

(1) Amounts outstanding represent TransCanada’s proportionate share. (2) Interest rates are the effective interest rates except those pertaining to long-term debt issued for TQM’s regulated operations, in which case the weighted average interest rate is presented as required by the regulators. (3) Weighted average and effective interest rates are stated as at the respective outstanding dates. At December 31, 2007, the effective interest rate resulting from swap agreements were 7.5 per cent on the Iroquois bank loan (2006 – weighted average rate of 6.9 per cent). (4) Weighted average interest rates are stated at the respective outstanding dates. (5) TransCanada increased its effective ownership in Great Lakes to 68.5 per cent from 50.0 per cent on February 22, 2007. The Company commenced consolidation of Great Lakes, on a prospective basis, effective February 22, 2007.

The long-term debt of joint ventures is non-recourse to TransCanada, except that TransCanada has provided certain pro-rata guarantees related to the capital lease obligations of Bruce Power. The security provided with respect to the debt by each joint venture is limited to the rights and assets of that joint venture and does not extend to the rights and assets of TransCanada, except to the extent of TransCanada’s investment. Other joint venture debt includes a demand loan secured by a first interest in all personal property, a floating charge over all real property and a demand collateral leasehold mortgage in the amount of $20 million creating a first fixed and specific charge over the joint venture’s leasehold interest in all land and premises. TQM’s Bonds are secured by a first interest in all TQM real and immoveable property and rights, a floating charge on all residual property and assets, and a specific interest on Bonds of TQM Finance Inc. and on rights under all licenses and permits relating to the TQM pipeline system and natural gas transportation agreements.

Subject to meeting certain requirements, the Bruce Power capital lease agreements provide for renewals commencing January 1, 2019. The first renewal is for a period of one year and each of 12 renewals thereafter is for a period of two years.

The Company’s proportionate share of principal repayments resulting from maturities and sinking fund obligations of the non-recourse joint venture debt is approximately as follows: 2008 – $21 million; 2009 – $161 million; 2010 – $185 million; 2011 – $36 million; and 2012 – $95 million.

The Company’s proportionate share of principal payments resulting from the capital lease obligations of Bruce Power is approximately as follows: 2008 – $9 million; 2009 – $11 million; 2010 – $13 million; 2011 – $15 million; and 2012 – $18 million.

In April 2007, Northern Border established a US$250-million five-year bank facility. A portion of the bank facility was drawn to refinance US$150 million of the Senior Unsecured Notes that matured on May 1, 2007, with the balance available to fund Northern Border’s ongoing operations.

Sensitivity A one per cent change in interest rates would have the following effects assuming all other variables were to remain constant:

(millions of dollars) Increase Decrease Effect on fair value of fixed interest rate debt (13) 15 Effect on interest expense of variable interest rate debt 1 (1)

Financial Charges of Joint Ventures

Year ended December 31 (millions of dollars) 2007 2006 2005 Interest on long-term debt 50 67 60 Interest on capital lease obligations 18 19 3 Short-term interest and other financial charges 4 31 Deferrals and amortization 3 32 75 92 66

The Company’s proportionate share of the interest payments of joint ventures was $45 million in 2007 (2006 – $73 million; 2005 – $62 million).

The Company’s proportionate share of interest payments from the capital lease obligations of Bruce Power was $26 million in 2007 (2006 – $20 million; 2005 – $3 million). Attachment 1 CAPP 11 Page 108 of 142 104 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 11 JUNIOR SUBORDINATED NOTES

2007 Effective Outstanding loan amount Outstanding Interest (millions of dollars) Maturity Dates December 31 Rate TRANSCANADA PIPELINES LIMITED U.S. dollars (2007 – US$1,000) 2017 975 6.5%

In April 2007, TCPL issued US$1.0 billion of Junior Subordinated Notes, maturing in 2067 and bearing interest of 6.35 per cent per year until May 15, 2017, when interest will convert to a floating rate, reset quarterly to the three-month LIBOR plus 221 basis points. The Company has the option to defer payment of interest for periods of up to ten years without giving rise to a default and without permitting acceleration of payment under the terms of the Junior Subordinated Notes. The Company would be prohibited from paying dividends during any deferral period. The Junior Subordinated Notes are subordinated in right of payment to existing and future senior indebtedness and are effectively subordinated to all indebtedness and obligations of TCPL. The Junior Subordinated Notes are callable at the Company’s option at any time on or after May 15, 2017 at 100 per cent of the principal amount of the Junior Subordinated Notes plus accrued and unpaid interest to the date of redemption. The Junior Subordinated Notes are callable earlier upon the occurrence of certain events and at the Company’s option, in whole or in part, at an amount equal to the greater of 100 per cent of the principal amount of the Junior Subordinated Notes plus accrued and unpaid interest to the date of redemption and an amount determined by formula in accordance with the terms of the Junior Subordinated Notes. The Junior Subordinated Notes were issued under the U.S. shelf prospectus filed in March 2007.

Sensitivity A one per cent change in interest rates would have the following effects assuming all other variables were to remain constant:

(millions of dollars) Increase Decrease Effect on fair value of Junior Subordinated Notes (61) 66

NOTE 12 DEFERRED AMOUNTS

December 31 (millions of dollars) 2007 2006 Regulatory liabilities 525 386 Fair value of derivative contracts 205 254 Employee benefit plans 196 195 Asset retirement obligations 88 45 Hedging deferrals(1) – 84 Other 93 65 1,107 1,029

(1) Changes in GAAP required the Company to record the effective portion and changes in fair value of cash flow and fair value hedges in Other Comprehensive Income and Net Income, respectively, effective January 1, 2007. Prior to this date, the fair value of certain hedges was deferred and recognized in income when the financial instrument had settled.

NOTE 13 REGULATED BUSINESSES

Regulatory assets and liabilities represent future revenues that are expected to be recovered from or refunded to customers in future periods. They stem from the rate-setting process associated with certain costs and revenues, incurred in the current period or in prior periods and the under- or over-collection of revenues in the current or prior periods.

Canadian Regulated Operations Canadian natural gas transmission services are supplied under gas transportation tariffs that provide for cost recovery including return of and return on capital as approved by the applicable regulatory authorities. Attachment 1 CAPP 11 Page 109 of 142 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 105

Rates charged by TransCanada’s wholly owned and partially owned Canadian regulated pipelines are set typically through a process that involves filing an application with the regulators for a change in rates. Regulated rates are underpinned by the total annual revenue requirement, which comprises a specified annual return on capital, including debt and equity, and all necessary operating expenses, taxes and depreciation.

TransCanada’s Canadian regulated pipelines have generally been subject to a cost-of-service model wherein forecasted costs, including a return on capital, equal the revenues for the upcoming year. To the extent that actual costs are more or less than the forecasted costs, the regulators generally allow the difference to be deferred to a future period and recovered or refunded in revenues at that time. Costs for which the regulator does not allow the difference between actual and forecast to be deferred are included in the determination of net income in the year they are incurred.

The Canadian Mainline, Foothills and TQM pipelines are regulated by the NEB under the National Energy Board Act. At December 31, 2007, the Alberta System was regulated by the EUB primarily under the provisions of the Gas Utilities Act (Alberta) and the Pipeline Act (Alberta). The EUB was reorganized into the AUC and the Energy Resource Conservation Board effective January 1, 2008. The AUC regulates the Alberta System’s construction and operation of facilities, and the terms and conditions of services, including rates. The NEB regulates the construction and operation of facilities, and the terms and conditions of services, including rates, for the Company’s other Canadian regulated transmission systems.

Canadian Mainline In February 2007, TransCanada reached a five-year tolls settlement with interested stakeholders for 2007 to 2011 on the Canadian Mainline. In May 2007, the NEB approved the application as filed, including TransCanada’s request that interim tolls for 2007 be made final. The terms of the settlement are effective January 1, 2007, to December 31, 2011.

As part of the settlement, TransCanada and its stakeholders agreed that the cost of capital will reflect a rate of return on common equity (ROE) as determined by the NEB’s ROE formula, on a deemed common equity ratio of 40 per cent, an increase from 36 per cent. The allowed ROE in 2007 for Canadian Mainline was 8.46 per cent. The remaining capital structure consists of short- and long-term debt following the agreed-upon redemption of the US$460-million Preferred Securities.

The settlement also established the Canadian Mainline’s fixed operating, maintenance and administration (OM&A) costs for each year of the five years. Any variance between actual OM&A costs and those agreed to in the settlement will accrue to TransCanada from 2007 to 2009. Variances in OM&A costs will be shared equally between TransCanada and its customers in 2010 and 2011. All other cost elements of the revenue requirement will be treated on a flow-through basis. The settlement also allows for performance-based incentive arrangements that will provide mutual benefits to both TransCanada and its customers.

Alberta System The Alberta System operated under the 2005-2007 Revenue Requirement Settlement. This settlement, approved by the EUB in June 2005, encompassed all elements of the Alberta System’s revenue requirement for 2005, 2006 and 2007 and established methodologies for calculating the revenue requirement for all three years, based on the recovery of all cost components and the use of deferral accounts.

OM&A and certain other costs, including foreign exchange on interest payments, uninsured losses and amortization of severance costs, were fixed for each of the three years and any difference between actual and forecast fixed costs will be included in the determination of net income in the year they are incurred. Costs other than those that are fixed are forecast at the beginning of each year and included in calculating the revenue requirement. Any variance between forecasted and actual costs is included in a deferral account and adjusted in the following year’s revenue requirement. The settlement also set the ROE using the formula for determining the annual generic ROE established in the EUB’s General Cost of Capital Decision 2004-052 on a deemed common equity of 35 per cent for all three years. The allowed ROE in 2007 was 8.51 per cent.

Other Canadian Pipelines In February 2007, the NEB approved TransCanada’s application to integrate the BC System and Foothills and charge tolls based on the integrated structure. The two systems were integrated effective April 1, 2007, resulting in a transfer of BC System regulatory assets and liabilities to Foothills. The ROE for Foothills, which is based on the NEB-allowed ROE formula established in the RH-2-94 Multi-Pipeline Cost of Capital proceeding, was 8.46 per cent in 2007 on a deemed equity component of 36 per cent.

The NEB approves pipeline tolls on an annual cost of service basis for Foothills and TQM, similar to the basis it uses to approve tolls on the Canadian Mainline. The NEB allows each pipeline to charge a schedule of tolls based on the estimated cost of service. This schedule of tolls is used for the current year until a new toll filing is made for the following year. Differences between the estimated cost of service and the actual cost of service are calculated and reflected in the subsequent year’s tolls.

TQM filed an application with the NEB in November 2007 for approval of a three-year partial negotiated settlement for the years 2007 to 2009. The partial settlement represents agreement on all cost of service matters for the three-year period, with the exception of cost of capital and associated income taxes. In December 2007, TQM filed a cost of capital application with the NEB for the years 2007 and 2008. The application requests approval of an 11 per cent return on deemed common equity of 40 per cent. TQM currently is subject to an NEB ROE Attachment 1 CAPP 11 Page 110 of 142 106 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

formula on deemed common equity of 30 per cent. TQM tolls remain in effect on an interim basis pending a decision on the application. Any adjustments to the interim tolls will be recorded in accordance with the decision.

U.S. Regulated Operations TransCanada’s wholly owned and partially owned U.S. pipelines are ‘natural gas companies’ operating under the provisions of the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and the Energy Project Act of 2005, and are subject to the jurisdiction of the FERC. The Natural Gas Act of 1938 grants the FERC authority over the construction and operation of pipelines and related facilities. The FERC also has authority to regulate rates for natural gas transportation in interstate commerce.

ANR ANR’s operations are regulated primarily by the FERC. ANR’s natural gas storage and transportation services that are regulated by the FERC also operate under approved tariff rates. ANR Pipeline’s rates were established pursuant to a settlement approved by a FERC order issued in February 1998 and became effective in November 1997. These tariffs include maximum and minimum rate levels for services and permit ANR to discount or negotiate rates on a non-discriminatory basis. ANR Storage Company’s rates were established pursuant to a settlement approved by the FERC in April 1990 and became effective in June 1990. None of ANR’s FERC-regulated operations are required to file for new rates at any time in the future, nor are any of the operations prohibited from filing a case for new rates.

GTN GTN is regulated by the FERC. Both of GTN’s systems, the GTN System and North Baja, operate in accordance with FERC-approved tariffs that establish maximum and minimum rates for various services. The pipelines are permitted to discount or negotiate these rates on a non-discriminatory basis. The GTN System filed a general rate case in June 2006 under the Natural Gas Act of 1938. The GTN System filed a Stipulation and Agreement with the FERC on November 1, 2007, that comprised an uncontested settlement of all aspects of its 2006 rate case. The FERC approved the settlement on January 7, 2008, and GTN’s financial results in 2007 reflect the terms of the settlement. In 2008, the GTN System will refund to customers amounts collected above the settlement rates for the period from January 1, 2007 through October 31, 2007. Under the settlement, a five-year moratorium period was set in which the GTN System and the settling parties are prohibited from taking certain actions under the Natural Gas Act of 1938, including any filings. The GTN System is also required to file a rate case within seven years. Rates for capacity on North Baja were established in 2002 in the FERC’s initial order certificating construction and operations of North Baja.

Great Lakes Great Lakes’ rates and tariffs are regulated by the FERC. In 2000, Great Lakes negotiated an overall rate settlement with its customers that established the current rates. The settlement expired October 31, 2005, with no requirement to file for new rates at any time in the future, nor is Great Lakes prohibited from filing such a rate case.

Portland In 2003, Portland received final approval from the FERC of its general rate case under the Natural Gas Act of 1938. Portland is required to file a general rate case under Section 4 of the Natural Gas Act of 1938, with a proposed effective date of April 1, 2008.

Northern Border Northern Border and its customers reached a settlement in September 2006 that was approved by the FERC in November 2006. The settlement established maximum long-term mileage-based rates and charges for transportation on Northern Border’s system. Beginning January 1, 2007, overall rates were reduced by approximately five per cent from the rates in effect prior to the filing. The settlement provided for seasonal rates, which vary on a monthly basis, for short-term transportation services. It also included a three-year moratorium on filing rate cases and on participants filing challenges to rates, and required that Northern Border file a general rate case within six years. Northern Border was required to provide services under negotiated and discounted rates on a non-discriminatory basis. Attachment 1 CAPP 11 Page 111 of 142 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 107

Regulatory Assets and Liabilities Remaining Recovery/ Settlement Year ended December 31 (millions of dollars) 2007 2006 Period (years) Regulatory Assets Operating and debt-service regulatory assets(1) 85 1 Unrealized losses on derivatives – Canadian Mainline(2) 63 44 1 - 3 Unrealized losses on derivatives – Foothills(2) 33 33 6 Unrealized losses on derivatives – Alberta System(2) 10 7 1 - 5 Foreign exchange on long-term debt principal – Alberta System(3) 34 33 22 Deferred income tax on carrying costs capitalized during construction of utility plant – ANR(4) 20 n/a Unamortized issue costs on Preferred Securities – Canadian Mainline(5) 19 19 Phase II preliminary expenditures – Foothills(6) 18 20 8 Transitional other benefit obligations(7) 16 18 9 Unamortized post-retirement benefits – ANR(8) 13 4 - 6 Other 25 23 n/a Total Regulatory Assets (Other Assets) 336 178

Regulatory Liabilities Operating and debt-service regulatory liabilities(1) 3 70 1 Foreign exchange on long-term debt – Alberta System(9) 168 60 5 - 22 Foreign exchange on long-term debt – Canadian Mainline(9) 61 195 1 - 3 Foreign exchange on long-term debt – Foothills(9) 37 19 6 Foreign exchange gain on redemption of Preferred Securities, net of income tax of $15 million – Canadian Mainline(5) 150 4 Post-retirement benefits other than pension – ANR(10) 38 n/a Fuel tracker – ANR(11) 29 n/a Negative salvage – ANR(12) 17 n/a Post-retirement benefits other than pension – GTN System(13) – 19 4 Other 22 23 n/a Total Regulatory Liabilities (Deferred Amounts) 525 386

(1) Operating and debt-service regulatory assets and liabilities represent the accumulation of cost and revenue variances approved by the regulatory authority for inclusion in the determination of tolls for the immediate following calendar year. In the absence of rate-regulated accounting, GAAP would have required the inclusion of variances resulting in a regulatory asset in the operating results of the year in which the variances were incurred. There is no difference between rate-regulated and GAAP accounting treatments if the variances yield a regulatory liability. Pre-tax operating results would have been $85 million lower in 2007 (2006 – no change) in the absence of rate-regulated accounting. (2) Unrealized losses on derivatives represent the net position of fair value gains and losses on cross-currency and interest-rate swaps, and forward currency contracts which act as economic hedges. The cross-currency swaps pertain to foreign debt instruments associated with the Canadian Mainline, Foothills and Alberta System. The Canadian Mainline interest-rate swaps were entered into as a result of the Mainline Interest Rate Management Program approved by the NEB as a component of the 1996 - 1999 Incentive Cost Recovery and Revenue Settlement. Interest savings or losses are determined when the interest swaps are settled. In the absence of rate-regulated accounting, GAAP would have required the inclusion of these fair value losses in the operating results of the Canadian Mainline, as they were not documented as hedges for accounting purposes. In the absence of rate-regulated accounting, pre-tax operating results of the Canadian Mainline would have been $19 million lower in 2007 (2006 – $1 million lower). The regulatory asset with respect to Foothills represents the unrealized losses for the ineffective period of the derivative from inception to December 31, 2005. In the absence of rate-regulated accounting, pre-tax operating results of Foothills would have been the same in 2007 and 2006. The regulatory asset related to the Alberta System represents cross-currency swaps on foreign debt instruments and forward foreign currency contracts related to hedging foreign exchange risk inherent in contractual obligations to purchase materials for construction projects. In the absence of rate-regulated accounting, pre-tax operating results of the Alberta System would have been $3 million lower in 2007 (2006 – no change). (3) The foreign exchange on long-term debt principal account in the Alberta System, as approved by the EUB, is designed to facilitate the recovery or refund of foreign exchange gains and losses over the life of the foreign currency debt issues. The estimated gain or loss on Attachment 1 CAPP 11 Page 112 of 142 108 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

foreign currency debt is amortized over the remaining years of the longest outstanding U.S. debt issue. The annual amortization amount is included in the determination of tolls for the year. (4) Rate-regulated accounting allows the capitalization of both an equity and an interest component for the carrying costs of funds used during the construction of utility assets. The capitalized Allowance for Funds Used During Construction (AFUDC) is depreciated as part of the total depreciable plant after the utility assets are placed in service. Equity AFUDC is not subject to income taxes, therefore, a deferred tax provision is recorded with an offset to a corresponding regulatory asset. (5) In July 2007, the Company redeemed the US$460-million 8.25 per cent Preferred Securities that underpinned the Canadian Mainline’s investment base. Upon redemption of the securities, there was a realized foreign exchange gain that will flow through, net of income tax, to Canadian Mainline’s customers over the five years of the settlement approved by the NEB in May 2007. In addition, the issue costs on the Preferred Securities will be amortized over 20 years beginning January 1, 2007. In the absence of rate-regulated accounting, GAAP would have required the foreign exchange gain and the unamortized issue costs to be included in the operating results of the Canadian Mainline in the year the securities were redeemed. This would have increased/(decreased) pre-tax operating results by $165 million and $(19) million arising from the foreign exchange gain and issue costs, respectively, in 2007. (6) Phase II preliminary expenditures are costs incurred by Foothills prior to 1981 related to development of Canadian facilities to deliver Alaskan gas. These costs have been approved by the regulator for collection through straight-line amortization over the period November 1, 2002 to December 31, 2015. In the absence of rate-regulated accounting, GAAP would have required these costs to be expensed in the year incurred, increasing pre-tax operating results by $2 million in 2007 (2006 – $3 million higher). (7) The regulatory asset with respect to the annual transitional other benefit obligations is being amortized over 17 years, from January 1, 2000 to December 31, 2016, at which time the full transitional obligation will have been recovered through tolls. In the absence of rate-regulated accounting, pre-tax operating results would have been $2 million higher in 2007 (2006 – $2 million higher). (8) An amount is recovered in ANR’s rates for Post-retirement Benefits Other than Pensions (PBOP). A curtailment and special termination benefits charge related to PBOP for a closed group of retirees was recorded as a regulatory asset and is being amortized at a rate of $3 million per year through 2011. In the absence of rate-regulated accounting, pre-tax operating results would have been $3 million higher in 2007. (9) Foreign exchange on long-term debt of the Canadian Mainline, the Alberta System and Foothills represents the variance resulting from revaluing foreign currency-denominated debt instruments to the current foreign exchange rate from the historic foreign exchange rate. Foreign exchange gains and losses realized when foreign debt matures or is redeemed early are expected to be recovered or refunded through the determination of future tolls. In the absence of rate-regulated accounting, GAAP would have required the inclusion of these unrealized gains or losses either on the balance sheet or income statement depending on whether the foreign debt is designated as a hedge of the Company’s net investment in foreign assets. (10) An amount is recovered in ANR’s rates for post-employment and post-retirement benefits. This regulatory liability represents the difference between the amount collected in rates and the amount of post-employment and post-retirement benefit expense. (11) ANR’s tariff stipulates a fuel tracker mechanism to track over- or under-collections of fuel used and lost and gas unaccounted for (collectively, fuel). The fuel tracker represents the difference between the value of ‘in-kind’ natural gas retained from shippers and the actual amount of natural gas used for fuel by ANR. Any over- or under-collections are returned to or collected from shippers through a prospective annual adjustment to fuel retention rates. A regulatory asset or liability is established for the difference between ANR’s actual fuel use and amounts collected through its fuel rates. Pre-tax operating results are not affected by the fuel tracker mechanism. (12) ANR collects in its current rates an allowance for negative salvage related to its offshore transmission and gathering facilities. The allowance for negative salvage is collected as a component of depreciation expense and recorded to a negative salvage account within the reserve for accumulated depreciation. Costs associated with the abandonment of offshore transmission and with gathering facilities are recorded against the negative salvage reserve. (13) An amount was recovered for PBOP in the GTN System’s rates under a 1996 rate case settlement. This regulatory liability represents the difference between the amount collected in rates and the amount of PBOP expense determined under GAAP. Under the terms of the 2007 settlement, the GTN System’s PBOP regulatory liability is deemed to be nil and, as such, has been transferred to other deferred amounts. The December 31, 2006 balance is being amortized over five years.

As prescribed by regulators, the taxes payable method of accounting for income taxes is used for toll-making purposes on Canadian regulated natural gas transmission operations. As permitted by GAAP, this method is also used for accounting purposes, since there is a reasonable expectation that future income taxes payable will be included in future costs of service and recorded in revenues at that time. Consequently, future income tax liabilities have not been recognized, as it is expected that when these amounts become payable, they will be recovered through future rates. In the absence of rate-regulated accounting, GAAP would have required the recognition of future income tax liabilities. If the liability method of accounting had been used, additional future income tax liabilities of $1,138 million would have been recorded at December 31, 2007 (2006 – $1,355 million) and would have been recoverable from future revenues. In 2007, reductions in enacted Canadian federal and provincial corporate future income tax rates resulted in a decrease of $123 million to this unrecorded future income tax liability. The liability method of accounting is used for both accounting and toll-making purposes for the U.S. natural gas transmission operations. Attachment 1 CAPP 11 Page 113 of 142 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 109

Under this method, future income tax assets and liabilities are recognized based on the differences between financial statement carrying amounts and the tax basis of the assets and liabilities. This method is also used for toll-making purposes for the U.S. natural gas transmission operations. As a result, current year’s revenues include a tax provision that is calculated based on the liability method of accounting and there is no recognition of a related regulatory asset or liability.

NOTE 14 PREFERRED SECURITIES

In July 2007, TransCanada exercised its right to redeem the US$460-million 8.25 per cent preferred securities due 2047. The preferred securities were redeemed for cash at par as part of the tolls settlement on the Canadian Mainline. The foreign exchange gain realized on redemption of the securities will flow through to the Canadian Mainline shippers over a five-year period, pursuant to the settlement.

NOTE 15 NON-CONTROLLING INTERESTS

The Company’s non-controlling interests included in the consolidated balance sheet were as follows.

December 31 (millions of dollars) 2007 2006 Non-controlling interest in PipeLines LP 539 287 Preferred shares of subsidiary 389 389 Other 71 79 999 755

The Company’s non-controlling interests included in the consolidated income statement are as follows.

Year ended December 31 (millions of dollars) 2007 2006 2005 Non-controlling interest in PipeLines LP 65 43 52 Preferred share dividends of subsidiary 22 22 22 Other 10 13 10 97 78 84

The non-controlling interest in PipeLines LP as at December 31, 2007, represented the 67.9 per cent interest not owned by TransCanada (2006 – 86.6 per cent). Other non-controlling interests as at December 31, 2007, included the 38.3-per-cent (2006 – 38.3 per cent) non-controlling interest in Portland held by an unrelated partner.

TransCanada received revenues of $2 million from PipeLines LP in 2007 (2006 – $1 million; 2005 – $1 million) and $7 million from Portland in 2007 (2006 – $6 million; 2005 – $6 million) for services it provided.

Preferred Shares of Subsidiary

Number of Dividend Rate Redemption December 31 Shares Per Share Price Per Share 2007 2006 (thousands) (millions of dollars) (millions of dollars) Cumulative First Preferred Shares of Subsidiary Series U 4,000 $2.80 $50.00 195 195 Series Y 4,000 $2.80 $50.00 194 194 389 389

The authorized number of preferred shares of TCPL issuable in series is unlimited. All of the cumulative first preferred shares of TCPL are without par value.

The issuer may redeem at $50 per share the Series U shares on or after October 15, 2013, and the Series Y shares on or after March 5, 2014. Attachment 1 CAPP 11 Page 114 of 142 110 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 16 COMMON SHARES

Number of Shares Amount (thousands) (millions of dollars) Outstanding at January 1, 2005 484,914 4,711 Exercise of options 2,322 44 Outstanding at December 31, 2005 487,236 4,755 Exercise of options 1,739 39 Outstanding at December 31, 2006 488,975 4,794 Issuance of common shares(1) 45,390 1,683 Dividend reinvestment and share purchase plan 4,147 157 Exercise of options 1,253 28 Outstanding at December 31, 2007 539,765 6,662

(1) Net of underwriting commissions and future income taxes.

Common Shares Issued and Outstanding The Company is authorized to issue an unlimited number of common shares without par value.

In January 2007, TransCanada filed a short form shelf prospectus with securities regulators in Canada and the U.S. to allow for the offering of up to $3.0 billion of common shares, preferred shares and/or subscription receipts in Canada and the U.S. until February 2009. In 2007, the Company issued 45.4 million common shares at a price of $38.00 each, generating gross proceeds of approximately $1.725 billion. The proceeds were used towards financing the acquisitions of ANR and an increased ownership interest in Great Lakes.

Net Income per Share Basic and diluted earnings per share are calculated based on the weighted average number of common shares outstanding during the year of 529.9 million and 532.5 million (2006 – 488.0 million and 490.6 million; 2005 – 486.2 million and 489.1 million), respectively. The increase in the weighted average number of shares for the diluted earnings per share calculation is due to the options exercisable under TransCanada’s Stock Option Plan.

Stock Options Weighted Number of Average Options Options Exercise Prices Exercisable (thousands) (thousands) Outstanding at January 1, 2005 9,965 $20.90 7,239 Granted 1,075 $30.21 Exercised (2,322) $18.57 Cancelled or expired (4) $25.34 Outstanding at December 31, 2005 8,714 $22.67 6,300 Granted 1,841 $34.48 Exercised (1,739) $21.44 Cancelled or expired (17) $30.98 Outstanding at December 31, 2006 8,799 $25.37 5,888 Granted 1,083 $38.10 Exercised (1,253) $22.77 Cancelled or expired (20) $35.08 Outstanding at December 31, 2007 8,609 $27.32 6,118 Attachment 1 CAPP 11 Page 115 of 142 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 111

Stock options outstanding at December 31, 2007, were as follow: Options Outstanding Options Exercisable Weighted Weighted Weighted Average Average Average Number of Remaining Exercise Number of Exercise Range of Exercise Prices Options Contractual Life Price Options Price (thousands) (years) (thousands) $10.03 to $20.27 1,013 2.9 $15.58 1,013 $15.58 $20.58 to $21.86 1,524 3.8 $21.15 1,524 $21.15 $22.33 to $24.49 1,134 2.1 $22.65 1,134 $22.65 $24.61 to $26.85 1,103 3.1 $26.81 1,103 $26.81 $30.09 to $33.08 1,585 4.8 $31.28 860 $30.81 $35.23 to $36.67 1,180 5.2 $35.25 484 $35.27 $38.10 to $38.14 1,070 6.2 $38.10 – – 8,609 4.0 $27.32 6,118 $24.00

An additional five million common shares were reserved for future issuance under TransCanada’s Stock Option Plan at December 31, 2007. In 2007, TransCanada issued 976,217 and 107,199 options to purchase common shares at a price of $38.10 and $38.14, respectively, under the Company’s Stock Option Plan and the weighted average fair value of each option was determined to be $4.22. The Company used the Black- Scholes model for determining the fair value of options granted applying the following weighted average assumptions for 2007: four years of expected life (2006 and 2005 – four years); 4.1 per cent interest rate (2006 – 4.1 per cent; 2005 – 4.0 per cent); 15 per cent volatility (2006 – 14 per cent; 2005 – 15 per cent); and 3.6 per cent dividend yield (2006 – 3.7 per cent; 2005 – 3.3 per cent). The amount expensed for stock options, with a corresponding increase in contributed surplus, was $4 million in 2007 (2006 – $3 million; 2005 – $3 million).

Shareholder Rights Plan The Company’s Shareholder Rights Plan is designed to encourage the fair treatment of shareholders in connection with any takeover offer for the Company. Under certain circumstances, each common share is entitled to one right that entitles certain holders to purchase two common shares of the Company for the price of one.

Dividend Reinvestment and Share Purchase Plan In 2007, TransCanada’s Board of Directors authorized the issuance of common shares from treasury at a discount of two per cent to participants in the Company’s Dividend Reinvestment and Share Purchase Plan (DRP). Eligible shareholders may reinvest their dividends and make optional cash payments to obtain additional TransCanada common shares under the DRP. Commencing with the dividend payable in April 2007, the DRP shares are provided to the participants at a two per cent discount to the average market price in the five days before dividend payment. Previously, TransCanada purchased shares on the open market and provided them to DRP participants at cost. The Company reserves the right to alter the discount or return to purchasing shares on the open market at any time. In accordance with the DRP, dividends of $157 million were paid in 2007 by the issuance from treasury of 4.1 million common shares.

NOTE 17 RISK MANAGEMENT AND FINANCIAL INSTRUMENTS Risk Management Overview TransCanada has exposure to market, counterparty credit and liquidity risk. The risk management function assists in managing these risks. TransCanada’s primary risk management objective is to protect earnings and cash flow, and ultimately shareholder value. Risk management strategies, policies and limits are designed to ensure TransCanada’s risks and related exposures are in line with the Company’s business objectives and risk tolerance. Risks are managed within limits ultimately established by the Company’s Board of Directors, implemented by senior management and monitored by risk management personnel. TransCanada’s Audit Committee oversees how management monitors compliance with risk management policies and procedures, and management’s review of the adequacy of the risk management framework. Internal audit personnel assist the Audit Committee in its oversight role by performing regular and ad-hoc reviews of risk management controls and procedures, the results of which are reported to the Audit Committee.

Market Risk The Company constructs and invests in large infrastructure projects, purchases and sells commodities, issues short- and long-term debt including amounts in foreign currencies, and invests in foreign operations. These activities expose the Company to market risk from changes in commodity prices, foreign exchange rates and interest rates, which affect the Company’s earnings and the value of the financial instruments it holds. The Company uses derivatives as part of its overall risk management policy to manage exposures to market risk that result from these activities. Attachment 1 CAPP 11 Page 116 of 142 112 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Contracts used to manage market risk generally consist of the following: • Forwards and futures contracts – contractual agreements to purchase or sell a specific financial instrument or commodity at a specified price and date in the future. TransCanada enters into foreign exchange and commodity forwards and futures to mitigate the impact of volatility in foreign exchange rates and commodity prices. • Swaps – contractual agreements between two parties to exchange streams of payments over time according to specified terms. The Company enters into interest rate, cross-currency and commodity swaps to mitigate the impact of changes in interest rates, foreign exchange rates and commodity prices. • Options – contractual agreements to convey the right, but not the obligation, for the purchaser to buy or sell a specific amount of a financial instrument or commodity at a fixed price, either at a fixed date or at any time within a specified period. The Company enters into option agreements to mitigate the impact of changes in interest rates, foreign exchange rates and commodity prices. • Heat rate contracts – contracts for the purchase or sale of power that are priced based on a natural gas index. Commodity Price Risk The Company is exposed to commodity price movements as part of its normal business operations, particularly in relation to the prices of power and natural gas. A number of strategies are used to mitigate these exposures, including the following: • The Company enters into offsetting or back-to-back physical positions and derivative financial instruments to manage market risk exposures created by certain fixed and variable pricing arrangements at different pricing indices and delivery points. • Subject to the Company’s overall risk management policies, the Company commits a significant portion of its power supply to medium- or long-term sales contracts, while reserving an amount of unsold supply to maintain operational flexibility in the overall management of its asset portfolio. • The Company purchases a portion of the natural gas required for its gas-fired cogeneration plants or enters into heat-rate contracts that base the sales price of electricity on the cost of natural gas, effectively locking in a margin. A significant portion of the electricity needed to fulfill the Company’s power requirements is purchased with forward contracts or fulfilled through power generation, thereby reducing the Company’s exposure to fluctuating commodity prices. The Company assesses its commodity contracts and derivative instruments used to manage energy commodity risk to determine the appropriate accounting treatment. Contracts, with the exception of leases, have been assessed to determine whether they meet the definition of a derivative. Certain commodity purchase and sale contracts are derivatives but are not within the scope of CICA Handbook Section 3855 ‘‘Financial Instruments – Recognition and Measurement’’, as they were entered into and continue to be held for the purpose of receipt or delivery in accordance with the Company’s normal purchases and normal sales exemption. Certain other contracts are not within the scope of Section 3855 as they are considered to meet other exemptions. TransCanada manages its exposure to seasonal natural gas price spreads in its natural gas storage business by hedging storage capacity with a portfolio of third-party storage capacity leases and proprietary natural gas purchases and sales. By matching purchase and sale volumes, TransCanada locks in a margin on a back-to-back basis and thereby effectively eliminates its exposure to natural gas market price fluctuations. Natural Gas Inventory Price Risk Effective April 1, 2007, TransCanada began valuing its proprietary natural gas inventory held in storage at fair value, as measured by the one-month forward price for natural gas. At December 31, 2007, $190 million of proprietary natural gas inventory was included in Inventories. The amount recorded in 2007 in Revenues for the net change in the fair value of proprietary natural gas held in inventory was insignificant. A gain of $10 million was recorded in 2007 in Revenues for the net change in fair value of the forward proprietary natural gas purchase and sales contracts. Foreign Exchange and Interest Rate Risk Foreign exchange and interest rate risk is created by fluctuations in the fair values or cash flows of financial instruments due to changes in foreign exchange rates and/or changes in the market interest rates. A portion of TransCanada’s earnings from its Pipelines and Energy operations outside of Canada is generated primarily in U.S. dollars and is subject to currency fluctuations. The performance of the Canadian dollar relative to the U.S. dollar could positively or negatively affect TransCanada’s earnings. This foreign exchange impact is offset by exposures in certain of TransCanada’s businesses and by the Company’s hedging activities. Due to its growing operations in the U.S., including the acquisitions of ANR and increased ownership in Great Lakes and PipeLines LP, TransCanada expects to have a greater exposure to U.S. dollar fluctuations than in prior years. The Company uses foreign currency and interest rate derivatives to manage the foreign exchange and interest rate risks related to its U.S. dollar-denominated debt and other transactions, as well as to manage the interest rate exposures of the Canadian Mainline, Alberta System and Foothills. Certain of the realized gains and losses on these derivatives are shared with shippers on predetermined terms. These gains and losses are deferred as regulatory assets and liabilities until they are recovered from or paid to the shippers in accordance with the terms of the shipping agreements. The Company has fixed-rate long-term debt, which subjects it to interest rate price risk, and has floating interest rate debt, which subjects it to interest rate cash flow risk. The Company uses a combination of forwards, interest rate swaps and options to manage its exposure to these risks. Attachment 1 CAPP 11 Page 117 of 142 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 113

Net Investment in Self-Sustaining Foreign Operations The Company hedges its net investment in self-sustaining foreign operations on an after-tax basis with U.S. dollar-denominated debt, forward contracts, cross-currency interest rate swaps and options. The Company had designated U.S. dollar-denominated debt with a carrying value of $4.7 billion (US$4.7 billion) and a fair value of $4.8 billion (US$4.8 billion) as a net investment hedge at December 31, 2007. The forwards, swaps and options are recorded at their fair value and are included in Other Assets. The fair values and notional or principal amount for the derivatives designated as a net investment hedge were as follow:

2007 2006 Asset/(Liability) Notional or Notional or Principal Principal December 31 (millions of dollars) Fair Value Amount Fair Value Amount U.S. dollar cross-currency swaps (maturing 2009 to 2014) 77 U.S. 350 58 U.S. 400 U.S. dollar options (maturing 2008) 3 U.S. 600 (6) U.S. 500 U.S. dollar forward foreign exchange contracts (maturing 2008) (4) U.S. 150 (7) U.S. 390 76 U.S. 1,100 45 U.S. 1,290

VaR Analysis TransCanada uses a Value-at-Risk methodology (VaR) to estimate the potential impact resulting from its exposure to market risk. VaR estimates the potential change in pre-tax earnings over a given holding period for a specified confidence level. The VaR number calculated and used by TransCanada reflects the 95 per cent probability that the daily change resulting from normal market fluctuations in its liquid positions will not exceed the reported VaR. VaR methodology is a statistically-defined, probability-based approach that takes into consideration market volatilities as well as risk diversification by recognizing offsetting positions and correlations between products and markets. Risks are measured across all products and markets, and risk measures can be aggregated to arrive at a single VaR number. There is currently no uniform industry methodology for estimating VaR. The use of VaR has limitations because it is based on historical correlations and volatilities in commodity prices, interest rates and foreign exchange rates, and assumes that future price movements will follow a statistical distribution. Although losses are not expected to exceed the statistically estimated VaR on 95 per cent of occasions, losses on the other five per cent of occasions could be substantially greater than the estimated VaR. TransCanada’s estimation of VaR includes wholly owned subsidiaries, and incorporates relevant risks associated with each market or business unit. The calculation does not include the Pipelines segment as the rate-regulated nature of the pipeline business reduces the impact of market risks and limits TransCanada’s ability to manage these risks. The Company’s Board of Directors has established a VaR limit, which is monitored on an ongoing basis as part of the Company’s risk management policy. TransCanada’s consolidated VaR was less than $10 million at December 31, 2007.

Counterparty Credit Risk Counterparty credit risk represents the financial loss that the Company would experience if a counterparty to a financial instrument, in which the Company has an amount owing from the counterparty, failed to meet its obligations in accordance with the terms and conditions of its contracts with the Company. Counterparty credit risk is mitigated through established credit management techniques, including conducting financial and other assessments to establish and monitor a counterparty’s creditworthiness, setting exposure limits, monitoring exposures against these limits, utilizing master netting arrangements and obtaining financial assurances where warranted. In general, financial assurances include guarantees, letters of credit and cash. The Company monitors and manages its concentration of counterparty credit risk on an ongoing basis. TransCanada’s maximum counterparty credit exposure at the balance sheet date consists primarily of the carrying amount of non-derivative financial assets as well as the fair value of derivative financial assets. The Company has contracts for the sale of non-financial items. Many of these contracts do not meet the definition of a financial instrument since the underlying volumes are physically delivered during the Company’s normal course of business. Exposure to counterparty credit risk on these non-financial contracts results from the potential of a counterparty defaulting on invoiced amounts owing to TransCanada. These invoiced amounts are included in the Accounts Receivable and Other Assets amounts disclosed in the Non-Derivative Financial Instruments Summary table presented later in this Note. Some of these non-financial contracts do meet the definition of a derivative and are recorded at fair value. The carrying amounts and fair values of financial assets and non-financial derivatives are disclosed in the Non-Derivative Financial Instruments Summary and the Derivative Financial Instruments Summary tables presented later in this Note. Attachment 1 CAPP 11 Page 118 of 142 114 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Company does not have any significant concentrations of counterparty credit risk and the majority of the counterparty credit exposure is with counterparties who are investment grade.

The Company has reached agreements for allowed unsecured claims with certain subsidiaries of Calpine Corporation (Calpine), former shippers on TransCanada’s pipeline systems that have filed for bankruptcy protection, as discussed in Note 25.

Liquidity Risk Liquidity risk is the risk that TransCanada will not be able to meet its financial obligations as they fall due. The Company’s approach to managing liquidity risk is to ensure that it always has sufficient cash and credit facilities to meet its obligations when due, under both normal and stressed conditions, without incurring unacceptable losses or damage to the Company’s reputation.

Management typically forecasts cash flows for a period of 12 months to identify financing requirements. These requirements are then addressed through a combination of committed and demand credit facilities and access to capital markets, as discussed in the Capital Management section in this Note.

The following tables detail the remaining contractual maturities for TransCanada’s non-derivative financial liabilities, including both the principal and interest cash flows at December 31, 2007:

Contractual Repayments of Financial Liabilities Payments Due by Period 2009 to 2011 to 2013 and December 31, 2007 (millions of dollars) Total 2008 2010 2012 Thereafter Notes payable 421 421 – – – Long-term debt and junior subordinated notes 13,908 556 1,619 2,051 9,682 Long-term debt of joint ventures 903 30 370 164 339 Total contractual repayments 15,232 1,007 1,989 2,215 10,021

Interest Payments on Financial Liabilities Payments Due by Period 2009 to 2011 to 2013 and December 31, 2007 (millions of dollars) Total 2008 2010 2012 Thereafter Interest payments on long-term debt and junior subordinated notes 11,566 895 1,636 1,464 7,571 Interest payments on long-term debt of joint ventures 332 55 85 53 139 Total interest payments 11,898 950 1,721 1,517 7,710 Attachment 1 CAPP 11 Page 119 of 142 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 115

Capital Management The primary objective of capital management is to ensure TransCanada’s strong credit rating is maintained to support its businesses and maximize shareholder value. This overall objective and policy for managing capital remained unchanged in 2007 from the prior year.

TransCanada manages its capital structure in a manner consistent with the risk characteristics of the underlying assets. The Company’s management considers its capital structure to consist of net debt, Non-Controlling Interests and Shareholders’ Equity. Net debt is comprised of Notes Payable, Long-Term Debt, Junior Subordinated Notes and Preferred Securities less Cash and Cash Equivalents. Net debt only includes obligations that the Company controls and manages. Consequently, it does not include Cash and Cash Equivalents, Notes Payable and Long-Term Debt of TransCanada’s joint ventures.

The capital structure at December 31, 2007 was as follows:

(millions of dollars) Notes payable 407 Long-term debt 12,933 Junior subordinated notes 975 Cash and cash equivalents (333) Net debt 13,982 Non-controlling interests 999 Shareholders’ equity 9,785 Total equity 10,784 Total capital 24,766

Fair Values The fair value of Cash and Cash Equivalents and Notes Payable approximates their carrying amounts due to the short time period to maturity. The fair value of foreign exchange and interest rate derivatives has been calculated using year-end market rates. The fair value of power, natural gas and heat rate derivatives has been calculated using estimated forward prices for the relevant period.

Fair values of financial instruments are determined by reference to quoted bid or asking price, as appropriate, in active markets at period-end dates. In the absence of an active market, the Company determines fair value by using valuation techniques that refer to observable market data or estimated market prices. These include comparisons with similar instruments that have observable market prices, option pricing models and other valuation techniques commonly used by market participants. Fair values determined using valuation models require the use of assumptions about the amount and timing of estimated future cash flows and discount rates. In making these assumptions, the Company looks primarily to readily observable external market input factors such as interest rate yield curves, currency rates, and price and rate volatilities as applicable.

The fair value of the Company’s Long-Term Debt was estimated based on quoted market prices for the same or similar debt instruments and, when such information was not available, by discounting future payments of interest and principal at estimated interest rates that were made available to the Company at December 31, 2007. The fair value of Preferred Securities was determined using market prices for the same or similar issues. Attachment 1 CAPP 11 Page 120 of 142 116 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Fair Value of Long-Term Debt and Other Long-Term Securities The carrying and fair values of long-term debt and other long-term securities were as follow: 2007 2006 Carrying Fair Carrying Fair December 31 (millions of dollars) Amount Value Amount Value Long-Term Debt TransCanada PipeLines Limited(1) 8,519 9,400 8,549 9,738 NOVA Gas Transmission Ltd. 1,508 1,877 1,648 2,111 TransCanada PipeLine USA Ltd. 850 850 –– ANR Pipeline Company 435 573 Gas Transmission Northwest Corporation 399 383 466 450 TC PipeLines, LP 499 499 463 463 Great Lakes Gas Transmission Limited Partnership 434 519 –– Tuscarora Gas Transmission Company 67 81 86 94 Portland Natural Gas Transmission System 205 214 263 265 Other 17 24 28 28 12,933 14,420 11,503 13,149 Junior Subordinated Notes 975 914 –– 13,908 15,334 11,503 13,149

Long-Term Debt of Joint Ventures Northern Border Pipeline Company 311 329 368 363 Iroquois Gas Transmission System, L.P. 169 180 209 230 Great Lakes Gas Transmission Limited Partnership–– 262 258 Bruce Power L.P. and Bruce Power A L.P. 243 243 250 249 Trans Quebec´ & Maritimes Pipeline Inc. 165 169 171 177 Other 15 16 18 18 903 937 1,278 1,295 14,811 16,271 12,781 14,444 Preferred Securities ––536 532

(1) Carrying amount of Long-Term Debt increased $15 million for fair value adjustments of swap agreements on $150 million and US$200 million of debt. Non-Derivative Financial Instruments Summary The carrying and fair values of non-derivative financial instruments were as follow: Carrying December 31, 2007 (millions of dollars) Amount Fair Value Financial Assets(1) Cash and cash equivalents 504 504 Accounts receivable and other assets(2)(3) 1,231 1,231 Available-for-sale assets(2) 17 17 1,752 1,752

Financial Liabilities(1)(3) Notes payable 421 421 Accounts payable and deferred amounts(4) 1,454 1,454 Long-term debt and junior subordinated notes 13,908 15,334 Long-term debt of joint ventures 903 937 Other long-term liabilities of joint ventures(4) 60 60 16,746 18,206

(1) Consolidated Net Income in 2007 included unrealized gains or losses of nil for the fair value adjustments to each of these financial instruments. (2) The Consolidated Balance Sheet included financial assets of $1,018 million in Accounts Receivable and $230 million in Other Assets at December 31, 2007. (3) Recorded at amortized cost, except for Long-Term Debt adjusted to fair value as noted in Note 9. (4) The Consolidated Balance Sheet included financial liabilities of $1,436 million in Accounts Payable and $78 million in Deferred Amounts at December 31, 2007. Attachment 1 CAPP 11 Page 121 of 142 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 117

Derivative Financial Instruments Summary Information for the Company’s derivative financial instruments is as follows: 2007 December 31 Foreign (all amounts in millions unless otherwise indicated) Power Natural Gas Exchange Interest Derivative Financial Instruments Held for Trading Fair Values(1) Assets $55 $43 $11 $23 Liabilities $(44) $(19) $(79) $(18) Notional Values Volumes(2) Purchases 3,774 47 – – Sales 4,469 64 – – Canadian dollars – – – 615 U.S. dollars – – U.S. 484 U.S. 550 Japanese yen (in billions) – – JPY 9.7 – Cross-currency – – 227/U.S. 157 – Unrealized gains/(losses) in the period(3) $16 $(10) $8 $(5) Realized (losses)/gains in the period(3) $(8) $47 $39 $5 Maturity dates 2008 - 2016 2008 - 2010 2008 - 2012 2008 - 2016

Derivative Financial Instruments in Hedging Relationships(4)(5) Fair Values(1) Assets $135 $19 $ – $2 Liabilities $(104) $(7) $(62) $(16) Notional Values Volumes(2) Purchases 7,362 28 – – Sales 16,367 4 – – Canadian dollars – – – 150 U.S. dollars – – U.S. 113 U.S. 875 Cross-currency – – 136/U.S. 100 – Realized (losses)/gains in the period(3) $(29) $18 $ – $3 Maturity dates 2008 - 2013 2008 - 2010 2008 - 2013 2008 - 2013

(1) Fair value is equal to the carrying value of these derivatives. (2) Volumes for power and natural gas derivatives are in gigawatt hours and billion cubic feet, respectively. (3) All realized and unrealized gains and losses are included in Net Income. Realized gains are included in Net Income after the financial instrument has been settled. (4) All hedging relationships are designated as cash flow hedges except for $2 million of interest-rate derivative financial instruments designated as fair value hedges. (5) Net Income in 2007 included gains of $7 million for the changes in fair value of power and natural gas cash flow hedges that were ineffective in offsetting the change in fair value of their related underlying positions. Net Income in 2007 included a loss of $4 million for the changes in fair value of an interest-rate cash flow hedge that was reclassified as a result of discontinuance of cash flow hedge accounting. The cash flow hedge accounting was discontinued when the anticipated transaction was not probable of occurring by the end of the originally specified time period. Attachment 1 CAPP 11 Page 122 of 142 118 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Balance Sheet Presentation of Derivative Financial Instruments The fair values of the derivative financial instruments in the Company’s Balance Sheet were as follow: December 31 (millions of dollars) 2007 Current Other current assets 160 Accounts payable (144)

Long-term Other assets 204 Deferred amounts (205)

Derivative Financial Instruments of Joint Ventures Included in the Balance Sheet Presentation of Derivatives Financial Instruments table above are amounts related to power derivatives used by certain of the Company’s joint ventures to manage commodity price risk. The Company’s proportionate share of the fair value of these power sales derivatives was $75 million at December 31, 2007. These contracts mature from 2008 to 2013. The Company’s proportionate share of the notional sales volumes of power associated with this exposure was 7,300 gigawatt hours (GWh) at December 31, 2007. The Company’s proportionate share of the notional purchased volumes of power associated with this exposure was 50 GWh at December 31, 2007.

NOTE 18 INCOME TAXES

Provision for Income Taxes Year ended December 31 (millions of dollars) 2007 2006 2005 Current Canada 367 264 499 Foreign 65 37 51 432 301 550

Future Canada 12 104 (46) Foreign 46 71 106 58 175 60 490 476 610

Geographic Components of Income Year ended December 31 (millions of dollars) 2007 2006 2005 Canada 1,228 1,161 1,316 Foreign 582 444 587 Income from continuing operations before income taxes and non-controlling interests 1,810 1,605 1,903 Attachment 1 CAPP 11 Page 123 of 142 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 119

Reconciliation of Income Tax Expense Year ended December 31 (millions of dollars) 2007 2006 2005 Income from continuing operations before income taxes and non-controlling interests1,810 1,605 1,903 Federal and provincial statutory tax rate 32.1% 32.5% 33.6% Expected income tax expense 581 522 639 Income tax differential related to regulated operations69 72 71 (Lower)/higher effective foreign tax rates (39) –2 Tax rate and legislated changes (72) (33) – Income from equity investments and non-controlling interests(34) (27) (29) Non-taxable portion of gains on sale of assets (3) – (68) Large corporations tax – –15 Other(1) (12) (58) (20) Actual income tax expense 490 476 610

(1) Includes income tax benefits of $13 million recorded in 2007 on the resolution of certain income tax matters with taxation authorities and changes in estimates (2006 – $51 million).

Future Income Tax Assets and Liabilities December 31 (millions of dollars) 2007 2006 Deferred amounts 43 65 Other post-employment benefits 57 45 Unrealized losses on derivatives 22 – Other 77 53 199 163 Less: valuation allowance 13 14 Future income tax assets, net of valuation allowance 186 149 Difference in accounting and tax bases of plant, equipment and PPAs 1,073 768 Investments in subsidiaries and partnerships 61 113 Pension benefits 50 59 Unrealized foreign exchange gains on long-term debt 110 39 Unrealized gains on derivatives 27 – Other 44 46 Future income tax liabilities 1,365 1,025 Net future income tax liabilities 1,179 876

Unremitted Earnings of Foreign Investments Income taxes have not been provided on the unremitted earnings of foreign investments that the Company does not intend to repatriate in the foreseeable future. Future income tax liabilities would have increased by approximately $72 million at December 31, 2007 (2006 – $72 million) if there had been a provision for these taxes.

Income Tax Payments Income tax payments of $442 million were made during the year ended December 31, 2007 (2006 – $494 million; 2005 – $531 million). Attachment 1 CAPP 11 Page 124 of 142 120 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 19 NOTES PAYABLE

2007 2006 Weighted Weighted Average Average Interest Rate Interest Rate Outstanding Per Annum at Outstanding Per Annum at December 31 December 31 December 31 December 31 (millions of dollars) (millions of dollars) Canadian dollars 55 5.0% 467 4.3% U.S. dollars (2007 – US$370; 2006 – nil) 366 5.5% 421 467

Notes Payable consists of commercial paper outstanding and drawings on bridge and line-of-credit facilities. Total unsecured revolving and demand credit facilities of $2.9 billion were available at December 31, 2007 to support the Company’s commercial paper program and for general corporate purposes. These credit facilities include the following: • in December 2007, the $1.5 billion committed five-year term syndicated credit facility was increased to $2.0 billion and extended to December 2012. The cost to maintain the credit facility was $2 million in 2007 (2006 – $2 million). • at December 31, 2007, a US$300 million five-year, extendible revolving facility was available, which is part of the US$1.0 billion TransCanada PipeLine USA Ltd. credit facility discussed in Note 9. • the Company also has in place $600 million of demand lines, which support the issuance of letters of credit and provide additional liquidity. The Company had used approximately $334 million of its total lines of credit for letters of credit at December 31, 2007. When drawn, interest on the lines of credit is charged at prime rates of Canadian chartered and U.S. banks, and at other negotiated financial bases.

In February 2007, the Company established a US$2.2-billion unsecured, committed one-year bridge facility and drew down $1.5 billion and US$700 million for the sole purpose of partially financing the acquisitions of ANR and an increased ownership in Great Lakes. The facility had a floating interest rate based on the one-month LIBOR plus 25 basis points. The outstanding balance at December 31, 2007 was US$370 million, which was repaid on January 7, 2008. The undrawn balance of this facility has been cancelled and is no longer available to the Company. Attachment 1 CAPP 11 Page 125 of 142 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 121

NOTE 20 ASSET RETIREMENT OBLIGATIONS

The estimated undiscounted cash flows required to settle the asset retirement obligations with respect to the regulated and non-regulated operations in the Pipelines segment were $65 million at December 31, 2007 (2006 – $39 million), calculated using an inflation rate ranging from two to three per cent per annum. The estimated fair value of these liabilities was $25 million at December 31, 2007 (2006 – $9 million) after discounting the estimated cash flows at rates ranging from 5.4 per cent to 8.0 per cent. At December 31, 2007, the expected timing of payment for settlement of the obligations ranged from one to 27 years.

The estimated undiscounted cash flows required to settle the asset retirement obligations with respect to the Energy segment were $216 million at December 31, 2007 (2006 – $162 million), calculated using an inflation rate ranging from two to three per cent per annum. The estimated fair value of this liability was $63 million at December 31, 2007 (2006 – $36 million) after discounting the estimated cash flows at rates ranging from 5.4 per cent to 6.6 per cent. At December 31, 2007, the expected timing of payment for settlement of the obligations ranges from 11 to 32 years.

Reconciliation of Asset Retirement Obligations(1)

(millions of dollars) Pipelines Energy Total Balance at January 1, 2005 5 31 36 New obligations and revisions in estimated cash flows (1) 1 – Sale of Power LP – (5) (5) Accretion expense –22 Balance at December 31, 2005 4 29 33 New obligations and revisions in estimated cash flows 4 6 10 Accretion expense 112 Balance at December 31, 2006 9 36 45 New obligations and revisions in estimated cash flows 14 25 39 Accretion expense 224 Balance at December 31, 2007 25 63 88

(1) Asset Retirement Obligations are included in Deferred Amounts.

NOTE 21 EMPLOYEE FUTURE BENEFITS

The Company sponsors DB Plans that cover substantially all employees. Benefits provided under the DB Plans are based on years of service and highest average earnings over three consecutive years of employment, and increase annually by a portion of the increase in the Consumer Price Index (CPI). Past service costs are amortized over the expected average remaining service life of employees, which is approximately 11 years.

The Company also provides its employees with DC Plans and post-employment benefits other than pensions, including termination benefits and defined life insurance and medical benefits beyond those provided by government-sponsored plans. Past service costs are amortized over the expected average remaining life expectancy of former employees, which was approximately 14 years at December 31, 2007. Contributions to DC Plans are expensed as incurred.

The Company expensed $8 million in 2007 (2006 – $2 million; 2005 – $2 million) related to retirement savings plans for its U.S. employees.

Total cash payments for employee future benefits, consisting of cash contributed by the Company to the DB Plans and other benefit plans, was $61 million in 2007 (2006 – $104 million; 2005 – $74 million).

The Company measures its accrued benefit obligations and the fair value of plan assets for accounting purposes as at December 31 of each year. The most recent actuarial valuation of the pension plans for funding purposes was as at January 1, 2008, and the next required valuation will be as at January 1, 2009. Attachment 1 CAPP 11 Page 126 of 142 122 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Pension Benefit Plans Other Benefit Plans (millions of dollars) 2007 20062007 2006 Change in Benefit Obligation Benefit obligation – beginning of year1,378 1,282132 148 Current service cost 45 39 2 3 Interest cost 73 65 7 8 Employee contributions 4–3– Benefits paid (65) (64) (7) (7) Actuarial (gain)/loss (22) 53 8 (2) Foreign exchange rate changes (16) ––(6) Plan amendment ––– (18) Acquisition 65 ––19 Benefit obligation – end of year 1,462 1,378 155 132

Change in Plan Assets Plan assets at fair value – beginning of year 1,264 1,096 33 27 Actual return on plan assets 33 134 2 6 Employer contributions 46 95 7 7 Employee contributions 4–3– Benefits paid (65) (64) (7) (7) Foreign exchange rate changes (17) ––(5) Acquisition 93 ––– Plan assets at fair value – end of year 1,358 1,264 30 33 Funded status – plan deficit (104) (114) (125) (99) Unamortized net actuarial loss 299 291 44 39 Unamortized past service costs 28 32 7 (12) Accrued benefit asset/(liability), net of valuation allowance of nil 223 209 (74) (72)

The accrued benefit asset/(liability) in the Company’s balance sheet was as follows:

Pension Benefit Plans Other Benefit Plans (millions of dollars) 2007 2006 2007 2006 Other Assets 223 230 5 5 Deferred Amounts – (21) (79) (77) Total 223 209 (74) (72)

Included in the above benefit obligation and fair value of plan assets at December 31 were the following amounts for plans that are not fully funded:

Pension Benefit Plans Other Benefit Plans (millions of dollars) 2007 2006 2007 2006 Benefit obligation (1,324) (1,359) (155) (102) Plan assets at fair value 1,198 1,243 30 – Funded status – plan deficit (126) (116) (125) (102)

The Company’s expected contributions in 2008 are approximately $60 million for the pension benefit plans and approximately $14 million for the other benefit plans. Attachment 1 CAPP 11 Page 127 of 142 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 123

The following are estimated future benefit payments, which reflect expected future service.

Pension Other (millions of dollars) Benefits Benefits 2008 65 7 2009 68 7 2010 71 8 2011 74 9 2012 78 9 2013 to 2017 447 54

The significant weighted average actuarial assumptions adopted in measuring the Company’s benefit obligations at December 31 were as follow:

Pension Benefit Plans Other Benefit Plans 2007 2006 2007 2006 Discount rate 5.30% 5.00%5.50% 5.20% Rate of compensation increase 3.50% 3.50%

The significant weighted average actuarial assumptions adopted in measuring the Company’s net benefit plan cost for years ended December 31 were as follow:

Pension Benefit Plans Other Benefit Plans 2007 2006 2005 2007 2006 2005 Discount rate 5.05%5.00% 5.75% 5.20% 5.15% 6.00% Expected long-term rate of return on plan assets 6.90%6.90% 6.90% 7.75% 7.75% 7.20% Rate of compensation increase 3.50% 3.50% 3.50%

The overall expected long-term rate of return on plan assets is based on historical and projected rates of return for the portfolio in aggregate and for each asset class in the portfolio. Assumed projected rates of return are selected after analyzing historical experience and estimating future levels and volatility of returns. Asset class benchmark returns, asset mix and anticipated benefit payments from plan assets are also considered in the determination of the overall expected rate of return. The discount rate is based on market interest rates of high quality bonds that match the timing and benefits expected to be paid under each plan.

A nine per cent annual rate of increase in the per-capita cost of covered health care benefits was assumed for 2008 measurement purposes. The rate was assumed to decrease gradually to five per cent in 2016 and remain at this level thereafter. A one percentage point change in assumed health care cost trend rates would have the following effects:

(millions of dollars) Increase Decrease Effect on total of service and interest cost components 1 (1) Effect on post-employment benefit obligation 14 (12) Attachment 1 CAPP 11 Page 128 of 142 124 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Company’s net benefit cost is as follows.

Pension Benefit Plans Other Benefit Plans Year ended December 31 (millions of dollars) 20072006 2005 2007 2006 2005 Current service cost45 39 32 2 3 3 Interest cost73 65 63 7 8 7 Actual return on plan assets(33) (134) (119) (2) (6) (2) Actuarial (gain)/loss(22) 53 149 8 (2) 21 Plan amendment–– – – (18) – Elements of net benefit cost prior to adjustments to recognize the long-term nature of net benefit cost63 23 125 15 (15) 29 Difference between expected and actual return on plan assets(51) 63 54 (1) 4 – Difference between actuarial (gain)/loss recognized and actual actuarial (gain)/loss on accrued benefit obligation47 (27) (131) (7) 4 (20) Difference between amortization of past service costs and actual plan amendments4 4 3 – 19 1 Amortization of transitional obligation related to regulated business – ––2 22 Net benefit cost recognized 6363 51 9 14 12

The Company pension plans’ weighted average asset allocations and weighted average target allocations by asset category were as follow:

December 31 Percentage of Plan Assets Target Allocation Asset Category 2007 2006 2007 Debt securities 42% 40% 35% to 60% Equity securities 58% 60% 40% to 65% 100% 100%

Debt securities included the Company’s debt of $4 million (0.3 per cent of total plan assets) and $4 million (0.3 per cent of total plan assets) at December 31, 2007 and 2006, respectively. Equity securities included the Company’s common shares of $6 million (0.4 per cent of total plan assets) and $6 million (0.5 per cent of total plan assets) at December 31, 2007 and 2006, respectively.

The assets of the pension plans are managed on a going concern basis subject to legislative restrictions. The plans’ investment policies are to maximize returns within an acceptable risk tolerance. Pension assets are invested in a diversified manner with consideration given to the demographics of the plans’ participants.

Employee Future Benefits of Joint Ventures Certain of the Company’s joint ventures sponsor DB Plans as well as post-employment benefits other than pensions, including defined life insurance and medical benefits beyond those provided by government-sponsored plans. The obligations of these plans are non-recourse to TransCanada. The following amounts in this note, including those in the tables, represent TransCanada’s proportionate share with respect to these plans.

Total cash payments for employee future benefits, consisting of cash contributed by the Company’s joint ventures to DB Plans and other benefit plans was $34 million in 2007 (2006 – $25 million; 2005 – $4 million).

The Company’s joint ventures measure the benefit obligations and the fair value of plan assets for accounting purposes as at December 31 of each year. The most recent actuarial valuations of the pension plans for funding purposes were as at January 1, 2008, and the next required valuations will be as at January 1, 2009. Attachment 1 CAPP 11 Page 129 of 142 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 125

Pension Benefit Plans Other Benefit Plans (millions of dollars) 2007 2006 2007 2006 Change in Benefit Obligation Benefit obligation – beginning of year807 679169 81 Current service cost 28 24 10 7 Interest cost 40 37 8 5 Employee contributions 5–5– Benefits paid (23) (15) (2) (2) Actuarial (gain)/loss (34) 77 (16) 72 Foreign exchange rate changes (3) ––– Acquisition (31) ––(2) Plan amendment –(–62) Benefit obligation – end of year 789 807 165 169

Change in Plan Assets Plan assets at fair value – beginning of year 666 585 – – Actual return on plan assets (1) 68 – – Employer contributions 32 23 2 2 Employee contributions 5–5– Benefits paid (23) (15) (2) (2) Foreign exchange rate changes (5) ––– Acquisition (48) ––– Plan assets at fair value – end of year 626 666 – – Funded status – plan deficit (163) (141) (165) (169) Unamortized net actuarial loss 169 174 45 66 Unamortized past service costs –3–6 Accrued benefit asset/(liability), net of valuation allowance of nil 6 33 (117) (97)

The accrued benefit asset/(liability), net of valuation allowance of nil in the Company’s balance sheet was as follows:

Pension Benefit Plans Other Benefit Plans (millions of dollars) 2007 2006 2007 2006 Other assets 6–33 – Deferred amounts – – (117) (97) Total 6 33 (117) (97)

The following amounts were included at December 31 in the above benefit obligation and fair value of plan assets for plans that are not fully funded:

Pension Benefit Plans Other Benefit Plans (millions of dollars) 2007 2006 2007 2006 Benefit obligation (786) (773) (165) (169) Plan assets at fair value 623 609 – – Funded status – plan deficit (163) (164) (165) (169)

The expected contributions of the Company’s joint ventures in 2008 are approximately $31 million for the pension benefit plans and approximately $3 million for the other benefit plans. Attachment 1 CAPP 11 Page 130 of 142 126 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following are estimated future benefit payments, which reflect expected future service. Pension Other (millions of dollars) Benefits Benefits 2008 26 3 2009 30 4 2010 33 5 2011 37 5 2012 41 6 2013 to 2017 263 39

The significant weighted average actuarial assumptions adopted in measuring the benefit obligations of the Company’s joint ventures at December 31 were as follow: Pension Benefit Plans Other Benefit Plans 2007 20062007 2006 Discount rate 5.25% 5.05%5.15% 4.95% Rate of compensation increase 3.50% 3.50%

The significant weighted average actuarial assumptions adopted in measuring the net benefit plan costs of the Company’s joint ventures for years ended December 31 were as follow: Pension Benefit Plans Other Benefit Plans 2007 2006 20052007 2006 2005 Discount rate5.00% 5.25% 6.20%4.90% 5.15% 6.25% Expected long-term rate of return on plan assets7.00% 7.30% 7.40% Rate of compensation increase3.50% 3.50% 3.50%

A one percentage point change in assumed health care cost trend rates would have the following effects:

(millions of dollars) Increase Decrease Effect on total of service and interest cost components 2 (1) Effect on post-employment benefit obligation 23 (20)

The Company’s proportionate share of net benefit cost of joint ventures is as follows.

Pension Benefit Plans Other Benefit Plans Year ended December 31 (millions of dollars) 2007 2006 20052007 2006 2005 Current service cost28 24 410 7 1 Interest cost40 37 78 5 1 Actual return on plan assets1– (68) (18) – – Actuarial (gain)/loss(34) 77 17(16) 72 2 Plan amendment–( – –2) 6 – Elements of net benefit cost prior to adjustments to recognize the long-term nature of net benefit cost35 70 10– 90 4 Difference between expected and actual return on plan assets(44) 26 9– – – Difference between actuarial (gain)/loss recognized and actual actuarial (gain)/loss on accrued benefit obligation44 (70) (16)20 (72) (3) Difference between amortization of past service costs and actual plan amendments–3 – – (6) – Net benefit cost recognized related to joint ventures35 26 323 12 1 Attachment 1 CAPP 11 Page 131 of 142 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 127

The weighted average asset allocations and weighted average target allocation by asset category in the pension plans of the Company’s joint ventures were as follow:

December 31 Percentage of Plan Assets Target Allocation Asset Category 2007 2006 2007 Debt securities 43% 29% 40% Equity securities 57% 71% 60% 100% 100%

Debt securities included the Company’s debt of $1 million (0.2 per cent of total plan assets) and $1 million (0.2 per cent of total plan assets) at December 31, 2007 and 2006, respectively. Equity securities included the Company’s common shares of $3 million (0.5 per cent of total plan assets) and $6 million (1.0 per cent of total plan assets) at December 31, 2007 and 2006, respectively.

The assets of the pension plans are managed on a going concern basis subject to legislative restrictions. The plans’ investment policies are to maximize returns within an acceptable risk tolerance. Pension assets are invested in a diversified manner with consideration given to the demographics of the plans’ participants.

NOTE 22 CHANGES IN OPERATING WORKING CAPITAL

Year ended December 31 (millions of dollars) 2007 2006 2005 Decrease/(increase) in accounts receivable 51 (188) (100) Increase in inventories (6) (108) (50) Decrease/(increase) in other current assets 118 (6) (1) Increase/(decrease) in accounts payable 61 (42) 97 (Decrease)/increase in accrued interest (9) 41 5 215 (303) (49)

NOTE 23 COMMITMENTS, CONTINGENCIES AND GUARANTEES

Commitments

Operating leases Future annual payments, net of sub-lease receipts, under the Company’s operating leases for various premises, services, equipment and a natural gas storage facility are approximately as follows.

Minimum Amounts Recoverable Net Year ended December 31 (millions of dollars) Lease Payments under Sub-Leases Payments 2008 62 (13) 49 2009 58 (12) 46 2010 57 (12) 45 2011 61 (10) 51 2012 61 (6) 55 2013 and thereafter 848 (13) 835 Total 1,147 (66) 1,081

The operating lease agreements for premises, services and equipment expire at various dates through 2021, with an option to renew certain lease agreements for one to ten years. The operating lease agreement for the natural gas storage facility expires in 2030. The lessee has the right to terminate the agreement on anniversary dates five years apart commencing in 2010, and the lessor has the right to terminate the agreement on the same schedule commencing in 2015. Net rental expense on operating leases in 2007 was $34 million (2006 – $25 million; 2005 – $17 million). Attachment 1 CAPP 11 Page 132 of 142 128 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

TransCanada’s commitments under the Alberta PPAs are considered to be operating leases and a portion of these PPAs have been subleased to third parties under similar terms and conditions. Future payments under these PPAs have been excluded from the above table, as these payments are dependent upon plant availability, among other things. The amount of power purchased under the PPAs in 2007 was $440 million (2006 – $499 million; 2005 – $230 million). The generating capacities and expiry dates of the PPAs are as follow: Megawatts Expiry Date Sheerness 756 December 31, 2020 Sundance A 560 December 31, 2017 Sundance B 353 December 31, 2020

TransCanada and its affiliates have long-term natural gas transportation and natural gas purchase arrangements as well as other purchase obligations, all of which are transacted at market prices and in the normal course of business.

Bruce Power Bruce A has signed commitments to third-party suppliers related to refurbishing and restarting Units 1 and 2 and refurbishing Units 3 and 4 to extend their operating life. TransCanada’s share of these signed commitments, which extend over the four-year period ending December 31, 2011, are as follow:

Year ended December 31 (millions of dollars) 2008 360 2009 151 2010 69 2011 14 594

Aboriginal Pipeline Group On June 18, 2003, the Mackenzie Delta gas producers, the APG and TransCanada reached an agreement governing TransCanada’s role in the Mackenzie Gas Pipeline (MGP) project to build a natural gas pipeline from Inuvik, Northwest Territories, to the northern border of Alberta, where it would connect with the Company’s Alberta System. Under the agreement, TransCanada agreed to finance the APG for its one-third share of project pre-development costs. These costs are currently forecasted to be between $150 million and $200 million, depending on the pace of project development. As at December 31, 2007, the Company had advanced $137 million of this total.

TransCanada and the other co-venture companies involved in the MGP continue to pursue approval of the proposed project, focusing on the regulatory process and discussions with the Canadian government on the fiscal framework. Project timing is uncertain and is conditional upon resolution of regulatory and fiscal matters. TransCanada’s ability to recover its investment depends on the successful outcome of the project.

Other Commitments TransCanada is committed to capital expenditures of approximately $1.6 billion related to its share of the construction costs of the Keystone oil pipeline and other pipeline projects.

The Company is committed to capital expenditures of approximately $608 million related to its share of the construction costs of the Halton Hills, Portlands Energy and remaining Cartier Wind projects.

Contingencies The Canadian Alliance of Pipeline Landowners’ Associations (CAPLA) and two individual landowners commenced an action in 2003 against TransCanada and Enbridge Inc. under Ontario’s Class Proceedings Act, 1992 for damages of $500 million. The damages are alleged to have arisen from the creation of a control zone within 30 metres of a pipeline pursuant to Section 112 of the National Energy Board Act. In November 2006, TransCanada and Enbridge Inc. were granted a dismissal of the case but CAPLA appealed the decision. The Ontario Court of Appeal heard the appeal on December 18, 2007, and reserved its decision. The Company continues to believe the claim is without merit and will vigorously defend the action. The Company has made no provision for any potential liability. A liability, if any, would be dealt with through the regulatory process.

TransCanada and its subsidiaries are subject to various legal proceedings and actions arising in the normal course of business. While the final outcome of such legal proceedings and actions cannot be predicted with certainty, it is the opinion of management that the resolution of such proceedings and actions will not have a material impact on the Company’s consolidated financial position or results of operations. Attachment 1 CAPP 11 Page 133 of 142 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 129

Guarantees TransCanada, Cameco Corporation and BPC Generation Infrastructure Trust (BPC) have each severally guaranteed one-third of certain contingent financial obligations of Bruce B related to power sales agreements, operator licenses, a lease agreement and contractor services. The guarantees have terms ranging from one year ending in 2008 to perpetuity.

TransCanada and BPC have each severally guaranteed one-half of certain contingent financial obligations related to an agreement with the Ontario Power Authority to refurbish and restart Bruce A power generation units. The guarantees were part of the reorganization of Bruce Power in 2005 and have terms ending in 2019 to 2036. TransCanada’s share of the potential exposure under these Bruce Power guarantees was estimated at December 31, 2007 to range from $711 million to a maximum of $750 million. The fair value of these guarantees is estimated to be $12 million.

The Company and its partners in certain jointly owned entities have severally and joint and severally guaranteed the performance of these entities related primarily to construction projects, redelivery of natural gas, PPA payments and the payment of liabilities. TransCanada’s share of the potential exposure under these guarantees was estimated at December 31, 2007 to range from $699 million to a maximum of $1,210 million. For certain of these entities, any payments made by TransCanada under these guarantees in excess of its ownership interest are to be reimbursed by its partners. Deferred Amounts includes $7 million for the fair value of these joint and several guarantees.

TransCanada has guaranteed a subsidiary’s equity undertaking that supports the payment, under certain conditions, of principal and interest on US$75 million of the public debt obligations of TransGas de Occidente S.A. (TransGas). The Company has a 46.5 per cent interest in TransGas. Under the terms of a shareholder agreement, TransCanada and another major multinational company, may be required to severally fund more than their proportionate share of debt obligations of TransGas in the event that the minority shareholders fail to contribute. Any payments made by TransCanada under this agreement convert into share capital of TransGas. The Company’s potential exposure is contingent on the impact any change of law would have on the ability of TransGas to service the debt. There has been no change in applicable law since the issuance of debt in 1995 and, thus, no exposure for TransCanada. The debt matures in 2010. The Company has made no provision related to this guarantee.

NOTE 24 DISCONTINUED OPERATIONS

TransCanada had no income from discontinued operations in 2007 (2006 – $28 million; 2005 – nil). The income from discontinued operations in 2006 reflected settlements received from bankruptcy claims related to TransCanada’s Gas Marketing business, which was divested in 2001.

NOTE 25 SUBSEQUENT EVENTS

Certain subsidiaries of Calpine filed for bankruptcy protection in both Canada and the U.S. in 2005. Portland and Gas Transmission Northwest Corporation (GTNC) have reached agreements with Calpine for allowed unsecured claims of US$125 million and US$192.5 million, respectively, in the Calpine bankruptcy. Creditors will receive shares in the re-organized Calpine and these shares will be subject to market price fluctuations as the new Calpine shares begin to trade. In February 2008, Portland and GTNC received initial distributions of 6.1 million shares and 9.4 million shares, respectively, which are expected to result in a significant increase in TransCanada’s net earnings in first-quarter 2008.

Claims by NGTL and Foothills Pipe Lines (South B.C.) Ltd. for $31.6 million and $44.4 million, respectively, were received in cash in January 2008 and will be passed on to shippers on these systems. Attachment 1 CAPP 11 Page 134 of 142 130 SUPPLEMENTARY INFORMATION

SUPPLEMENTARY INFORMATION

SELECTED QUARTERLY AND ANNUAL CONSOLIDATED FINANCIAL DATA

The following sets forth selected quarterly and annual financial data for 2007, 2006 and 2005:

Toronto Stock Exchange (Stock trading symbol TRP) First Second Third Fourth Annual 2007 (dollars) High 41.35 40.29 39.83 40.73 41.35 Low 36.75 35.77 35.43 36.47 35.43 Close 38.35 36.64 36.47 40.54 40.54 Volume (millions of shares) 88.7 78.7 91.4 77.2 336.0

2006 (dollars) High 37.15 34.93 36.49 40.90 40.90 Low 33.60 30.77 31.70 33.87 30.77 Close 33.67 31.85 35.15 40.61 40.61 Volume (millions of shares) 71.9 74.1 61.6 61.0 268.6

2005 (dollars) High 30.84 33.03 37.29 37.90 37.90 Low 28.94 29.23 31.49 34.06 28.94 Close 29.82 32.24 35.50 36.65 36.65 Volume (millions of shares) 64.1 54.1 61.4 58.4 238.0

New York Stock Exchange (Stock trading symbol TRP) 2007 (U.S. dollars) High 35.30 37.21 38.06 43.94 43.94 Low 31.33 32.91 32.92 36.68 31.33 Close 33.28 34.41 36.61 40.93 40.93 Volume (millions of shares) 8.2 5.7 9.0 7.9 30.8

2006 (U.S. dollars) High 32.14 31.36 32.85 35.40 35.40 Low 28.66 27.40 28.23 29.82 27.40 Close 28.93 28.68 31.44 34.95 34.95 Volume (millions of shares) 5.8 9.0 5.6 7.3 27.7

2005 (U.S. dollars) High 25.49 26.85 31.61 32.41 32.41 Low 23.66 23.36 25.84 28.81 23.36 Close 24.70 26.46 30.55 31.48 31.48 Volume (millions of shares) 4.9 3.9 14.7 8.1 31.6 Attachment 1 CAPP 11 Page 135 of 142 SUPPLEMENTARY INFORMATION 131

EIGHT-YEAR FINANCIAL HIGHLIGHTS (millions of dollars except where indicated) 2007 2006 2005 2004 2003 2002 2001 2000 Income Statement Revenues 8,828 7,520 6,124 5,497 5,636 5,225 5,285 4,384 Net income from continuing operations 1,223 1,051 1,209 980 801 747 686 628 Net income/(loss) by segment Pipelines 686 560 679 584 625 639 572 613 Energy 514 452 566 398 217 160 181 95 Corporate 23 39 (36) (2) (41) (52) (67) (80) Continuing operations 1,223 1,051 1,209 980 801 747 686 628 Discontinued operations – 28 – 52 50 – (67) 61 Net income 1,223 1,079 1,209 1,032 851 747 619 689

Cash Flow Statement Funds generated from operations 2,621 2,378 1,951 1,703 1,822 1,843 1,625 1,484 Decrease/(increase) in operating working capital 215 (303) (49) 29 93 92 (487) 437 Net cash provided by operations 2,836 2,075 1,902 1,732 1,915 1,935 1,138 1,921

Capital expenditures and acquisitions (5,874) (2,042) (2,071) (2,046) (965) (851) (1,082) (1,144) Disposition of assets 35 23 671 410 – – 1,170 2,233 Cash dividends paid on common shares (546) (617) (586) (552) (510) (466) (418) (423)

Balance Sheet Assets Plant, property and equipment Pipelines 18,280 17,141 16,528 17,306 16,064 16,158 16,562 16,937 Energy 5,127 4,302 3,483 1,421 1,368 1,340 1,116 776 Corporate 45 44 27 37 50 64 66 111 Total assets Continuing operations 30,330 25,909 24,113 22,415 20,876 20,416 20,255 20,238 Discontinued operations – – – 7 11 139 276 5,007 Total assets 30,330 25,909 24,113 22,422 20,887 20,555 20,531 25,245

Capitalization Long-term debt 12,377 10,887 9,640 9,749 9,516 8,899 9,444 10,008 Junior subordinated notes 975 ––––––– Preferred securities – 536 536 554 598 944 950 1,208 Non-controlling interests 999 755 783 700 713 677 675 646 Common shareholders’ equity 9,785 7,701 7,206 6,565 6,091 5,747 5,426 5,211 Attachment 1 CAPP 11 Page 136 of 142 132 SUPPLEMENTARY INFORMATION

2007 2006 2005 2004 2003 2002 2001 2000 Per Common Share Data (dollars) Net income – Basic Continuing operations$2.31 $2.15 $2.49 $2.02 $1.66 $1.56 $1.44 $1.32 Discontinued operations– 0.06 – 0.11 0.10 – (0.14) 0.13 $2.31 $2.21 $2.49 $2.13 $1.76 $1.56 $1.30 $1.45 Net income – Diluted Continuing operations$2.30 $2.14 $2.47 $2.01 $1.66 $1.55 $1.44 $1.32 Discontinued operations– 0.06 – 0.11 0.10 – (0.14) 0.13 $2.30 $2.20 $2.47 $2.12 $1.76 $1.55 $1.30 $1.45 Dividends declared$1.36 $1.28 $1.22 $1.16 $1.08 $1.00 $0.90 $0.80 Book Value(1)(6) $18.13 $15.75 $14.79 $13.54 $12.61 $11.99 $11.38 $10.97 Market Price Toronto Stock Exchange ($Cdn) High41.35 40.90 37.90 30.35 28.49 23.91 21.13 17.25 Low35.43 30.77 28.94 25.37 20.77 19.05 14.85 9.80 Close40.54 40.61 36.65 29.80 27.88 22.92 19.87 17.20 Volume (millions of shares)336.0 268.6 238.0 280.1 277.9 280.6 288.2 400.7 New York Stock Exchange ($US) High43.94 35.40 32.41 24.91 21.88 15.56 13.41 11.50 Low31.33 27.40 23.36 18.75 14.16 11.89 9.88 6.75 Close40.93 34.95 31.48 24.87 21.51 14.51 12.51 11.50 Volume (millions of shares)30.8 27.7 31.6 33.0 21.2 16.3 16.8 21.2 Shares outstanding (millions) Average for the year529.9 488.0 486.2 484.1 481.5 478.3 475.8 474.6 End of year539.8 489.0 487.2 484.9 483.2 479.5 476.6 474.9 Registered common shareholders(1) 34,204 35,522 30,533 31,837 33,133 34,902 36,350 30,758

Financial Ratios Return on average common shareholders’ equity(2) 14.0% 14.5% 17.6% 16.3% 14.4% 13.4% 11.6% 13.6% Dividend yield(3) 3.4% 3.2% 3.3% 3.9% 3.9% 4.4% 4.5% 4.7% Price/earnings multiple(4)(5) 17.5 18.4 14.7 14.0 15.8 14.7 15.3 11.9 Price/book multiple(4)(6) 2.2 2.6 2.5 2.2 2.2 1.9 1.7 1.6 Debt to debt plus shareholders’ equity(7) 59% 61% 59% 63% 64% 64% 67% 69% Total shareholder return(8) 3% 15% 28% 11% 27% 21% 21% 48% Earnings to fixed charges(9) 2.6 2.5 2.9 2.5 2.3 2.3 2.1 1.9

(1) As at December 31. (2) The ratio of return on average common shareholders’ equity is determined by dividing net income by average common shareholders’ equity (i.e. opening plus closing shareholders’ equity divided by two) for each year. (3) The ratio of dividend yield is determined by dividing dividends declared during the year by price per share as at December 31. (4) Price per share refers to market price per share as reported on the Toronto Stock Exchange as at December 31. (5) The price/earnings multiple is determined by dividing price per share by the basic net income per share. (6) The price/book multiple is determined by dividing price per share by book value per share as calculated by dividing shareholders’ equity by the number of shares outstanding as at December 31. (7) Debt includes total long-term debt plus preferred securities as at December 31 and excludes non-recourse debt of joint ventures. Shareholders’ equity in this ratio is at December 31. (8) Total shareholder return is the sum of the change in price per share plus the dividends received plus the impact of dividend reinvestment in a calendar year, expressed as a percentage of the value of shares at the end of the previous year. (9) The ratio of earnings to fixed charges is determined by dividing the income from continuing operations before financial charges and income taxes, excluding undistributed income from equity investees by the financial charges incurred by the company (net of capitalized interest). Attachment 1 CAPP 11 Page 137 of 142 TRANSCANADA CORPORATION 133

INVESTOR INFORMATION

STOCK EXCHANGES, SECURITIES AND SYMBOLS

TransCanada Corporation Common shares are listed on the Toronto and New York stock exchanges under the symbol: TRP

TransCanada PipeLines Limited (TCPL)* Preferred shares are listed on the Toronto Stock Exchange under the following symbols:

Cumulative redeemable first preferred Series U: TCA.PR.X and Series Y: TCA.PR.Y

* TCPL is a wholly owned subsidiary of TransCanada Corporation.

Annual Meeting The annual meeting of shareholders is scheduled for April 25, 2008 at 10:00 a.m. (Mountain Daylight Time) at the Roundup Centre, Calgary, Alberta.

Dividend Payment Dates Scheduled common share dividend payment dates in 2008 are January 31, April 30, July 31 and October 31.

Dividend Reinvestment and Share Purchase Plan TransCanada’s dividend reinvestment and share purchase plan (Plan) allows common shareholders of TransCanada and preferred shareholders of TCPL to purchase additional common shares by reinvesting their cash dividends without incurring brokerage or administrative fees. Participants in the Plan may also buy additional common shares, up to $10,000 (US$7,000) per quarter. Please contact our Plan agent, Computershare Trust Company of Canada, for more information on the Plan or visit us at www.transcanada.com.

TRANSFER AGENTS, REGISTRARS AND TRUSTEE

TransCanada Corporation Common Shares Computershare Trust Company of Canada (Montreal,´ Toronto, Calgary and Vancouver) and Computershare Trust Company, N.A. (Golden)

TCPL Preferred Shares Computershare Trust Company of Canada (Montreal,´ Toronto, Calgary and Vancouver)

TCPL Debentures

Canadian Series: CIBC Mellon Trust Company (Halifax, Montreal,´ Toronto, Calgary and Vancouver)

11.10% series N 10.50% series O 10.50% series P 10.625% series Q 11.85% series R 11.90% series S 11.80% series U 9.80% series V 9.45% series W

U.S. Series: The Bank of New York (New York) 9.875% and 8.625%

TCPL Canadian Medium-Term Notes CIBC Mellon Trust Company (Halifax, Montreal,´ Toronto, Calgary and Vancouver)

TCPL U.S. Medium-Term Notes and Senior Notes The Bank of New York (New York)

TCPL U.S. Junior Subordinated Notes The Bank of Nova Scotia Trust Company of New York Attachment 1 CAPP 11 Page 138 of 142 134 TRANSCANADA CORPORATION

NOVA Gas Transmission Ltd. (NGTL) Debentures

Canadian Series: CIBC Mellon Trust Company (Halifax, Montreal, Toronto, Calgary and Vancouver)

11.95% series 13 11.70% series 15 11.20% series 18 12.625% series 19 12.20% series 20 12.20% series 21 9.90% series 23

U.S. Series: U.S. Bank Trust National Association (New York) 8.50% and 7.875%

NGTL Canadian Medium-Term Notes CIBC Mellon Trust Company (Halifax, Montreal, Toronto, Calgary and Vancouver)

NGTL U.S. Medium-Term Notes U.S. Bank Trust National Association (New York)

REGULATORY FILINGS

Annual Information Form TransCanada’s 2007 Annual Information Form, as filed with Canadian securities commissions and as filed under Form 40-F with the SEC, is available on our website at www.transcanada.com.

A printed copy may be obtained from:

Corporate Secretary, TransCanada Corporation, P.O. Box 1000, Station M, Calgary, Alberta, Canada T2P 4K5 Attachment 1 CAPP 11 Page 139 of 142 TRANSCANADA CORPORATION 135

SHAREHOLDER ASSISTANCE

If you are a registered shareholder and have questions regarding your account, please contact our transfer agent in writing, by telephone, fax or e-mail at:

Computershare Trust Company of Canada, 100 University Avenue, 9th Floor, North Tower, Toronto, Ontario, Canada M5J 2Y1

Toll-free: 1 (800) 340-5024 Fax: 1 (888) 453-0330 (North America) Telephone: 1 (514) 982-7959 Fax: 1 (416) 263-9394 (outside North America)

E-mail: [email protected]

If you hold your shares in a brokerage account (beneficial shareholder), questions should be directed to your broker on all administrative matters.

If you would like to receive quarterly reports, please contact Computershare or visit our website at www.transcanada.com.

Electronic Proxy Voting and Delivery of Documents TransCanada is pleased to offer registered and beneficial shareholders the ability to receive their documents (annual report, management information circular, notice of meeting and view-only proxy form) and vote online.

In 2008, registered shareholders who opt to receive their documents electronically will have a tree planted on their behalf through eTree. For more information and to sign up online, registered shareholders can visit www.etree.ca/transcanada.

Shareholders who do not have access to e-mail, or who still prefer to receive their proxy materials by mail also have the ability to choose whether to receive TransCanada’s annual report by regular mail. Each year, shareholders are required to renew their option and will receive a notification for doing so. The annual report is available on the TransCanada website at www.transcanada.com/investor/financial.html at the same time that the report is mailed to shareholders.

Electronic delivery and the ability to opt out of receiving the annual report by mail, provides increased convenience to shareholders, benefits to the environment and reduced mailing and printing costs for the company.

TransCanada in the Community TransCanada’s annual Corporate Social Responsibility Report is available at www.transcanada.com. If you would like to receive a copy of this report by mail, please contact:

Communications P.O. Box 1000, Station M, Calgary, Alberta T2P 4K5, 1 (403) 920-2000 or 1 (800) 661-3805.

Visit our website at www.transcanada.com to access TransCanada’s corporate and financial information, including quarterly reports, news releases, real-time conference call webcasts and investor presentations.

Si vous desirez´ vous procurer un exemplaire de ce rapport en fran¸cais, veuillez consulter notre site web ou vous adresser par ecrit´ a` TransCanada Corporation, bureau du secretaire.´ Attachment 1 CAPP 11 Page 140 of 142 136 TRANSCANADA CORPORATION

BOARD OF DIRECTORS (as at December 31, 2007)

S. Barry Jackson* E. Linn Draper(3)(4) John A. MacNaughton(1)(2) Chairman Former Chairman, President and CEO Chairman TransCanada Corporation American Electric Power Co., Inc. (AEP) Business Development Bank of Canada Calgary, Alberta Lampasas, Texas Toronto, Ontario Harold N. Kvisle The Hon. Paule Gauthier, P.C., O.C., O.Q., Q.C.(1)(3) David P. O’Brien(2)(4) President and CEO Senior Partner Chairman TransCanada Corporation Stein Monast L.L.P. EnCana Corporation Calgary, Alberta Quebec,´ Quebec´ Royal Bank of Canada Calgary, Alberta Kevin E. Benson(1) Kerry L. Hawkins(3)(4) Corporate Director Retired President W. Thomas Stephens(3)(4) Wheaton, Illinois Cargill Limited Chairman and Chief Executive Officer Winnipeg, Manitoba Boise Cascade, LLC (1)(2) Derek H. Burney, O.C. Boise, Idaho Senior Strategic Advisor Paul L. Joskow(1)(2) Ogilvy Renault LLP President D. Michael G. Stewart(3) Ottawa, Ontario Alfred P. Sloan Foundation Principal New York, New York Ballinacurra Group (2)(4) Wendy K. Dobson Calgary, Alberta Professor, Rotman School of Management and Director, Institute for International Business University of Toronto Uxbridge, Ontario

* Non-voting member of the Governance Committee and the Human Resources Committee of the Board (1) Member, Audit Committee (2) Member, Governance Committee (3) Member, Health, Safety and Environment Committee (4) Member, Human Resources Committee

CORPORATE GOVERNANCE

Please refer to TransCanada’s Notice of 2008 Annual Meeting of Common Shareholders and Management Proxy Circular for the company’s statement of corporate governance. TransCanada’s Corporate Governance Guidelines, Board charter, Committee charters, Chair and CEO terms of reference and codes of business conduct and ethics are available on our website at www.transcanada.com. Also available on our website is a summary of the significant ways in which TransCanada’s corporate governance practices differ from those required to be followed by U.S. domestic companies under the New York Stock Exchange’s listing standards. Additional information relating to the company is filed with securities regulators in Canada on SEDAR at www.sedar.com and in the United States on EDGAR at www.sec.gov. The documents referred to in this Annual Report may be obtained free of charge by contacting TransCanada’s Corporate Secretary at P.O. Box 1000, Station M, Calgary, Alberta, Canada T2P 4K5, or by telephoning 1 (403) 920-2000. Ethics Help-Line The Audit Committee of the Board of Directors has established an anonymous and confidential toll-free telephone number for employees, contractors and others to call with respect to accounting irregularities and ethical violations. The Ethics Help-Line number is 1 (888) 920-2042. Attachment 1 CAPP 11 executive officers Page 141 of 142

Harold N. Kvisle President and Chief Executive Officer

Russell K. Girling President, Pipelines

Alexander J. Pourbaix President, Energy contact information

Gregory A. Lohnes Visit our website for more information on: Executive Vice-President and Chief Financial Officer • Our Pipelines and Energy businesses • Projects and initiatives • Corporate responsibility

Dennis J. McConaghy • Corporate governance Executive Vice-President, • Investor services Pipeline Strategy and Development www.transcanada.com

TransCanada welcomes questions from shareholders and investors. Please contact: Sean D. McMaster Executive Vice-President, David Moneta, Vice President, Corporate and General Counsel Investor Relations and Communications 1.800.361.6522 (Canada and U.S. Mainland)

Sarah E. Raiss TransCanada Corporation Executive Vice-President, TransCanada Tower Corporate Services 450 First Street SW Calgary, Alberta T2P 5H1 1.403.920.2000 1.800.661.3805 Donald M. Wishart Executive Vice-President, Operations and Engineering

Please recycle Printed in Canada March 2008 Attachment 1 CAPP 11 Page 142 of 142 TransCanada’s vision TransCanada’s

TransCanada will be the leading energy infrastructure company in North America, with a strong focus on pipelines and power generation opportunities located in regions where we enjoy significant competitive advantages. Attachment 2 CAPP 11 Page 1 of 92

2007 annual report

LIVE BETTER WITH BLUE Attachment 2 CAPP 11 Page 2 of 92

LIVE BETTER WITH BLUE

01 02 03 06 07 Highlights Management Report Corporate Management’s committee to partners structure discussion and analysis

41 79 80 82 85 Consolidated Five-year Ten-year Board of Governance financial review review directors information statements summary

87 88 89 Directors Offices Information and officers for partners Attachment 2 CAPP 11 Page 3 of 92 GAZ MÉTRO 2007 Annual Report 1 LIVE BETTER WITH BLUE

HIGHLIGHTS

ADJUSTED ADJUSTED NET RETURN ON ADJUSTED DISTRIBUTION NET INCOME INCOME PER UNIT AVERAGE EQUITY PAID PER UNIT (in millions of dollars) (in dollars) (in %) (in dollars) 154 147 149 1.33 1.25 1.24 16.1 15.2 14.9 1.36 1.33 1.24 200 1.5 20 1.50

150 15 1.0 1.00 100 10 0.5 0.50 50 5

0 0 0 0 05 06 07 05 06 0705 06 07 05 06 07

Years ended September 30 (in millions of dollars, except for unit data which is in dollars) 2007 2006

CONSOLIDATED INCOME AND CASH FLOWS Revenues $1,957.5 $2,003.8 Gross margin $ 623.6 $ 576.3 Income before interest, taxes and amortization $ 418.4 $ 391.6 Net income $ 122.8 $ 147.2 Adjusted net income (1) $ 149.0 $ 147.2 Cash flows related to operating activities (before working capital) $ 347.7 $ 297.3 Capital expenditures $ 124.8 $ 153.9 Variations in deferred charges and credits $ 108.9 $ 37.0 Net income per unit (basic and diluted) $ 1.02 $ 1.25 Adjusted net income per unit (basic and diluted) (1) $ 1.24 $ 1.25 Distributions paid per unit $ 1.24 $ 1.33 Return on average equity 12.4% 15.2% Return on adjusted average equity (1) 14.9% 15.2% Weighted average number of outstanding units (in millions) 120.4 117.5 Interest coverage on consolidated long-term debt over a period of 12 months (times) 2.53 2.75

CONSOLIDATED NORMALIZED VOLUMES (2) (in millions of cubic metres) MARKETS Industrial 3,882 3,116 Commercial 1,879 1,873 Residential 733 728 Total 6,494 5,717

OTHER INFORMATION Authorized rate of return on deemed common equity (Quebec distribution activity) 9.57% 9.33% Credit ratings Long-term bonds (3) (S&P/DBRS) A/A A/A Commercial paper (3) (S&P/DBRS) A-1(low)/R-1 (low) A-1(low)/R-1 (low) Stability of distributions (S&P/DBRS) SR-2/STA-2 (average) SR-2/STA-2 (average) Market prices on Toronto Stock Exchange (in dollars): High $ 18.50 $ 22.50 Low $ 15.30 $ 15.56 Close $ 16.02 $ 17.60 Public ownership in Partnership (non-controlling Partners) 29.0% 27.2%

CONSOLIDATED BALANCE SHEETS Total assets $3,142.5 $2,783.2 Total debt $1,684.8 $1,423.4 Partners’ equity $ 921.9 $ 924.6 Partners’ equity per unit $ 7.65 $ 7.87

(1) Adjusted to exclude special $26.2 million future income tax expense. (2) Estimated volumes at normal temperatures in Quebec only. (3) Through its General Partner, Gaz Métro inc. Attachment 2 CAPP 11 Page 4 of 92 2 2007 Annual Report GAZ MÉTRO LIVE BETTER WITH BLUE

MANAGEMENT COMMITTEE

Sophie Brochu PRESIDENT AND CHIEF EXECUTIVE OFFICER Sophie in 1984 as a Research Analyst with DATECH (technological devel- Brochu was appointed President and Chief Executive Officer in opment and assistance group). Later, she was Senior Advisor, February 2007. Since joining Gaz Métro in 1997, she has then Department Head, Marketing Communications, before being successively occupied the positions of Vice President, Business promoted to Director, Marketing and Energy Efficiency. Ms. Lehoux Development, Vice President, Customer and Gas Supply, and Exe- sits on the boards of the Agence de l’efficacité énergétique du cutive Vice President, Quebec Distribution. Madame Brochu Québec and the Natural Gas Technologies Center. She is also a began her career in 1987 as a Financial Analyst at SOQUIP, where director of many other organizations, including the Conseil des she later served as Assistant to the President from 1990 to 1992, normes de la publicité du Québec and the Association québécoise then as Vice President, Development, from 1992 to 1997. She is du gaz naturel and she is a member of several professional as- a director of the Montreal Museum of Archeology and History sociations. Ms. Lehoux is often invited to be a guest speaker and (Pointe-à-Callière) and the Rehabilitation Institute of Montreal. to serve on juries in the fields of marketing and communications. She also contributes to Muscular Dystrophy Canada and to École Hochelaga, a primary school in the Hochelaga-Maisonneuve Marc Lemieux VICE PRESIDENT, LEGAL AFFAIRS AND CORPORATE district of Montreal that Gaz Métro sponsors. SECRETARY Marc Lemieux joined Gaz Métro in February 2007 as Vice President, Legal Affairs and Corporate Secretary. A law- Patrick Cabana VICE PRESIDENT, CORPORATE CONTROL Patrick Cabana yer by profession, Mr. Lemieux began his career as a Law Clerk at was appointed Vice President, Corporate Control, in July 2006. the Supreme Court of Canada, in 1988 and 1989. He was then in Since joining Gaz Métro in March 2002, he has successively oc- private practice from 1990 to 2006 with a major national law firm, cupied the positions of Department Head, Corporate Control, principally in the fields of financing and banking services, where and Corporate Controller. Mr. Cabana acquired his experience he acquired sound experience appearing before tribunals and in accounting and auditing first with Raymond, Chabot, Martin, negotiating commercial transactions. He is a lecturer in the Paré from 1990 to 1997, then as a member of the management Faculty of Law at McGill University, where he has taught banking team at The Hockey Company (Sport Maska inc.), a public com- law since 2002. Mr. Lemieux is a director of the Ensemble pany where he served as director of Corporate Accounting from instrumental Appassionata and the Dynamo Théâtre. 1997 until 2002, when he joined Gaz Métro. Serge Régnier VICE PRESIDENT, EMPLOYEES AND CULTURE Serge Pierre Despars EXECUTIVE VICE PRESIDENT AND CHIEF FINANCIAL Régnier was appointed Vice President, Employees and Culture, OFFICER From November 2005 to February 2007, he was Executive in February 2007, after serving as Vice President, Human Vice President, Finance and Business Development. Since joining Resources, Quality and Internal Communications from 2001. He Gaz Métro in 1991, he has in turn served as Senior Advisor, Regu- joined Gaz Métro in 1998 as Director, Human Resources and latory Affairs, Director, Accounting and Budgets, Vice President, Advisory Services, to which role was added responsibility for Administration and Regulatory Affairs, and Vice President, corporate security and total compensation and benefits. In Finance and Corporate Affairs Mr. Despars began his career in his professional career, Mr. Régnier has held human resources 1985 as an auditor at KPMG before being named Controller and management positions at Culinar, Dry Products Group (1984), at Dir ec tor of A ccounting at Q uebecor P r inting in 19 8 9. Mr. Despars Agropur, Fine Cheese Division, where he was Director, Personnel sits on the board of directors of ExelTech Aerospace and chairs and Industrial Relations, then at Natrel inc., where he was the Audit Committee. He also chairs the board of directors of Director of Labour Relations and later Director of Personnel and the Lina-Cyr Foundation, which supports the Maison des greffés Industrial Relations. Mr. Régnier is Co-Chair of the board of du Québec. directors of the Association québécoise des allergies alimen- taires. He also serves as a governor of the Mouvement québécois Martin Imbleau VICE PRESIDENT, BUSINESS DEVELOPMENT, GAS de la qualité. SUPPLY AND TRANSPORTATION Martin Imbleau was appointed Vice President, Business Development, Gas Supply and Transportation Jean Simard VICE PRESIDENT, SUSTAINABLE DEVELOPMENT AND in February 2007. As Vice President of Rabaska inc., he has been PUBLIC & GOVERNMENTAL AFFAIRS Jean Simard was appointed Vice responsible for this liquefied natural gas terminal project from President, Sustainable Development and Public & Governmental the outset. Since joining Gaz Métro in 1996, Mr. Imbleau has Affairs in February 2007, after serving as Vice President, Public & successively occupied the positions of legal counsel, Business Governmental Affairs from May 2004. He acquired his expertise Development Advisor, Director, and later Vice President, Business in the environment and energy fields inside and outside Québec, in Development and Regulatory Affairs outside Québec Mr. Imbleau particular as Vice President, Energy and Environment at HKDP. He began his professional career as a participant in many projects has more than 20 years of experience in public affairs, principally and missions related to international human rights law. He has in crisis management, government relations, environmental com- published several works and articles on human rights. munications and strategic counsel. Mr. Simard chairs the board of directors of the Nature Conservancy of Canada (Québec Chapter) Guylaine Lehoux VICE PRESIDENT, MARKETING AND RATE DESIGN and is a director of CIRANO. He is a member of the Canadian Gas Guylaine Lehoux was appointed Vice President, Marketing and Rate Association Standing Committee on Public Affairs and sits on the Design in November 2005. She began her career with Gaz Métro board of the Energy Council of Canada. Attachment 2 CAPP 11 Page 5 of 92 GAZ MÉTRO 2007 Annual Report 3 LIVE BETTER WITH BLUE

REPORT TO PARTNERS

Blue today and beyond is the theme marking Gaz Métro’s order to remove nearly 260,000 tonnes of CO2 equivalents 50th anniversary. from the planet each year.

Blue today is the choice of more than 7,000 new customers In October 2007, the Carbon Disclosure Project recognized who, in 2007, joined the customer ranks Gaz Métro is Gaz Métro as one of Canada’s leaders in reporting on the privileged to serve. Blue today is also the challenge we challenges posed by climate change. Introduced in Europe face every day in striking a balance between the three four years ago by large investment funds whose ranks pillars–economic, environmental and social–of sustainable continue to grow, the Carbon Disclosure Project asks development to ensure we grow. large public companies around the world to volunteer their carbon fingerprint, i.e. to disclose their greenhouse And beyond is to go further. gas reduction objectives, the steps taken to achieve those objectives and the results achieved, in a comprehensive CITIZENS TOMORROW rigorous report. Those investors seek to identify and grade Society increasingly expects more of businesses. Any the risks and the opportunities flowing from a capitalist business that wants to grow now has to earn the public’s system that is conscious of the environment. Gaz Métro confidence in addition to maintaining a balance between was recognized in this regard along with 15 other Canadian investor, customer and employee satisfaction. The public enterprises that stood out amongst the 200 solicited. now wants businesses to develop sensibly and intelligently in terms of environmental considerations. Leadership and coherent actions guide our march to corpo- rate citizenship. Quebecers’ environmental awakening provided a stimulus for becoming a true citizen, instead of just a simple consumer. As DISPLACE HEAVY FUEL OIL TO REDUCE GREENHOUSE citizens acquire a better understanding of the environmental, GAS EMISSIONS AND IMPROVE AIR QUALITY economic and societal implications, they think harder about Over the years, Quebec has become Canada’s largest each action they take. As a result, these new citizens raise industrial heavy fuel oil consumer. Aware that this energy the bar in terms of the demands they place on businesses. profile is having a significant impact on our collective environmental performance, on October 1, the government And beyond is to see Gaz Métro climb to the top of the chart of Quebec announced a major plan for reducing the use of of Quebec’s corporate citizens. this fuel derivative and, consequently, Quebec’s greenhouse gas emissions. ENVIRONMENTAL PERFORMANCE: RECOGNITION OF EXCELLENCE The objective of this government program is to provide A long time ago, Gaz Métro understood that the greenhouse financial support for projects that will enable industry gases challenge was an opportunity, not an obstacle. to reduce its heavy fuel oil consumption, in particular by purchasing more efficient equipment and converting to Four years before the Kyoto Protocol was signed, i.e. well other energies, such as natural gas, that are less harmful before it became popular, Gaz Métro had already decided to to the environment. reduce its own emissions voluntarily. To date, our voluntary plan has generated reductions of 28% from our 1990 levels Gaz Métro intends to meet this challenge. We plan to get through state-of-the-art practices and sustained efforts back a large number of our industrial customers that by our employees, without whom it would not have been switched to heavy fuel oil in 2001 following the increase in possible to achieve our ambitious objectives. natural gas prices. This represents a potential of 15 billion cubic feet of gas, i.e. the equivalent of 7.5% of Quebec’s Those accomplishments came on top of the energy total gas consumption last year, and is a huge business conservation measures implemented by customers opportunity for Gaz Métro. This conversion would also who took advantage of the programs offered under the reduce total green house gas emissions in Quebec by Partnership’s Global Energy Efficiency Program, as well 400,000 tons a year, i.e. 4% of the government of Quebec’s as the Energy Efficiency Fund’s programs that are financed total objective in the wake of the Kyoto Protocol. The from productivity gains generated by Gaz Métro over the utilization of natural gas instead of fuel oil would also years. More than 34,000 residential customers and 2,700 significantly reduce atmospheric pollution that causes business customers put their noses to the grindstone in urban smog and acid rain. Attachment 2 CAPP 11 Page 6 of 92 4 REPORT TO PARTNERS 2007 Annual Report GAZ MÉTRO LIVE BETTER WITH BLUE

Quality of life in Quebec will be determined by a healthier On October 24, 2007 the Cabinet of the Quebec government environment and more pragmatic environmental choices adopted the decree authorizing the Rabaska project to that require energy efficiency and clean energies, which proceed. At a time when global negotiating activities include natural gas. are intensifying, as liquefied natural gas is sought by an ever-growing number of countries and consumers, the ENERGY EFFICIENCY AND REGULATION: government authorization arrives in time to allow Rabaska AN INNOVATIVE UNIQUE MODEL to hold legitimate discussions with international suppliers. Since 2001, Gaz Métro has been carrying on its gas distribution activities in Quebec under a regulatory Acquisition of Green Mountain Power Corporation framework that is unique in Canada. Introduced under On April 12, 2007, Gaz Métro, through its wholly-owned the aegis of the Régie de l’énergie, this innovative model subsidiary, Northern New England Energy Corporation compensates Gaz Métro for its productivity gains as well (NNEEC), acquired Green Mountain Power Corporation as, like any regulated enterprise, its investors based on (GMP), the second largest electricity distributor in the State their capital invested. of Vermont in the United States. As Gaz Métro has already been involved in the gas distribution business in Vermont for Over the years, this modus operandi has successfully with- 20 years, this acquisition enables it to pursue the targeted stood the test of time and changing contexts. On April 27, prudent diversification strategy for its energy activities. 2007, the Régie de l’énergie accepted a proposal by Gaz Métro and its customers’ representatives to revise the This acquisition creates wealth for Gaz Métro’s unitholders performance incentive mechanism a third time to ensure and allows us to join forces with an enterprise that adheres to it is consistent with the Partnership’s business reality. The the sustainable development values that we hold dear. GMP is Partnership is now compensated for customers’ energy recognized for its philosophy of excellence in environmental conservation attributable to its energy efficiency efforts. matters and for its involvement as a corporate citizen. It is a Gaz Métro’s performance incentive mechanism is therefore leader in its industry and is strongly committed to providing perfectly in line with sustainable development. its customers with maximum electricity produced from clean renewable energies. It recently joined the Chicago On October 15, 2007, the Régie de l’énergie rendered its Climate Exchange, which trades greenhouse gas emission decision on the 2008 rate application. The Régie’s decision credits. In terms of social responsibility, in 2005, GMP won modified certain parameters of the present formula for fixing the Large Business Leader of the Year award given out by the rate of return allowed on deemed Partners’ equity. As Vermont Businesses for Social Responsibility. These are a a result, the return is 9.05% for the 2008 fiscal year, which few examples of GMP’s extensive environmental, economic is 14 basis points higher than what the present formula and social commitments. would have produced and 32 basis points higher than the rate allowed last year. This increases the Partnership’s Seigneurie de Beaupré Wind Power Project pre-tax income in the order of $3.2 million. Another important milestone of our strategy was reached on September 18, 2007, when Gaz Métro, Boralex Inc. and STRUCTURAL DEVELOPMENT INITIATIVES FOR GAZ MÉTRO the Séminaire de Québec submitted three joint bids for Rabaska projects totalling 375.5 megawatts (MW) in response to Last year, the Rabaska LNG terminal project, which will Hydro-Québec Distribution’s call for tenders for 2,000 MW be used to import liquefied natural gas, reached a major of wind power energy. milestone with the publication of a favourable joint report by the Bureau d’audiences publiques sur l’environnement du Québec and the Canadian Environmental Assessment Agency. Attachment 2 CAPP 11 Page 7 of 92 GAZ MÉTRO 2007 Annual Report REPORT TO PARTNERS 5 LIVE BETTER WITH BLUE

The projects have extraordinary wind power potential Finally, more than 90% of all of Gaz Métro’s employees on the proposed Seigneurie de Beaupré lands. Their participated in the Partnership’s employee motivation remoteness from populated areas minimizes the visual survey. The motivation index continues to rise significantly. and noise impacts. The environmental impact is virtually Clearly, Gaz Métro is evolving rapidly, and its employees are non-existent. Enercon, a wind turbine manufacturer that is keeping pace and adhering to the Partnership’s fundamental recognized worldwide for its know-how, intends to install a values. To be able to count on dedicated women and men wind turbine parts plant in Quebec. It is also involved in the who endeavour each day to earn the confidence of customers projects proposed by Gaz Métro, Boralex and the Séminaire and investors is a remarkable asset for management. We de Québec. Hydro-Québec Distribution plans to announce extend our sincere thanks to them. the bids retained in the spring of 2008. 2007 RESULTS OVERVIEW Diversification of gas supplies and a targeted diversification Gaz Métro continued to grow, adding 7,183 new customers strategy for our energy investments are cornerstones of during the 2007 fiscal year, including 5,060 residential Gaz Métro’s future direction. These actions will create value customers. Natural gas captured 19% of the new residential for our customers, our investors, our employees and for construction market in the Greater Montreal Area. Quebec society as a whole. Net income, before the non-recurring adjustment of ECONOMIC AND FINANCIAL ENVIRONMENT $26.2 million to take account of the legislative change During the past few months, two major events had an affecting income trusts and limited partnerships, is impact on the price of Gaz Métro’s units. $149.0 million, an increase of $1.8 million over the previous year. The adjustment represents a non-monetary Federal Bill C-52, adopted on June 22, 2007, amended the expense to record a future income tax liability arising Income Tax Act for the proposals in the Tax Fairness Plan from amendments to the Income Tax Act, adopted on June announced by Canada’s Minister of Finance in October 2006. 22, 2007, implementing the proposals in the Minister of The Bill taxes income trusts and limited partnerships on Finance’s Tax Fairness Plan tabled on October 31, 2006. the same basis as corporations. As of October 1st, 2010, distributions received by a Partner will be reduced by the Income per unit, before the $26.2 million non-recurring income tax paid directly by the Partnership and treated adjustment, is $1.24 in 2007, which is $0.01 less than the as dividends. 2006 fiscal year. The quarterly distribution to Partners of $0.31 per unit was maintained throughout the fiscal year The price of Gaz Métro’s units have also been affected by the and we expect it will remain at that level in each quarter of turbulence on the Canadian and U.S. markets since mid- the 2008 fiscal year. August 2007 on account of the crisis of confidence triggered by the asset-backed commercial paper problem. Few financial experts are willing to predict the length and magnitude of this turbulence that is affecting all listed securities.

EMPLOYEES AND CULTURE; COLLABORATION THAT ENABLES US TO GO EVEN FURTHER During the past few months, two new collective agreements were signed with Gaz Métro’s unions. These multi-year agreements contribute to the stability of our work environ- ment and remind us we are privileged to have union executives who have both the interests of their members SOPHIE BROCHU ROBERT TESSIER President and Chief Executive Officer Chairman of the Board and the development of the Partnership at heart. November 21, 2007 Attachment 2 CAPP 11 Page 8 of 92 6 2007 Annual Report GAZ MÉTRO LIVE BETTER WITH BLUE

CORPORATE STRUCTURE

CAISSE DE FONDS DE SNC-LAVALIN INC. BC INVESTMENT RÉGIME DES RENTES RÉGIME DE DÉPÔT ET SOLIDARITÉ FTQ MANAGEMENT DU MOUVEMENT RETRAITE PLACEMENT CORPORATION1 DESJARDINS DE L’UNIVERSITÉ DU QUÉBEC DU QUÉBEC 51.11% 16.66% 11.11% 11.11% 8.33% 1.67%

CAPITAL TRENCAP L.P. ENBRIDGE INC.2 GAZDEFRANCE2 D’AMÉRIQUE CDPQ INC. (GENERAL PARTNER) 0.01% 50.38% 32.06% 17.56%

NOVERCO INC.

100%

GAZ MÉTRO INC. (GENERAL PARTNER)

71.01%

GAZ MÉTRO PUBLIC LIMITED (LIMITED PARTNERS) PARTNERSHIP

28.99%

ENERGY NATURAL GAS NATURAL GAS ENERGY SERVICES DISTRIBUTION TRANSPORTATION STORAGE & OTHER ACTIVITIES

1 BC Investment Management Corporation: two trusts in the group hold 9.44% (bcIMC (PPSAF) Investment Trust No.1, and 1.67% (bcIMC (WCBAF-PPSAF) Investment Trust No.1), respectively. 2 Indirect participations’. Attachment 2 CAPP 11 Page 9 of 92 GAZ MÉTRO 2007 Annual Report 7 LIVE BETTER WITH BLUE

MANAGEMENT’S DISCUSSION AND ANALYSIS

MANAGEMENT’S DISCUSSION AND ANALYSIS (MD&A) SHOULD BE READ IN CONJUNCTION WITH THE AUDITED CONSOLIDATED FINANCIAL STATEMENTS OF GAZ MÉTRO LIMITED PARTNERSHIP (GAZ MÉTRO OR THE PARTNERSHIP) INCLUDED IN THE 2007 ANNUAL REPORT. THOSE CONSOLIDATED FINANCIAL STATEMENTS HAVE BEEN PREPARED IN ACCORDANCE WITH CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (GAAP). ALL AMOUNTS IN THE FINANCIAL STATEMENTS AND THIS REPORT ARE IN MILLIONS OF CANADIAN DOLLARS, UNLESS OTHERWISE INDICATED.

FORWARD-LOOKING STATEMENTS To enable investors to better understand the Partnership’s outlook for the future and make more informed decisions, the matters discussed in this report may contain forward-looking information about Gaz Métro’s objectives, strategies, financial condition, operating results and activities. Such information expresses, as of the date hereof, the estimates, forecasts, projections, expectations or opinions of the Partnership concerning future events or results. Actual results may differ materially from the results anticipated herein and, consequently, we cannot guarantee that any forward-looking statement will materialize. Forward-looking information does not take account of the impact transactions or non-recurring matters, announced or arising after the statements have been made, might have on the Partnership’s activities.

Significant risks and uncertainties that could cause actual results and future events to differ materially from current expectations are described herein, in particular under “Risks”. Gaz Métro therefore cautions readers not to place too much reliance on forward-looking information.

Gaz Métro does not propose nor does it commit to update forward-looking information, even if new information becomes available as a result of future events, or for any other reason, unless required to do so by applicable securities laws.

ADJUSTED INDICATORS NOT STANDARDIZED IN ACCORDANCE WITH GAAP In the view of Gaz Métro’s management, certain “adjusted” indicators, such as adjusted net income, adjusted net income per unit and others provide readers with information they consider useful for analyzing its financial results. However, they are not standardized by GAAP and should not be considered in isolation or as substitutes for other performance measures that are in accordance with GAAP. The results obtained might not be comparable with similar indicators used by other issuers and should therefore only be considered as complementary information.

DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROLS OVER FINANCIAL REPORTING The Partnership has designed disclosure controls and procedures to ensure the information reported in this MD&A, the consolidated financial statements and the related annual documents is properly recorded, processed, summarized and reported to the Audit Committee and the Board of Directors. Based on its evaluation, management is satisfied that, at the end of the fiscal year ended September 30, 2007, they adequately ensure the financial information required to be disclosed is complete and reliable.

Furthermore, the Partnership has examined the internal controls that were designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. Based on this evaluation, management has concluded that the design of its internal controls over financial reporting is effective.

During the 2007 fiscal year, the Partnership did not make any modifications to the internal controls over financial reporting that had or could reasonably be expected to have a significant impact on those internal controls.

STANDARDIZED DISTRIBUTABLE CASH This MD&A complies in all material respects with the recommendations in the Canadian Institute of Chartered Accountants’(CICA) Standardized Distributable Cash in Income Trusts and Other Flow-through Entities–Guidance on Preparation of and Disclosure publication. Attachment 2 CAPP 11 Page 10 of 92 8 MANAGEMENT’S DISCUSSION AND ANALYSIS 2007 Annual Report GAZ MÉTRO LIVE BETTER WITH BLUE

Main topics 08 A) Overview of Partnership and Strategy 36 G) Recent Accounting Changes 12 B) Performance Summary 36 H) Significant Accounting Estimates 15 C) Segmented Results 37 I) Additional Information 23 D) Consolidated Financial Situation 38 J) Quarterly Results 24 E) Liquidity and Capital Structure 39 K) Outlook 34 F) Risks

A) OVERVIEW OF PARTNERSHIP AND STRATEGY Gaz Métro’s mission is to supply energy services and solutions to its target clientele and aims to be recognized as: a leader in the energy field; a performing, upright, socially responsible, environmentally caring enterprise; a reliable and responsible supplier whose customers appreciate the quality of the service and the expertise provided; and a leading financial and operating partner that generates ideas and achieves them.

Gaz Métro counts on a solid partnering arrangement with its employees and business partners to achieve this mission, the ultimate objective of which is to fulfil the expectations of customers and investors respectively.

The Partnership continues to believe that the success of any business of tomorrow, as is the case today, will depend on its ability to satisfy its three pillars–its investors, its customers and its employees.

It also believes it will have to earn the confidence of the general public, which means sensible intelligent development in terms of environmental considerations.

Gaz Métro’s financial objective continues to be to provide its Partners with a stable predictable return accompanied by growth in value over the years. While achieving this objective depends largely on the performance of the distribution of natural gas in Quebec, it also depends on its ability to develop its other activities profitably while maintaining a relatively low overall risk profile.

From a business perspective, the Partnership intends to continue to grow its clientele and provide its customers with high- quality energy services at the lowest possible cost, through policies and programs aimed at motivating its employees and business partners.

ENERGY DISTRIBUTION SECTOR The Energy Distribution Sector, formerly the “Natural Gas Distribution Sector”, now includes all of Gaz Métro’s energy distribution activities. Since April 12, 2007, the activities of Green Mountain Power Corporation (GMP) are included in this new Sector, which already included the natural gas distribution activities in Quebec and Vermont.

This change is in line with Gaz Métro’s broader mission to become a leader in the energy field. Additional information about the entities in this Sector will be provided to facilitate the reader’s analysis and understanding of their activities.

Natural gas distribution These activities include their share of significant challenges as a result of rising volatile energy prices, including natural gas prices, over the past few years, which has contributed to an increase in energy conservation initiatives. Such initiatives, while desired and encouraged by the Partnership, have reduced average per customer energy consumption for space and water heating. Attachment 2 CAPP 11 Page 11 of 92 GAZ MÉTRO 2007 Annual Report MANAGEMENT’S DISCUSSION AND ANALYSIS 9 LIVE BETTER WITH BLUE

However, the Partnership remains confident that the medium and long-term outlook is positive, particularly in Quebec, where acceptance of «the right energy in the right place» should generate larger market shares for natural gas in the future.

Distribution of Natural Gas in Quebec (Gaz Métro-QDA) Gaz Métro’s core business is Gaz Métro-QDA, which delivers approximately 97% of the natural gas consumed in Quebec. This activity is regulated by the Régie de l’énergie (Régie), which fixes the annual distribution rates and the rate of return allowed on equity. It also oversees the operating and development activities of the natural gas distribution systems.

Vermont Gas Systems, Inc. (VGS) VGS, a wholly-owned subsidiary of Northern New England Energy Corporation (NNEEC), is the sole gas distributor in Vermont in the United States. It is regulated by the Vermont Public Service Board (VPSB), which approved, effective October 1, 2006, a new regulatory framework for it. The new framework includes an adjustment mechanism for the price of gas sold to customers that reflects its acquisition cost and a mechanism for sharing productivity gains.

Electricity distribution activities GMP On April 12, 2007, Gaz Métro, through its wholly-owned subsidiary, NNEEC, acquired GMP, the second largest electricity distributor in Vermont. GMP’s territory covers approximately one-quarter of the State’s population. Although it produces part of the electricity it distributes, most is purchased from various producers. Its supply portfolio includes various generation sources, the main ones being hydroelectricity and nuclear power.

GMP is regulated by the VPSB. The rates for its activities are established on a cost-of-service method that enables it to recover the costs it expects to incur to serve its customers and earn a reasonable return on the shareholder’s equity. GMP benefits from a price adjustment mechanism for electricity sold to its customers.

GMP’s management team at the time of the acquisition will continue to manage the business from Vermont for Gaz Métro.

NATURAL GAS TRANSPORTATION SECTOR Gaz Métro owns significant financial interests in two natural gas transportation enterprises, TQM Pipeline and Company, Limited Partnership (TQM) and Portland Natural Gas Transmission System (PNGTS).

At constant rates of return, erosion of the rate bases, on which the authorized returns are calculated, inevitably reduces earnings. It is therefore especially important for these enterprises to remain on the lookout for potential additional investments in their system.

TQM The Partnership owns a 50% interest in TQM, which operates a gas pipeline in Quebec that connects upstream with that of TransCanada PipeLines (TCPL) and downstream with PNGTS and Gaz Métro. In Canada, transportation activities are regulated by the National Energy Board (NEB).

In terms of the outlook for the future, TQM could benefit from growth opportunities that will arise from the possible arrival of liquefied natural gas (LNG) from overseas. Attachment 2 CAPP 11 Page 12 of 92 10 MANAGEMENT’S DISCUSSION AND ANALYSIS 2007 Annual Report GAZ MÉTRO LIVE BETTER WITH BLUE

TQM has also signed a major preliminary natural gas transportation contract with TCPL to connect the Gros-Cacouna terminal, which is being developed by TCPL and Pétro-Canada, to its existing facilities. The contract stipulates that TQM has to make every reasonable effort to increase the capacity of its gas pipeline in order to transport 14 million cubic metres of natural gas per day from Gros-Cacouna to Quebec City for a period of 20 years starting on December 1, 2009 or as soon as possible thereafter.

However, on September 26, 2007, Énergie Cacouna, the developer, announced the project would be delayed two years, until 2012. Nevertheless, TQM still intends to submit an application to the NEB within the next few months to get approval to construct the aforementioned transportation facilities between Quebec City and Gros-Cacouna. The capital cost of the required expansion of the gas pipeline is estimated to be approximately $700 million. The preliminary transportation contract with TCPL provides TQM with all the necessary backstop protection.

PNGTS Gaz Métro also owns a 38.3% indirect interest in the PNGTS pipeline, which originates at the Quebec border and extends to the suburbs of Boston. In the United States, transportation activities are regulated by the Federal Energy Regulatory Commission (FERC).

The loss, over the last few years, of two large customers with whom PNGTS had concluded long-term contracts, coupled with the difficulties in concluding the same type of contract with other customers to replace the lost volumes, hurt the results expected from this investment interest. PNGTS’ main challenge continues therefore to be active and vigilant in seizing sales opportunities that will enable it to maximize the profitability of the capacity of its transportation system.

Meetings with existing customers to establish the bases for PNGTS’ next rate application, which should normally be effective in April 2008, got underway in October 2007.

NATURAL GAS STORAGE SECTOR Gaz Métro owns an interest in the Intragaz group whose activity is mainly underground natural gas storage. This activity is a natural fit with Gaz Métro’s mission because the storage of natural gas is part of its supply chain. While the respective ownership interests of Gaz Métro and Gaz de France, the other partner of the Intragaz group, vary for each of the entities in the group, overall they are roughly the same.

Intragaz operates the only two underground storage facilities in Gaz Métro’s service area in Quebec. Gaz Métro is also its only customer. Its rates are approved by the Régie on the basis of avoided costs. Intragaz’s expertise in identifying and developing new storage sites, in particular in complex geological formations, is an asset considering the expected growth in demand for storage capacity.

ENERGY SERVICES AND OTHER SECTOR The Partnership sells goods and services, through subsidiaries, joint ventures and companies subject to significant influence, in the energy business and in water, wastewater and fibre optic networks.

Energy services The energy-related activities are concentrated in the maintenance and repair of residential, commercial and industrial equipment, the heating and cooling of large buildings and the leasing of residential water heaters.

Water sector Gaz Métro’s objective is to provide diagnostic (Aqua Data) and rehabilitation (Aqua-Rehab) services for municipal water and wastewater systems under multi-year contracts. These activities will likely accelerate in the future since integrated water distribution and wastewater collection system master plans have become mandatory in Quebec for obtaining government grants. Attachment 2 CAPP 11 Page 13 of 92 GAZ MÉTRO 2007 Annual Report MANAGEMENT’S DISCUSSION AND ANALYSIS 11 LIVE BETTER WITH BLUE

Fibre optic sector Gaz Métro owns a 49.8% interest in MTO Telecom Inc. (MTO), which operates a high bandwidth fibre optic network that mainly serves Montreal, Toronto and Ottawa. Growth of MTO’s commercial clientele, combined with tight control over operating costs, should improve the company’s earnings over the next few years. In the Partnership’s view, the convergence of telecommunications and computer technology points to a promising future for this sector.

DEVELOPMENT PROJECTS AND POTENTIAL ACQUISITIONS LNG Terminal On October 24, 2007, the government of Quebec issued a decree approving proceeding with part of Rabaska Limited Partnership’s proposal for the construction of an LNG terminal at Lévis, on the conditions therein. The project, in which the Partnership’s partners are Enbridge Inc. and Gaz de France, therefore received the government’s endorsement of the favourable recommendation issued on July 5, 2007 by the Commission d’examen formed by the Bureau d’audiences publiques sur l’environnement (BAPE) and the Canadian Environmental Assessment Agency.

In its announcement, the government said its decision was in line with the logic of a government capable of combining the “economy” and the “environment”. It basically retained the main conclusions of the Commission d’examen, which, in management’s view, are that the project would: be safe and justified; have real economic benefits while minimizing the environmental impacts; and be a good fit with Quebec’s energy policy.

The federal government is pursuing its process for getting approval of the project.

Gaz Métro is pleased with this news and is continuing to work with its partners to secure a long-term gas supply contract for the project. When gas supplies would have been secured, construction, which would take a little more than three years, could start.

Wind power project On September 18, 2007, Gaz Métro and Boralex Inc. submitted three joint bids in response to Hydro-Québec Distribution’s call for tenders for 2,000 megawatts of wind power energy to be produced by three wind farms having a total capacity of approximately 375 megawatts to be developed on the Seigneurie de Beaupré lands, in collaboration with the Séminaire de Québec. Gaz Métro and its partner firmly believe they have an exceptional site for such a project in Quebec.

Hydro-Québec Distribution should announce the projects retained in the spring of 2008.

Potential acquisitions The Partnership is keeping its eyes open for opportunities that might arise but that are also in keeping with its approach of only considering projects that are in line with its mission, that would create value and that have a similar risk profile to Gaz Métro’s.

PERFORMANCE INDICATORS Gaz Métro’s core business is the distribution of natural gas in Quebec with its 1,287 employees and all the related challenges. In the pursuit of excellence with its suppliers and partners, Gaz Métro developed indicators that enable it to measure the organization’s performance in relation to the objectives set at the beginning of the fiscal year. Attachment 2 CAPP 11 Page 14 of 92 12 MANAGEMENT’S DISCUSSION AND ANALYSIS 2007 Annual Report GAZ MÉTRO LIVE BETTER WITH BLUE

Those indicators include: results; customer satisfaction; new customers; variances from operating budgets; employee motivation; occupational health and safety; and environmental management (ISO 14001).

B) PERFORMANCE SUMMARY HIGHLIGHTS

For fiscal years ended September 30 2007 2006 2005

Consolidated revenues 1,957.5 2,003.8 1,808.2 Gross margin 623.6 576.3 563.2 Net income 122.8 147.2 154.4 Adjusted net income (a) 149.0 147.2 154.4 Net income per unit (in $) 1.02 1.25 1.33 Adjusted net income per unit (in $) (a) 1.24 1.25 1.33 Distributions paid per unit (in $) 1.24 1.33 1.36 Return on average equity 12.4% 15.2% 16.1% Return on adjusted average equity (a) 14.9% 15.2% 16.1% Debt/total capitalization ratio 64.6% 60.6% 59.9% Debt/adjusted total capitalization ratio (a) 64.0% 60.6% 59.9% a) Adjusted to exclude recording of special future income tax expense and related liability explained under “NET INCOME AND NET INCOME PER UNIT”on page 13.

CONSOLIDATED REVENUES AND GROSS MARGIN Consolidated revenues for the fiscal year ended September 30, 2007 are down $46.3 million, or 2.3%, to $1,957.5 million from $2,003.8 million the previous year. This can be explained mainly by a reduction in the average selling price of natural gas, partially offset by the consolidation of GMP’s sales since April 12, 2007. In Quebec, and in Vermont since October 1, 2006, natural gas purchased by the Partnership and its Vermont subsidiary is billed to customers at cost, which minimizes the impact on gross margin and net income.

CONSOLIDATED NORMALIZED NATURAL GAS VOLUMES (in millions of cubic metres) 5,618 5,717 6,494 8,000

6,000

4,000

2,000

0 05 06 07 Attachment 2 CAPP 11 Page 15 of 92 GAZ MÉTRO 2007 Annual Report MANAGEMENT’S DISCUSSION AND ANALYSIS 13 LIVE BETTER WITH BLUE

Deliveries (normalized for temperatures in Quebec) during the 2007 fiscal year are 6,494 million cubic metres of natural gas, an increase of 13.6% over the 2006 fiscal year. The increase can be explained primarily by the maturation of a large new electric cogeneration customer and higher consumption in the metallurgy industry.

Consolidated gross margin of $623.6 million is up 8.2%, or $47.3 million, compared to the previous year, mainly due to the share of GMP’s gross margin included in Gaz Métro’s results since April 12, 2007 and the increase in the gross margin generated by Gaz Métro-QDA.

NET INCOME AND NET INCOME PER UNIT

NET INCOME GAZ MÉTRO-QDA GAZ MÉTRO-QDA PER UNIT AUTHORIZED RATE OF RETURN REALIZED RATE OF RETURN ON (in dollar) ON DEEMED COMMON EQUITY DEEMED COMMON EQUITY (in %) (in %) 1.39 1.40 1.33 1.25 1.02 9.33 9.57 9.66 9.91 10.34 10.96 11.64 10.82 11.47 10.52 2.00 12.00 12.00

1.50 9.00 9.00

1.00 6.00 6.00

0.50 3.00 3.00

0 0 0

03 04 05 06 07(a) 03 04 05 06 07 03 04 05 06 07 a) $1.24 per unit before recording of special future income tax expense described below.

Special future income tax expense On October 1, 2007, the CICA issued new recommendations requiring flow-through entities, like Gaz Métro, to recognize the impacts of amendments to the Income Tax Act when the legislative provisions are substantively enacted. On June 22, 2007, the House of Commons passed Bill C-52 amending the Income Tax Act to implement the proposals concerning the taxation of income trusts and limited partnerships (flow-through entities), starting October 1, 2010 in the case of the Partnership, in the Minister of Finance’s Tax Fairness Plan tabled on October 31, 2006. The application of those recommendations as at September 30, 2007 resulted in the recording of a future income tax liability of $26.2 million related to a joint venture (Intragaz) whose activities do not meet the definition of an enterprise subject to rate regulation in the CICA Handbook (Handbook).

Net income Net income in 2007 is $122.8 million, a decrease of $24.4 million from the previous year. If it had not been for the unfavourable $26.2 million non-monetary impact of the future income tax liability recorded, as explained above, income would have been up $1.8 million to $149.0 million.

The main reasons for the $1.8 million increase in adjusted net income are: the $6.4 million decrease in amounts recorded for the LNG terminal project; the $3.8 million increase in income from Gaz Métro-QDA; the recognition of one-third ($2.0 million) of last year’s gain on the sale of 50% of the units of Climatisation et Chauffage Urbains de Montréal (CCUM) to Dalkia; the consolidation of GMP’s results since April 12, 2007; and the recording of a $1.4 million tax benefit relating to prior years in MTO; Attachment 2 CAPP 11 Page 16 of 92 14 MANAGEMENT’S DISCUSSION AND ANALYSIS 2007 Annual Report GAZ MÉTRO LIVE BETTER WITH BLUE

partially offset by: the $4.9 million increase in interest expense related to the financing of the investments in subsidiaries and other investment interests; the decrease in TQM’s earnings following, among other things, a reduction in the rate of return allowed on the equity invested in this activity; the decrease in PNGTS’ income following the loss of two large customers that no longer contribute to its results; and the collection of a larger amount in the fourth quarter of 2006 than in 2007 in connection with the bankruptcy of a former customer of PNGTS ($3.5 million in 2006 versus $0.5 million in 2007).

Net income per unit Net income per unit is $1.02, which is $0.23 lower than in 2006. If it had not been for the unfavourable $26.2 million non- monetary impact of the future income tax liability recorded, net income per unit would have been $1.24.

The net income of Gaz Métro-QDA, which is strongly affected by the rate of return allowed by the Régie on its deemed common equity, represents more than 80% of Gaz Métro’s adjusted net income in 2007.

RETURN ON AVERAGE EQUITY The return on the adjusted average equity during the 2007 fiscal year is 14.9%, which is relatively similar to the 15.2% in 2006.

Virtually all of the income earned by the Partnership, except income earned by the U.S. subsidiaries, is presently taxed directly in the hands of the Partners.

For the fiscal year ended September 30, 2007, taxable income is 9.9% less than distributions for federal purposes and 9.6% less for provincial purposes, compared to 13.6% for federal purposes and 13.2% for provincial purposes last year.

LIQUIDITY

CONSOLIDATED DISTRIBUTIONS TOTAL DEBT PAID PER UNIT (in millions of dollars) (in dollars) 1.34 1.36 1.36 1.33 1.24 1,304 1,231 1,404 1,423 1,685 2,000 1.50

1,500 1.00 1,000 0.50 500

0 0 03 04 05 06 07 03 04 05 06 07

Debt/total capitalization ratio The debt/total capitalization ratio is 64.6% as at September 30, 2007, compared to 60.6% at the same date last year. If it had not been for the unfavourable $26.2 million non-monetary impact related to the recording of a future income tax liability, as explained above, the ratio would have been 64.0%, an increase of 3.4% over the previous year. This increase can be explained primarily by the acquisition of GMP, which has been financed entirely with debt to date.

The Partnership expects to issue units during the 2008 fiscal year in order to bring its capital structure back in line with previous years. Attachment 2 CAPP 11 Page 17 of 92 GAZ MÉTRO 2007 Annual Report MANAGEMENT’S DISCUSSION AND ANALYSIS 15 LIVE BETTER WITH BLUE

Distributions paid per unit In keeping with its policy of distributing virtually all of its income, Gaz Métro distributed 99.6% of its adjusted net income in 2007, compared to 106.2% in 2006.

The Partnership expects to maintain its distributions at $0.31 per unit in each quarter of the 2008 fiscal year.

OTHER HIGHLIGHTS In 2007, 7,183 (7,978 in 2006) new customers chose Gaz Métro. The penetration of natural gas in the new residential construction sector is relatively stable at 19% (20% in 2006) of new housing in the Greater Montreal Area.

The satisfaction rate of new customers in Quebec is up slightly over the previous year to 92% compared to 90% last year in spite of the pressure on the organization year after year to connect a large number of new customers to the system.

C) SEGMENTED RESULTS NET INCOME – HIGHLIGHTS

For fiscal years ended September 30 2007 2006 Variations

ENERGY DISTRIBUTION Gaz Métro–QDA 120.9 117.1 3.8 VGS and GMP 9.6 7.9 1.7 Financing costs of investments in Sector (1) (5.0) (1.9) (3.1) 125.5 123.1 2.4 TRANSPORTATION OF NATURAL GAS TQM and PNGTS 18.9 26.3 (7.4) Financing costs of investments in Sector (1) (4.9) (4.0) (0.9) 14.0 22.3 (8.3) STORAGE OF NATURAL GAS Intragaz 6.1 8.1 (2.0) Financing costs of investments in Sector (1) (2.9) (2.5) (0.4) Future income taxes (2) (26.2) – (26.2) (23.0) 5.6 (28.6) ENERGY SERVICES Energy, water and optics 10.6 5.8 4.8 Financing costs of investments in Sector (1) (2.6) (2.1) (0.5) 8.0 3.7 4.3 NON-ALLOCATED ITEMS Rabaska project (0.2) (6.6) 6.4 Other (1.5) (0.9) (0.6) (1.7) (7.5) 5.8 CONSOLIDATED NET INCOME 122.8 147.2 (24.4)

(1) Represents financial expense incurred by parent company to finance investments in the subsidiaries, joint ventures and companies subject to significant influence for each Sector. (2) Represents future income tax liability the Partnership will have to pay during the periods after October 1, 2010 and related to Intragaz, which does not qualify as a rate-regulated enterprise. Attachment 2 CAPP 11 Page 18 of 92 16 MANAGEMENT’S DISCUSSION AND ANALYSIS 2007 Annual Report GAZ MÉTRO LIVE BETTER WITH BLUE

ENERGY DISTRIBUTION SECTOR Revenues As the Sector’s most significant revenue item is the cost of the energy supply (natural gas and electricity) bought and sold in connection with the energy distribution activities, and this item has very little impact on Gaz Métro’s results, analyzing revenues does not provide a clear picture of the evolution of the Sector’s activities and will not be commented on.

Gaz Métro – QDA

NORMALIZED NATURAL AVERAGE RATE BASE GAS VOLUMES EVOLUTION (in millions of cubic metres) (in millions of dollars) 645 645 3,040 3,799 1,805 1,806 5,490 6,250 1,567 1,666 1,673 1,734 1,765 8,000 2,000

6,000 1,500

4,000 1,000

2,000 500 06 0 07 0

Industrial Commercial Residential Total volume 03 04 05 06 07

Deliveries and Temperature Normalization The Partnership benefits from a revenue normalization mechanism (for temperatures) for its Quebec natural gas distribution revenues based on normal temperatures. Gaz Métro-QDA normalizes (based on temperatures) the volumes of gas delivered and then reflects that adjustment in revenues through its rate stabilization accounts. Gaz Métro-QDA’s normalized natural gas volumes are up 13.8% to 6,250 million cubic metres during the 2007 fiscal year. This can be explained by higher volumes in the industrial market following the start-up of production (September 2006) by a large electric cogeneration customer, TCE in Bécancour, and by increased consumption in the metallurgy sector.

Volumes were maintained in the heating market as a result of the increase in the number of customers and the favourable impact of the wind factor on overall energy consumption, which offset the impact of customers’ energy conservation initiatives. Winds, which infiltrate buildings and cause heat loss, thereby increasing energy consumption, were stronger during the 2007 fiscal year than the previous year, which helped deliveries in the space heating market. In connection with the framework of the 2008 rate application, the Régie authorized the inclusion of wind in the revenue normalization mechanism effective October 1, 2007.

Average temperatures during the 2007 fiscal year were warmer than normal but colder than during the 2006 fiscal year, thereby increasing energy consumption over the previous year in the space heating market. A $21.2 million variation was recorded in the rate stabilization account related to temperatures in 2007, compared to $28.9 million in 2006.

A $0.6 million variation was recorded in the rate stabilization accounts related to inventory differences in 2007, compared to $8.2 million in 2006.

The regulatory mechanism provides that the Partnership will recover those amounts from customers over five years by adjusting its annual rates starting in the second subsequent year, in the case of temperatures, and over one year in the case of inventory differences. Attachment 2 CAPP 11 Page 19 of 92 GAZ MÉTRO 2007 Annual Report MANAGEMENT’S DISCUSSION AND ANALYSIS 17 LIVE BETTER WITH BLUE

Gross Margin and Incentive Return Gross margin for Gaz Métro-QDA is up $21.8 million, or 4.8%, to $473.3 million in 2007 from $451.5 million the previous year, mainly on account of higher distribution rates in the residential and commercial markets and increased deliveries in the industrial market.

The incentive return was $11.5 million in 2007, compared to $6.8 million the previous year, reflecting: anticipated productivity gains of $8.3 million included in the authorized rate of return in 2007, compared to $3.6 million in 2006; and the distributor’s $3.2 million share in the excess returns earned during the 2006 and 2007 fiscal years.

The reasons for the excess return of $13.0 million in 2007 are: an increase in the gross margin generated by, among other things, a reduction in compressor fuel costs and load- balancing costs due to the optimization of tools; and a decrease in the authorized operating income as a result of the reduction in the average rate base below the amount used to establish the rates in the 2007 rate application.

Operations and Maintenance Expenses Gaz Métro-QDA’s operations and maintenance expenses were up $6.7 million, or 4.3%, to $162.0 million.

This increase is attributable to, among other things, the increases in: salaries and employee benefits; and expenses related to the energy conservation programs.

Amortization Expense Amortization expense of $121.4 million related to property, plant and equipment and deferred charges is up $10.2 million in 2007, compared to 2006.

This can be explained primarily by: the fact there was no share of overearnings to return to customers in 2007, compared to $7.1 million in 2006; and large investments in the natural gas distribution system in Quebec over the past few years.

Interest and Financial Expenses Interest expense is up $1.1 million, mainly on account of the increase in the average cost of Gaz Métro’s debt over the previous year.

Net Income and Achieved Rate of Return Net income for Gaz Métro-QDA is $120.9 million, which is up $3.8 million from $117.1 million the previous year.

The achieved rate of return on Partners’ equity was 9.91% in 2007, compared to 9.66% last year. This is mainly attributable to an increase in the incentive return of 0.47% allowed under the performance incentive mechanism, partially offset by a 0.22% decrease in the base rate of return allowed in 2007 by the Régie, following the reduction in the projected return on long-term bonds. Attachment 2 CAPP 11 Page 20 of 92 18 MANAGEMENT’S DISCUSSION AND ANALYSIS 2007 Annual Report GAZ MÉTRO LIVE BETTER WITH BLUE

Regulatory Matters Performance incentive mechanism–Gaz Métro’s efforts to get its performance incentive mechanism revised were rewarded with the Régie’s approval, on April 27, 2007 of the changes proposed by Gaz Métro in collaboration with the interested parties. This is good news for the Partnership because it brings the regulatory framework more in line with its market reality.

Authorized base rate of return on equity–On May 15, 2007, the Partnership also made a proposal to the Régie, in connection with its 2008 rate application, to modify the present formula for determining the rate of return allowed on Partners’ deemed common equity to better reflect its business risk as well as the market’s expectations.

In its October 15, 2007 decision, the Régie did not retain the Partnership’s proposal, claiming that a more detailed analysis of the issues related to the use of a new model for determining a reasonable rate of return was required. It therefore maintained the present formula and increased the risk premium by 14 basis points, thereby reflecting, in its view, Gaz Métro’s increased business risk since the formula was introduced in 1999.

Outlook A large customer, TransCanada Energy Ltd. (TCE) in Bécancour, might stop consuming natural gas distributed by Gaz Métro as of January 1, 2008 for an indefinite period of time.

Following this news and in connection with the approval required by TCE and Hydro-Québec from the Régie, Gaz Métro made representations in order to minimize the impact thereof on its customers and Partners.

VGS AND GMP Deliveries VGS and GMP do not benefit from a temperature normalization mechanism and their deliveries therefore vary based on actual temperatures. The earnings of VGS, whose customers are more highly concentrated in the space heating market, are therefore affected to a greater extent by temperature fluctuations.

VGS–Deliveries during the 2007 fiscal year are up 7.5% over 2006 to 244 million cubic metres.

VGS – NATURAL GAS VOLUMES DELIVERED (in millions of cubic metres) 227 244 300

200

100

0 06 07 Attachment 2 CAPP 11 Page 21 of 92 GAZ MÉTRO 2007 Annual Report MANAGEMENT’S DISCUSSION AND ANALYSIS 19 LIVE BETTER WITH BLUE

However, as a result of warmer than normal average temperatures during the 2007 fiscal year, residential consumption, which generates the highest gross margin, was lower than what had been anticipated and used for establishing the rates for the 2007 fiscal year. This reduced earnings and could not be offset completely by higher volumes in the industrial market.

GMP–Electricity volumes distributed by GMP since April 12, 2007 are 1,009 gigawatthours.

The volumes distributed can be broken down as follows amongst the different markets of GMP: 251 gigawatthours in the residential market; 333 gigawatthours in the small commercial and industrial market; 320 gigawatthours in the large commercial and industrial market; and 105 gigawatthours to other customers, composed mainly of other electric distributors in respect of whom the gross margins, which have been historically very low, are fully redistributed to customers.

Gross Margin The gross margin realized by VGS and GMP is up $26.5 million in 2007 to $60.2 million. The increase is entirely due to the inclusion of the gross margin generated by GMP since April 12, 2007, which was partially offset by a decrease in VGS’ gross margin on non-recurring revenues in 2006.

VGS was able to take advantage of a favourable market context during the 2006 fiscal year to make a profit on certain transactions related to the price of natural gas. As the VPSB has authorized the use of a new price adjustment mechanism for the price of gas sold to customers that reflects its purchase cost, effective October 1, 2006. VGS is no longer at risk for the cost of the commodity. However, it can no longer take advantage of a favourable market context or excess capacities to increase its bottom line.

Operations and Maintenance Expenses Operations and maintenance expenses are up $13.0 million to $25.8 million, mainly from the inclusion of GMP’s expenses since April 12, 2007.

Amortization Expense Apart from the impact of GMP, the $7.8 million increase in amortization expense to $13.4 million in 2007 is due to amounts expended on the sustained expansion of VGS’gas system over the past few years.

Interest and Financial Expenses Interest and financial expenses are $14.4 million, an increase of $9.4 million over the previous year.

The increase can be explained by: the inclusion, since April 12, 2007, of GMP’s interest expense and of interest for financing its acquisition, including the interest on the new debt issued by NNEEC on June 19, 2007; and the increase in expenses related to Gaz Métro’s financing of investments in the Sector, following the acquisition of GMP, and the increase in the average financing rate.

Income from Companies Subject to Significant Influence The income share from companies subject to significant influence in 2007 comes entirely from GMP’s interests in electricity transmission and other service companies in Vermont.

Income Taxes Income tax expenses for VGS and GMP are $4.4 million in 2007 and 2006 for pre-tax income of $9.0 million and $10.4 million respectively. The effective tax rate of these companies therefore increased from 42.2% in 2006 to 48.5% in 2007. Attachment 2 CAPP 11 Page 22 of 92 20 MANAGEMENT’S DISCUSSION AND ANALYSIS 2007 Annual Report GAZ MÉTRO LIVE BETTER WITH BLUE

Net Income and Rate Base Net income from VGS and GMP is down $1.4 million to $4.6 million, mainly on account of: non-recurring revenues in VGS in 2006; higher financing costs due to, among other things, the investment in GMP; and lower deliveries than forecasted, as explained before; partially offset by: income of $4.4 million earned by GMP since last April 12.

The average rate base of VGS increased from US$77 million in 2006 to US$86 million in 2007 as a result of investments made in its activities. GMP’s rate base has been US$222 million on average since it was acquired.

NATURAL GAS TRANSPORTATION SECTOR Revenues and Gross Margin Natural gas transportation revenues, which also correspond to the Sector’s gross margin, are down $3.1 million, or 7.0%, to $40.8 million. This can be explained by, among other things, the reduction in TQM’s toll following, among other things, the decrease in its allowed rate of return on equity.

Operations and Maintenance Expenses Operations and maintenance expenses are $7.9 million compared to $9.2 million in 2006. The decrease is mainly due to an incident on TQM’s system that led to substantial preventive maintenance costs in the 2006 fiscal year.

Amortization Expense Amortization expense related to property, plant and equipment and deferred charges is up slightly by $0.4 million in 2007, compared to 2006, to $11.9 million.

Interest and Financial Expenses Interest and financial expenses are $14.9 million, compared to $13.5 million in 2006. The increase is due to the increase in the average financing rate for investments in the Sector.

Income from Companies Subject to Significant Influence The income from companies subject to significant influence is Gaz Métro’s share of the pre-tax income of PNGTS, which amounts to $13.0 million for the 2007 fiscal year, compared to $21.9 million last year.

The main reasons for the decrease are: the loss of two large customers that no longer contributed to the partnership’s results, as explained above; and the collection of a larger amount in the fourth quarter of 2006 than in 2007 in connection with the settlement of the bankruptcy of a former customer of PNGTS, as explained above.

Income Taxes Income taxes are down $4.1 million to $5.2 million because of the decrease in PNGTS’ pre-tax income. PNGTS’ effective tax rate decreased from 42.5% in 2006 to 40.2% in 2007. Attachment 2 CAPP 11 Page 23 of 92 GAZ MÉTRO 2007 Annual Report MANAGEMENT’S DISCUSSION AND ANALYSIS 21 LIVE BETTER WITH BLUE

Net Income Net income for the Sector is $14.0 million for the 2007 fiscal year, compared to $22.3 million in 2006, a decrease of $8.3 million, for the reasons explained above.

NATURAL GAS STORAGE SECTOR Revenues and Gross Margin Revenues are $13.0 million in 2007, compared to $15.8 million in 2006.

The decrease is due to: the recording in the first quarter of the previous fiscal year of a non-recurring revenue of $0.8 million from the sale of an asset to a third party; the favourable settlement (impact of $1.0 million) of a dispute in the fourth quarter of the previous year; and the unfavourable impact of approximately $0.9 million of the Régie’s decision with respect to the Pointe-du-Lac storage site rate on third and fourth quarter results for the fiscal year ended September 30, 2007.

The annualized impact on next year’s results of the decrease in the Pointe-du-Lac storage site rate is estimated to be approximately $0.8 million.

Operations and Maintenance Expenses and Amortization Expense Operations and maintenance expenses and amortization expense are down $1.0 million to $5.2 million for the 2007 fiscal year. The decrease is due to, among other things, the reduction in development expenditures during the year.

Interest and Financial Expenses Interest and financial expenses are up $0.6 million to $4.6 million. The increase is attributable to the increase in the average financing rate of investments in the Sector.

Income Taxes Income taxes for the year of $26.3 million include future income taxes of $26.2 million that should normally be paid by the parent company related to Intragaz’ activities during the years after the new flow-through entity tax rules come into force, i.e. October 1, 2010 in the case of Gaz Métro. Intragaz is the only company in the group that has a future income tax liability not recorded in the books and that does not qualify as an enterprise subject to rate regulation within the meaning of the Handbook.

Net Income Net income is down $28.6 million, compared to last year, for the reasons explained above.

Regulatory Matters Pointe-du-Lac rate–On June 6, 2007, the Régie rendered its decision concerning the rate applicable to the Pointe-du-Lac natural gas storage site owned by the Intragaz group. The decision reduced the rate, retroactive to May 1, 2006, which had a negative impact on the earnings of the Storage Sector, as explained above.

ENERGY SERVICES AND OTHER SECTOR Revenues and Gross Margin Revenues of $89.9 million are up 19.1%, or $14.4 million. Gross margin is up $4.1 million to $36.5 million. Attachment 2 CAPP 11 Page 24 of 92 22 MANAGEMENT’S DISCUSSION AND ANALYSIS 2007 Annual Report GAZ MÉTRO LIVE BETTER WITH BLUE

These increases are due to: greater activity by certain companies in the Sector; and the recording, during the second quarter of 2007, of one-third ($2.0 million) of last year’s deferred gain on the sale of 50% of the units of CCUM to Dalkia following the collection of one-third of the selling price by the company that had disposed of the units; partially offset by: the decrease in the share of CCUM’s revenues following that sale on February 14, 2006.

Operations and Maintenance Expenses and Amortization Expense Operations and maintenance expenses and amortization expense are up $0.3 million to $24.5 million. The increase in expenses caused by the increased activity was offset by the reduction in Gaz Métro’s share of CCUM’s expenses since February 14, 2006.

Interest and Financial Expenses Interest and financial expenses are up $0.6 million to $4.8 million in 2007. The increase is attributable to the increase in the average financing rate of investments in the Sector.

Net Income Net income for the Sector is up $4.3 million in 2007 to $8.0 million, mainly on account of: the recognition of one-third ($2.0 million) of the gain on the sale of the units of CCUM to Dalkia; the recording in the second quarter of 2007, of a $1.4 million tax benefit relating to prior years in MTO; and greater activity by certain companies in the Sector.

NON-ALLOCATED EXPENSES The net expenses not allocated to a particular sector are composed mainly of development expenditures incurred by Gaz Métro. They amount to $1.7 million in 2007, compared to $7.5 million the previous year.

Rabaska Project Development expenditures included in results and related to the Rabaska LNG terminal amount to $0.2 million this year, compared to $6.6 million the previous year, i.e. a decrease of $6.4 million.

Gaz Métro maintains its approach of not capitalizing any cost related to the project as long as it does not have reasonable assurance the project will generate benefits in the future. In the Partnership’s view, this assurance could be obtained, among other things, when Rabaska has secured its LNG supplies.

In the Partnership’s view, its results should no longer be significantly affected by additional development expenditures related to this project.

Other Expenses Other expenses, net, are $1.5 million in 2007, compared to $0.9 million in 2006. They include: development expenditures related to various smaller projects; and corporate expenses not allocated to the Sectors; net of: certain corporate revenues not allocated to the Sectors. Attachment 2 CAPP 11 Page 25 of 92 GAZ MÉTRO 2007 Annual Report MANAGEMENT’S DISCUSSION AND ANALYSIS 23 LIVE BETTER WITH BLUE

D) CONSOLIDATED FINANCIAL SITUATION The following table describes the main changes in the consolidated balance sheets between September 30, 2006 and September 30, 2007.

Increase Balance Sheet items (Decrease) Explanations Trade and other receivables 23.6 Increase related to acquisition of GMP on April 12, 2007 Inventories (36.8) Decrease mainly attributable to reduction in natural gas inventory on books of Gaz Métro-QDA Propery, plant and equipment 224.8 Increase related to acquisition of GMP on April 12, 2007 Investments and other 20.4 Increase attributable to investments worth $37.8 million owned through GMP, partially offset by decrease in value of investment in PNGTS as a result of strength of Canadian dollar in relation to US dollar Deferred charges 68.5 Increase related to acquisition of GMP on April 12, 2007, the increase in deferred charges related to the rate stabilization account (for temperatures) (Gaz Métro-QDA) and the increase in deferred charges (losses that did not materialize) related to financial instruments (Gaz Métro-QDA’s cost of gas) Goodwill 70.2 Increase almost entirely related to goodwill recorded when GMP was acquired on April 12, 2007 Accounts payable and accrued liabilities 32.1 Increase related to acquisition of GMP on April 12, 2007 Long-term debt, including current portion 257.8 Increase related to debt owned directly by GMP and acquired on April 12, 2007 ($111.6 million), debt issued to finance acquisition of GMP ($189.0 million) and other increase partially offset by repayment of $75.0 million bond matured in the first quarter of the 2007 fiscal year Deferred credits (14.0) Decrease attributable to reduction in credits related to the cost of natural gas supply to be returned to customers of Gaz Métro-QDA partially offset by customers’ share of Gaz Métro-QDA’s excess return for 2007 fiscal year Future income taxes 56.8 Increase related to acquisition of GMP on April 12, 2007 and recording of future income taxes related to Intragaz ($26.2 million) Net liability related to derivative 36.1 Increase related to acquisition of GMP on April 12, 2007 financial instruments and loss in net value of financial instruments related to the Gaz Métro- QDA activity during the fiscal year Capital 24.5 Increase attributable to unit issues by Gaz Métro on October 10, 2006 partially offset by unfavorable non-cash impact of recording of future income taxes related to Intragaz Other consolidated comprehensive (27.2) Decrease attributable to reduction in value of U.S. investments income, cumulative following appreciation of Canadian dollar in relation to US dollar Attachment 2 CAPP 11 Page 26 of 92 24 MANAGEMENT’S DISCUSSION AND ANALYSIS 2007 Annual Report GAZ MÉTRO LIVE BETTER WITH BLUE

ASSET-BACKED COMMERCIAL PAPER As of September 30, 2007, Gaz Métro owned asset-backed commercial paper totalling $1.5 million on a consolidated basis. A provision for a 15% deterioration in the capital value was recorded in the Partnership’s books during the fourth quarter of the 2007 fiscal year.

E) LIQUIDITY AND CAPITAL STRUCTURE This section discusses the financial position, cash flows and liquidity of the Partnership.

2007 HIGHLIGHTS Distributions financed entirely from operating activities in 2007; Investments of $247.2 million in development activities; Debt/total capitalization ratio of 64.6%; Credit ratings maintained through its General Partner, Gaz Métro inc.; and Stability ratings maintained.

CASH FLOW SUMMARY

For the years ended September 30 2007 2006 2005 Cash flows related to operating activities before change in non-cash working capital items 347.6 297.3 345.5 Change in non-cash working capital items 48.9 12.1 (26.1) CASH FLOWS RELATED TO OPERATING ACTIVITIES 1 396.5 309.4 319.4 Purchases of property, plant and equipment 2 (124.8) (153.9) (174.2) STANDARDIZED DISTRIBUTABLE CASH 3 271.7 155.5 145.2 Gaz Métro’s adjustments Variations in deferred charges and credits (108.9) (37.0) (64.8) Development CAPEX 23.4 55.8 91.8 DISTRIBUTABLE CASH 4 186.2 174.3 172.2 DISTRIBUTIONS TO PARTNERS 5 (148.4) (156.3) (157.7) EXCESS AVAILABLE 37.8 18.0 14.5 Investments in development of activities Regulated (242.2) (52.4) (89.2) Non-regulated (5.0) 11.2 (99.3) 6 (247.2) (41.2) (188.5) Net financing requirements (209.4) (23.2) (174.0) Financing activities Unit issues 50.1 0.1 66.1 Other financing activities 157.8 32.9 123.3 7 207.9 33.0 189.4 NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENT (1.5) 9.8 15.4 Attachment 2 CAPP 11 Page 27 of 92 GAZ MÉTRO 2007 Annual Report MANAGEMENT’S DISCUSSION AND ANALYSIS 25 LIVE BETTER WITH BLUE

1. CASH FLOWS RELATED TO OPERATING ACTIVITIES Cash flows from operating activities of $396.5 million for the 2007 fiscal year are up $87.1 million over the previous year.

This increase can be explained primarily by, among other things: higher energy consumption generating an additional $7.7 million as a result of average colder temperatures in 2007 than the previous year; lower inventory variances in Gaz Métro-QDA in 2007 than in 2006 ($7.6 million); $16.1 million increase in distributions received from companies subject to significant influence over the previous year; and cash flows generated by a greater reduction in working capital than the previous year.

2. PURCHASES OF PROPERTY, PLANT AND EQUIPMENT

2007 2006

Distribution Sector 110.9 126.7 Transportation Sector 2.6 17.0 Storage Sector 0.3 1.6 Energy Services and Other 11.0 8.6 TOTAL 124.8 153.9

Purchases of property, plant and equipment amounted to $124.8 million in 2007, $29.1 million less than in 2006. The decrease can be explained primarily by expenditures by TQM and Gaz Métro-QDA on a gas pipeline to serve the needs of TCE’s Bécancour cogeneration plant during the previous year. The level of capital expenditures is primarily a reflection of extensions and improvements to the natural gas distribution system in Quebec.

A partnership like Gaz Métro, a high percentage of whose activities are regulated, is generally concerned with maintaining the level of its capital expenditures in its various regulated activities in order to preserve its ability to generate future earnings. As explained in the previous sections, the Partnership is compensated based on the amounts it invests, primarily in its infrastructures, to serve its customers properly.

3. STANDARDIZED DISTRIBUTABLE CASH Standardized distributable cash was $271.7 million during the 2007 fiscal year, compared to $155.5 million the previous year. As explained above, the increase is due to the increase in cash flows from operating activities and a $29.1 million reduction in purchases of property, plant and equipment in 2007, compared to the previous year.

In general, standardized distributable cash flows are the cash flows from operating activities, net of capital expenditures during the fiscal year.

While the computation thereof is standard and comparable for all enterprises, in management’s opinion, it is not an appropriate reflection of the Partnership’s economic reality because it does not take account of certain factors that are specific to its activities. Attachment 2 CAPP 11 Page 28 of 92 26 MANAGEMENT’S DISCUSSION AND ANALYSIS 2007 Annual Report GAZ MÉTRO LIVE BETTER WITH BLUE

4. DISTRIBUTABLE CASH Distributable cash indicates whether the Partnership has generated sufficient funds from operating activities during the fiscal year to finance the distributions paid to the Partners. Two major adjustments have to be made to standardized distributable cash in order to determine the correct amount: an adjustment related to cash flows generated or used by variations in deferred charges and credits, composed mainly of regulatory assets or liabilities that the Partnership associates with working capital instead of long-term investments; and an adjustment to deduct the portion of the investments in property, plant and equipment associated with the increase of the potential for generating cash flows from operating activities in the future.

Distributable cash is $186.2 million for the 2007 fiscal year, an increase of $11.9 million over the previous year’s $174.3 million. Distributable cash per unit is $1.55 per unit in 2007, compared to $1.48 for the previous year. Those levels were sufficient, in both years, to pay the distributions to Partners without any outside financing.

Volatility of distributable cash The level of distributable cash during a year is subject to certain volatility, which is likely to be greater under the following circumstances: average temperatures during heating periods vary significantly in relation to normal, thereby creating significant fluctuations in energy consumption by Gaz Métro’s customers who use natural gas for space heating; natural gas costs vary significantly, thereby generating large differences in the amount of funds to be invested in working capital (to maintain inventories and other items); and large differences in energy costs billed to customers arise during a particular year and have to be recovered from or returned to customers through rates in a subsequent year.

The Partnership therefore has to: remain vigilant in establishing appropriate distribution levels in order not to transfer this volatility; and ensure it always has adequate unused credit facilities to handle all these possible situations.

Variations in deferered charges and credits Expenses related to the cost of energy supply represent net billing differences in connection with the energy costs recoverable from or returnable to customers through rates over a period of not more than 12 months. They amounted to $77.8 million recoverable from customers in 2007, compared to $8.5 million returnable to them last year.

The net funds invested in deferred charges and credits during the 2007 fiscal year, excluding the expenses related to the cost of energy supply, are $31.1 million, compared to $45.5 million the previous year. They are composed primarily of two items–grants paid to Gaz Métro’s customers to convert their equipment to natural gas and expenses on information technology development–both of which were lower than in the 2006 fiscal year. Attachment 2 CAPP 11 Page 29 of 92 GAZ MÉTRO 2007 Annual Report MANAGEMENT’S DISCUSSION AND ANALYSIS 27 LIVE BETTER WITH BLUE

DEFERRED CHARGES AND CREDITS

Normalization Increase Reduction Amortization At the rate (decrease) in Acquisition of charges deferred At the beginning stabilization deferred charges of a related to charges Non-cash end 10/01/2006 accounts and credits subsidiary energy costs and credits adjustments 09/30/2007

Rate stabilization accounts $ 49.9 $21.8 $ – $ – $ – $ (8.3) $ 0.1 $ 63.5 Development of information technology 60.4 – 4.8 – – (12.2) (0.1) 52.9 Credits related to the cost of energy supply (60.4) – 77.8 8.1 (58.0) – (0.6) (33.1) Financing costs 9.6 – 3.6 1.0 – (4.3) (0.3) 9.6 Expenses related to financial instruments 38.5 – – 23.6 – – 12.5 (1) 74.6 Customers’ share in overearnings (7.4) – (9.3) (7.1) – 0.1 1.0 (22.7) Government grants 100.4 – 20.5 4.5 – (17.7) (0.9) 106.8 Gain on transfer of investment (6.1) – – – – – 2.0 (4.1) Pension funding regulatory asset – – 2.1 13.1 – – (1.9) 13.3 Expenses related to Global Energy Efficiency Plan 6.6 – 2.9 – – (2.2) – 7.3 Other 6.5 – 6.5 2.3 – (2.1) (0.8) 12.4 $ 198.0 $21.8 $108.9 $45.5 $(58.0) $(46.7) $11.0 $ 280.5

(1) Net impact of variation in fair value of financial instruments related to Quebec and Vermont distribution activities. During the first quarter of 2007 fiscal year, $15.6 million relating to prior years had to be recorded following the adoption of the new accounting standards as at October 1, 2006 (see Note 3 to consolidated financial statements).

Development CAPEX To clearly identify the potential for generating cash flows from operating activities, a distinction has to be made between maintenance CAPEX and development CAPEX.

DEVELOPMENT CAPEX

2007 2006

Distribution Sector 18.4 47.6 Transportation Sector – 5.6 Storage Sector – – Energy Services and Other 5.0 2.6 TOTAL 23.4 55.8

Development CAPEX: is the portion of investments in property, plant and equipment associated with the growth of the potential for generating cash flows from operating activities in the future. It represents the excess of investments in property, plant and equipment over the amortization expense in each Sector.

Development CAPEX invested in 2007 is mainly in the Distribution Sector where Gaz Métro-QDA continues to connect large numbers of new customers. Attachment 2 CAPP 11 Page 30 of 92 28 MANAGEMENT’S DISCUSSION AND ANALYSIS 2007 Annual Report GAZ MÉTRO LIVE BETTER WITH BLUE

Maintenance CAPEX: is the amounts the Partnership invested in property, plant and equipment to maintain its ability to generate earnings, regardless of the nature of the investments made (system maintenance or extension). This is a financial concept that, in Gaz Métro’s case, is not necessary to reconcile with the concept of an investment in maintenance, which represents the amounts invested to ensure the facilities are reliable and safe.

For Gaz Métro, it is calculated on a sector basis and is deemed to be equal to the lesser of: the Sector’s amortization expense; and investments during the fiscal year in the Sector regardless of their nature.

An investment level that is less than the amortization expense for a particular year could be interpreted as being insufficient for maintaining the Partnership’s, or a particular sector’s, ability to earn income.

INVESTMENTS IN PROPERTY, PLANT AND EQUIPMENT

2007 2006

Distribution Sector 110.9 126.7 Transportation Sector 2.6 17.0 Storage Sector 0.3 1.6 Energy Services and Other 11.0 8.6 TOTAL 124.8 153.9

AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT

2007 2006

Distribution Sector 92.5 79.1 Transportation Sector 11.9 11.4 Storage Sector 2.1 2.1 Energy Services and Other 6.0 6.0 TOTAL 112.5 98.6

MAINTENANCE CAPEX

2007 2006

Distribution Sector 92.5 79.1 Transportation Sector 2.6 11.4 Storage Sector 0.3 1.6 Energy Services and Other 6.0 6.0 TOTAL 101.4 98.1

The Transportation and Storage Sectors did not invest enough during the 2007 fiscal year to offset the decrease in the value of the property, plant and equipment related to the amortization expense.

Risk related to temperature fluctuations Gaz Métro-QDA benefits from a temperature normalization mechanism that eliminates its impacts on the Partnership’s income. However, the mechanism does not shelter Gaz Métro from the impacts possible variations in consumption may have on its cash flows. A much warmer year than normal could result in a significant decrease in cash flows from operating activities. Attachment 2 CAPP 11 Page 31 of 92 GAZ MÉTRO 2007 Annual Report MANAGEMENT’S DISCUSSION AND ANALYSIS 29 LIVE BETTER WITH BLUE

5. DISTRIBUTIONS TO PARTNERS Gaz Métro distributed $0.31 per unit during each quarter of the 2007 fiscal year for a total of $1.24, compared to $1.33 in 2006. In keeping with its policy of distributing virtually all of its income, Gaz Métro distributed 99.6% of its adjusted net income in 2007, compared to 106.2% in 2006.

The Partnership expects to maintain the distributions at $0.31 per unit during each quarter of the 2008 fiscal year.

6. INVESTMENTS IN DEVELOPMENT OF ACTIVITIES Investments in Gaz Métro’s development activities represent the amounts spent on property, plant and equipment or to acquire businesses in order to increase the potential for generating cash flows from operating activities in the future, as explained above.

For Gaz Métro, this will be: the excess of the investments in property, plant and equipment over the amortization expense for those assets (development CAPEX); plus the amounts invested in acquiring new businesses.

INVESTMENTS IN DEVELOPMENT

2007 2006

Development CAPEX (23.4) (55.8) Acquisition of a subsidiary (224.3) – Sale of activities and other 0.5 14.6 TOTAL (247.2) (41.2)

Acquisition of a subsidiary On April 12, 2007, Gaz Métro, through its subsidiary, NNEEC, acquired GMP for a net consideration of $224.3 million, as explained above.

Sale of activities and other On February 14, 2006, Gaz Métro sold 50% of the units of CCUM for a net consideration of $13.9 million, as explained in the preceding sections. The transaction generated a deferred gain of $6.1 million, $2.0 million of which was recognized in the 2007 fiscal year following the collection of one-third of the selling price by the former parent company.

7. FINANCING ACTIVITIES Financing of $209.4 million was required during the 2007 fiscal year, compared to $23.2 million in 2006. The increase is primarily due to the acquisition of GMP on April 12, 2007 for a total consideration of $224.3 million. The required financing was raised through unit issues and new debt.

Unit issues On October 10, 2006, the Partnership issued 2,913,753 units to one of the ultimate beneficiaries of its General Partner at a price of $17.16 per unit for a net consideration of $49.9 million.

Under the Unit Option Plan for Named Executives, Gaz Métro issued 14,508 units in respect of options exercised in 2007 for cash of $218,000, compared to 4,000 units for $60,000 the previous year. Attachment 2 CAPP 11 Page 32 of 92 30 MANAGEMENT’S DISCUSSION AND ANALYSIS 2007 Annual Report GAZ MÉTRO LIVE BETTER WITH BLUE

Other financing activities On April 10, 2007, the Partnership arranged bridge financing of which it used a total of US$178.0 million (US$100.0 million and CAN$89.5 million), in connection with the acquisition of GMP. On June 19, 2007, US$100.0 million was repaid. The balance of CAN$89.5 million as at September 30, 2007 matures mainly on October 9, 2008.

On June 19, 2007, NNEEC issued two series of senior notes of US$50.0 million each bearing interest of 5.93% and 6.12% and maturing on June 19, 2017 and 2022. The proceeds of the issue were used to repay part of the Partnership’s bridge financing for the acquisition de GMP.

The Partnership repaid $75.0 million of first mortgage bonds that matured during the first quarter of the 2007 fiscal year.

CAPITAL STRUCTURE AND DEBT RATIO

2007 2006

Bank borrowings $ 40.8 $ 37.1 Long-term debt maturing within one year 9.4 81.0 Long-term debt 1,644.2 1,314.9 Deferred financing costs (9.6) (9.6) Total debt 1,684.8 1,423.4 Partners’ equity 921.9 924.6 Total capitalization $2,606.7 $ 2,348.0 Debt/total capitalization ratio 64.6% 60.6%

Debt increased by $261.4 million from the previous year’s level to $1,684.8 million, mainly on account of: the acquisition of GMP, which to date has been fully financed by debt, as mentioned above; and the assumption of GMP’s existing debt.

Partners’ equity decreased by $2.7 million in 2007 to $921.9 million, on account of: the unfavourable $27.2 million adjustment to Partners’ equity for the write-down of the U.S. dollar investments; and the unfavourable $26.2 million impact related to the recognition of a future income tax liability related to Intragaz’s activities, as explained above; partially offset by: the impact of the unit issues previously described for a net consideration of $50.1 million.

The debt/total capitalization ratio is 64.6% as at September 30, 2007, compared to 60.6% at the same date last year. As mentioned previously, the Partnership expects to issue units during the 2008 fiscal year in order to bring its capital structure back in line with the previous year.

Risk related to Fluctuations in Exchange Rate on Capital Structure The Partnership, which owns investments in U.S. companies, is exposed to the risk of the devaluation of the U.S. dollar in relation to the Canadian dollar, since it has to revalue its investments at the end of each period and record any changes in Partners’ equity. Attachment 2 CAPP 11 Page 33 of 92 GAZ MÉTRO 2007 Annual Report MANAGEMENT’S DISCUSSION AND ANALYSIS 31 LIVE BETTER WITH BLUE

During the 2007 fiscal year, it had to write down its U.S. dollar investments by $27.2 million, which had an unfavourable impact on the debt/total capitalization ratio. If it had not been for this write-down, the ratio would have been 64.0% instead of 64.6% as presented.

The value of the Partnership’s U.S. dollar investments as at September 30, 2007 is US$199.8 million.

RESTRICTIVE COVENANTS The trust deeds governing the long-term debt stipulate that Gaz Métro will not make any distribution to its Partners if, taking such distribution into account, the total long-term debt would exceed 75% of the total capitalization.

The deeds also stipulate that the Partnership will not issue any new long-term debt if it would increase Gaz Métro’s long- term debt ratio to more than 65% of the total capitalization. As at September 30, 2007, that ratio, which is based on the Partnership’s non-consolidated financial statements, was 56.3 %.

INTEREST RATE POLICY The Partnership’s policy is to fix the rate on approximately 75% of its long-term debt and leave the balance at floating rates. As at September 30, 2007, 84% of the long-term debt is at fixed rates, compared to 90% at the same date last year. This higher than normal level can be explained by the fact that Gaz Métro wanted to take advantage of market opportunities that arose during the 2006 fiscal year.

The Partnership will be able to reduce the percentage as its fixed-rate bonds mature over the next few years.

CREDIT AND STABILITY RATINGS The S&P and DBRS credit and stability ratings were maintained by the rating agencies, as shown in the following table:

2007 2006

Long-term bonds (S&P/DBRS) (1) A/A A/A Commercial paper (S&P/DBRS) (1) A-1(low)/R-1 (low) A-1(low)/R-1 (low) Stability of distributions (S&P/DBRS) SR-2/STA-2 (average) SR-2/STA-2 (average)

(1) Through its General Partner, Gaz Métro inc.

Following the announcement of the closing of the acquisition of GMP, S&P confirmed the credit ratings of Gaz Métro inc. However, it maintained a negative outlook to reflect their perception of a possible increase in the Partnership’s overall risk. In S&P’s view, GMP’s regulatory environment and Gaz Métro’s development strategy, which might increase the proportion of its investments in non-regulated activities, might alter the Partnership’s overall risk.

In terms of GMP’s regulatory risk, the Partnership continues to believe the experience it has acquired with the State’s regulatory bodies through VGS since 1986 clearly shows it is possible to benefit from an appropriate regulatory framework. Following a decision of the VPSB, since February 2007, GMP has been governed by an Alternative Regulation Plan that includes, among other things, quarterly adjustment mechanisms for the price of electricity and the annual sharing of productivity gains, like VGS.

In terms of its development strategy, Gaz Métro has always stated it would be targeted and would have to meet criteria that will enable it to increase earnings, while maintaining a relatively similar risk profile.

The credit ratings given by DBRS show a stable outlook. Attachment 2 CAPP 11 Page 34 of 92 32 MANAGEMENT’S DISCUSSION AND ANALYSIS 2007 Annual Report GAZ MÉTRO LIVE BETTER WITH BLUE

UNUSED CREDIT FACILITIES The Partnership has term credit facilities totalling $621.1 million and various operating credit lines totalling $168.6 million to finance current activities. As at September 30, 2007, borrowings under these facilities are $300.6 million, compared to $171.8 million at the same date last year.

The increase can be explained primarily by: the repayment of $75.0 million of first mortgage bonds in the first quarter of the year; and a bridge financing, of which there is a balance of $89.5 million, to finance part of the acquisition of GMP; partially offset by: the utilization of the proceeds of Gaz Métro’s unit issues, as explained above, to reduce the debt.

CASH AND FINANCING REQUIREMENTS In 2008, the Partnership expects to require funds to: bring its capital structure back in line, as explained above; finance capital expenditures, conversion grants and information technology development, which, in the normal course of business, could be approximately $185 million; finance working capital requirements; and finance the repayment of the $89.5 million balance of the bridge financing for the acquisition of GMP.

Financing is expected to come from: cash flows relating to operating activities; credit lines currently available for capital expenditures and working capital; new short- and long-term financing; and new unit issues.

As Gaz Métro’s policy is to distribute virtually all of its income, it has to turn to the capital markets to raise any financing it needs for major investment projects that are not part of its ongoing business requirements. In these cases, the Partnership usually issues debt or additional units required for Gaz Métro-QDA’s activities in order to maintain to the extent possible an average capital structure of 54% debt and 46% equity as authorized by the Régie. On a consolidated basis, the Partnership strives to keep its debt/total capitalization ratio below 60%. Normally, Gaz Métro does not have problem in raising financing, nor does it expect any problem in this regard in the future.

OFF-BALANCE SHEET ARRANGEMENTS Securitization program The Partnership has signed an agreement that expires on September 30, 2010 for the regular transfer of receivables to a securitization trust. The $85.0 million maximum authorized was negotiated with the financial institution, which has no recourse against the Partnership in the event debtors fail to pay amounts owing when due. As at September 30, 2007, the amount of the receivables transferred, net of the subordinated rights retained by Gaz Métro, amounts to $35.0 million.

Guarantees The Partnership and some of its subsidiaries have agreed to provide certain collateral, pursuant to financial instrument contracts that define the price of natural gas or electricity, the interest rates or the exchange rates, if the market value of the said instruments becomes negative for Gaz Métro and exceeds a pre-determined limit in the contract. However, these commitments cannot have any direct impact on income. Attachment 2 CAPP 11 Page 35 of 92 GAZ MÉTRO 2007 Annual Report MANAGEMENT’S DISCUSSION AND ANALYSIS 33 LIVE BETTER WITH BLUE

Gaz Métro is not authorized by the Régie to give guarantees to counter parties in connection with non-Gaz Métro-QDA activities in order to minimize the potential risks under these contracts. Gaz Métro has therefore not paid anything under these contracts in the past and does not expect to do so in the future.

Commitments The following table presents a summary, as at September 30, 2007, of the commitments for the next five years and thereafter.

2008 2009 2010 2011 2012 After Total

First mortgage bonds – 100.0 100.0 – – 933.4 1,133.4 Bonds – 50.0 87.5 – – – 137.5 Capital leases 0.6 0.3 0.3 0.3 0.4 1.6 3.5 Term loans 8.8 83.0 40.4 35.3 78.2 14.1 259.8 Other long-term debts – – – – – 119.4 119.4 9.4 233.3 228.2 35.6 78.6 1,068.5 1,653.6 Operating leases 1.6 1.3 0.6 0.5 0.1 – 4.1

TOTAL 11.0 234.6 228.8 36.1 78.7 1,068.5 1,657.7

In addition to the aforementioned commitments, the Partnership has signed natural gas and electricity supply, transportation and storage contracts for periods up to 2017. The costs relating to these contracts will be recovered from customers in the corresponding periods.

Financial instruments The Partnership uses derivative financial instruments to reduce or eliminate the risk inherent in certain transactions and identifiable balances that arise in the normal course of business. These inherent risks arise from fluctuations in natural gas and electricity prices, and interest and exchange rates. The Partnership does not hold or use derivative financial instruments for speculative purposes and only concludes hedge transactions with major financial institutions that meet its credit evaluation standards.

Gaz Métro mainly uses derivative financial instruments to manage its exposure to the volatility of natural gas prices for system gas customers. The Partnership has to respect temporal, volumetric and financial limits approved by the Régie in connection with Gaz Métro-QDA, or by management for other activities. Gains or losses attributable to these instruments for Gaz Métro-QDA’s supply service are included in the costs related to the supply of gas as these costs are recognized in accordance with the method approved by the Régie.

On October 1, 2006, the Partnership adopted the recommendations in the following Sections of the Handbook: Section 1530-Comprehensive Income; Section 3855, Financial Instruments-Recognition and Measurement, Section 3861, Financial Instruments-Disclosure and Presentation and Section 3865-Hedges. These new Sections of the Handbook contain, among other things, comprehensive standards for the recognition, measurement, presentation and disclosure of financial instruments, describe when and how hedge accounting may be applied and introduce a new income measurement- comprehensive income. Adoption of these recommendations did not have any impact on the Partnership’s net income or Partners’ equity. Attachment 2 CAPP 11 Page 36 of 92 34 MANAGEMENT’S DISCUSSION AND ANALYSIS 2007 Annual Report GAZ MÉTRO LIVE BETTER WITH BLUE

Based on the recommendations in these new Sections, all derivative financial instruments used by the Partnership should now be recorded in the balance sheet at their fair value. As at September 30, 2007, the net fair value of the instruments held by the Partnership was:

Presented as assets: $ 8,183 Presented as liability: (82,492) Net fair value: $(74,309)

Additional information about the magnitude of the changes from the adoption of these standards is provided in Note 3 to the consolidated financial statements.

OUTSTANDING UNITS As at September 30, 2007, consolidated Partners’ equity includes 120,437,400 units issued for $1,011.7 million.

F) RISKS This section describes the main risks likely to affect the results and financial condition of Gaz Métro but does not comment on all the means taken, in certain cases, to control or minimize the impact thereof.

ECONOMY AND MARKETS Gaz Métro’s activities are affected by general economic conditions. A poor economy will have a negative impact on the activities of its industrial and commercial customers, and therefore on the demand for natural gas. A significant reduction in demand at a time when it is increasingly difficult to reduce Gaz Métro-QDA’s expenses would push distribution rates up and could therefore adversely affect the Partnership’s competitiveness.

For a number of years, Gaz Métro has been making an effort to increase its market share of the residential market for which gross margins are higher and thereby reduce its vulnerability in the industrial market.

COMPETITION Gaz Métro’s ability to achieve sound financial results is dependent on the competitiveness of natural gas in relation to other energy sources, such as fuel oil and electricity. In Quebec, electricity has the largest share of the residential market. However, successive rate increases since 2004, combined with lower natural gas prices, have put these two energies on an equal footing in the new housing market.

In the commercial sector, natural gas is generally competitive with both fuel oil and electricity. The sharp recent increase in the price of fuel oil has improved its competitiveness with heavy fuel oil in the large industrial interruptible service market. However, large industrial firm service customers continue to prefer natural gas because the potential savings are generally insufficient to justify the expenditures required to adopt a substitute energy. They also prefer natural gas to heavy fuel oil for its environmental impacts.

The government of Quebec’s announcement on October 1, 2007 of a major program to provide financing to businesses for the purchase of efficient equipment or conversion to other energies that are cleaner than heavy fuel oil could help promote the use of natural gas. Attachment 2 CAPP 11 Page 37 of 92 GAZ MÉTRO 2007 Annual Report MANAGEMENT’S DISCUSSION AND ANALYSIS 35 LIVE BETTER WITH BLUE

COMMERCIAL RISK Every year, distribution rates are established by the Régie and the VPSB based on projections provided by Gaz Métro. If, among other things, actual deliveries were to be less than the projections for a particular year (based on normalized temperatures in Quebec), it could have an unfavourable impact on Gaz Métro’s income for that year.

REGULATION Decisions rendered by regulatory bodies, and in particular those rendered by the Régie, the NEB and the VPSB with respect to rates and the return allowed on Partners’ equity allocated to the natural gas and electricity distribution and transportation activities, can have a significant impact on Gaz Métro’s financial results. If economic or energy conditions become such that a performance incentive mechanism is no longer appropriate, this could also have an impact on the Partnership’s profitability.

Since October 1, 2007, Gaz Métro-QDA, which is the Partnership’s core business, benefits from a five-year performance incentive mechanism that is more in line with its environment, as explained before.

ENERGY SUPPLY Gaz Métro depends on various suppliers, carriers, storage operators and others for its natural gas supply, which comes primarily from western Canada. The failure of one of these parties to deliver natural gas or provide related services, as well as a major disruption in the supply chain, with no possible recourse to alternative supply sources, could have a negative impact on the Partnership and its ability to distribute natural gas to its customers.

To meet its energy needs, GMP depends on various energy supply contracts. There is no guarantee those contracts will be renewed on favourable terms and conditions (or that they will even be renewed) when they expire. If this were to happen, GMP might have to buy energy at higher prices than those in its present energy supply contracts or, if it could not access any alternative energy sources, its ability to respond to customer demand might be hindered, which could have an unfavourable impact on Gaz Métro’s income.

While the energy contracts still have a number of years to run, discussions have already been undertaken to ensure access to different reliable supply sources at a good price.

CONTINUITY OF ACTIVITIES Ensuring the distribution activity’s operations are not interrupted depends on Gaz Métro’s ability to protect the distribution systems and equipment, and the information stored in data centres from damage due to fire, natural disasters, power outages, break-ins, computer viruses, acts of war or terrorism and other similar situations. Any one of these events could interrupt service at any time, with repercussions on customers and operating results.

Gaz Métro has very strict policies with respect to safeguarding assets and information that it follows very carefully. It also carries insurance coverages with reputable insurers for amounts that are considered sufficient given the nature of the Partnership’s activities and its size.

FINANCING OF INVESTMENTS IN COMPANIES Gaz Métro finances the development of certain subsidiaries, joint ventures and companies subject to significant influence. If it were to discontinue financing, one of these enterprises and the enterprise did not have alternative financing, it could have a negative impact on the value of these investments and, therefore, on the Partnership’s results. Attachment 2 CAPP 11 Page 38 of 92 36 MANAGEMENT’S DISCUSSION AND ANALYSIS 2007 Annual Report GAZ MÉTRO LIVE BETTER WITH BLUE

VALUE OF INVESTMENTS The value of certain investments in subsidiaries, joint ventures and companies subject to significant influence could deteriorate if they are unable to generate sufficient earnings to justify the amounts invested. Persistent difficult economic conditions or unfavourable competitive situation might oblige the Partnership to write down certain investments, which could have a negative impact on its results.

G) RECENT ACCOUNTING CHANGES Note 3 to the consolidated financial statements provides details of the accounting policies adopted in 2007 as a result of the following new accounting standards: Financial Instruments–Recognition, Measurement, Disclosure and Presentation; Comprehensive Income; Hedges; and Equity.

Note 3 also provides information about accounting standards that will be applicable in the future: Accounting Changes; Capital Disclosures; and Financial Instruments–Disclosure and Presentation.

H) SIGNIFICANT ACCOUNTING ESTIMATES The preparation of the Partnership’s consolidated financial statements in accordance with Canadian generally accepted accounting principles (GAAP) requires management to make assumptions and exercise judgement in making estimates. Those estimates, which are based on past experience and present conditions, might differ significantly from actual results. The significant accounting estimates are described below.

REGULATION Some of the Partnership’s important activities are regulated and adopt, with the approval of their respective regulatory body, certain accounting policies that do not comply with GAAP. Accounting estimates are sometimes required because the regulatory frameworks under which the Partnership’s regulated public services carry on their activities often require that amounts be recorded at their estimated amount until they are definitively established, in accordance with regulatory decisions or other regulatory processes.

The definitive amounts approved by the regulatory bodies for treatment as regulatory assets and liabilities and the approved recovery or settlement periods may sometimes differ from the initial expectations. Any adjustment to the initial estimates is presented in income for the period during which it is confirmed. The nature of the Partnership’s regulatory assets and liabilities is described in Note 4 to the 2007 consolidated annual financial statements.

AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT Amortization is an estimate based mainly on the useful life of the assets. That estimate is based on actual facts and historical information and takes account of the anticipated useful life of the assets. Because of the magnitude of this class of the Partnership’s assets, variations in amortization rates may have a significant impact on amortization expense. Attachment 2 CAPP 11 Page 39 of 92 GAZ MÉTRO 2007 Annual Report MANAGEMENT’S DISCUSSION AND ANALYSIS 37 LIVE BETTER WITH BLUE

In connection with the process for establishing the rates for the Partnership’s regulated public services, appropriate amortization rates are approved by the regulatory bodies. The periods and the amortization rates used are reviewed regularly to ensure they continue to be appropriate. From time to time, third parties perform studies on the amortization of the property of regulated public utilities and, based on the results of those studies, the impact of any amortization or under-amortization attributable to a difference between actual and forecast information is normally reflected in future amortization rates and expense. The corresponding amounts are either returned to or recovered from customers through rates charged.

VALUATION OF GOODWILL Goodwill is the excess of the acquisition cost over the net values attributed to all assets and liabilities of an acquired enterprise and is not amortized. Goodwill is subject to an impairment test each year or more frequently if events or changes indicate it might not be recoverable.

In the fourth quarter of each fiscal year, the Partnership reviews its goodwill to determine if there is a possible decrease in value based on current information and valuations of the fair market value of the business units being examined. The fair market value is based on, among other things, the net present value of the expected cash flows based on management’s assumptions about the future profitability of the operating units. No write-off had to be recorded during the 2007 fiscal year.

I) ADDITIONAL INFORMATION RELATED PARTY TRANSACTIONS During the year, in the normal course of business, the Partnership paid gas storage costs totalling $20.0 million to Intragaz, a joint venture of Gaz Métro in partnership with an ultimate shareholder. The Partnership’s share of Intragaz’s revenues, which is eliminated on consolidation, is $12.0 million in 2007. These transactions were authorized by the Régie and the amounts paid were determined in accordance with the terms of the contracts signed by the parties establishing the value of the services rendered at the exchange amount.

LAWSUITS The Partnership is cited in claims and lawsuits in the normal course of its activities. In the opinion of management, these claims and lawsuits are, for the most part, covered by appropriate insurance coverage and the overall amount of the contingent liability is not material.

VGS and GMP, subsidiaries of NNEEC, jointly with others, have been cited as being potentially responsible for polluting land on which a manufactured gas plant that ceased operations in 1966 was located. In 1999, a settlement protocol was signed by the Environmental Protection Agency (EPA) and the enterprises involved. It included an action plan to restore the site and a cost sharing method. The EPA has not completed its investigation and NNEEC is not presently able to predict the outcome of this matter. The VPSB has agreed that the costs incurred to date by VGS and GMP can be recovered in rates over a period of 10 to 20 years. If future outlays exceed the provisions already recorded in the books, new requests to recover such amounts in rates will be submitted to the VPSB. In the opinion of management, the costs that might arise in connection with this potential lawsuit would not be significant for the Partnership. Attachment 2 CAPP 11 Page 40 of 92 38 MANAGEMENT’S DISCUSSION AND ANALYSIS 2007 Annual Report GAZ MÉTRO LIVE BETTER WITH BLUE

J) QUARTERLY RESULTS HIGHLIGHTS OF QUARTERLY RESULTS

2007 1st 2nd 3rd 4th Fiscal year

Revenues $ 534.0 $ 731.2 $ 388.7 $ 303.6 $1,957.5 Gross margin $ 185.4 $ 217.0 $ 122.0 $ 99.2 $ 623.6 Net income (loss) (a) $ 71.8 $ 104.3 $ 1.1 $ (54.4) $ 122.8 Basic and diluted net income (loss) per unit (in dollars) $ 0.60 $ 0.86 $ 0.01 $ (0.45) $ 1.02 Distributions paid per unit (in dollars) $ 0.31 $ 0.31 $ 0.31 $ 0.31 $ 1.24 Partners’ equity per unit (in dollars) $ 8.43 $ 8.98 $ 8.53 $ 7.65 $ 7.65 Market prices on Toronto Stock Exchange (in dollars): High $ 18.50 $ 17.42 $ 17.58 $ 17.33 $ 18.50 Low $ 15.30 $ 15.51 $ 16.50 $ 15.49 $ 15.30 Close $ 15.58 $ 16.86 $ 16.86 $ 16.02 $ 16.02 Weighted average number of outstanding units (in millions) 120.4 120.4 120.4 120.4 120.4 a) Including future income tax expense of $26.2 million in the fourth quarter related to the activities of Intragaz, as explained before.

2006 1st 2nd 3rd 4th Fiscal year

Revenues $ 681.3 $ 762.9 $ 323.1 $ 236.5 $ 2,003.8 Gross margin $ 179.9 $ 209.8 $ 109.1 $ 77.5 $ 576.3 Net income (loss) $ 70.8 $ 102.8 $ (0.1) $ (26.3) $ 147.2 Basic and diluted net income (loss) per unit (in dollars) $ 0.60 $ 0.88 $ 0.00 $ (0.23) $ 1.25 Distributions paid per unit (in dollars) $ 0.34 $ 0.34 $ 0.34 $ 0.31 $ 1.33 Partners’ equity per unit (in dollars) $ 8.25 $ 8.79 $ 8.40 $ 7.87 $ 7.87 Market prices on Toronto Stock Exchange (in dollars): High $ 22.50 $ 20.43 $ 20.53 $ 17.60 $ 22.50 Low $ 19.08 $ 19.50 $ 15.79 $ 15.56 $ 15.56 Close $ 19.57 $ 20.14 $ 16.20 $ 17.60 $ 17.60 Weighted average number of outstanding units (in millions) 117.5 117.5 117.5 117.5 117.5

NET INCOME NET INCOME PER UNIT (in millions of dollars) (in dollars) 72 71 176 174 177 173 123 147 0.60 0.60 1.46 1.48 1.47 1.48 1.02 1.25 200 2.00

100 1.00 07 07 0 06 0 06 YTD 07 YTD 07 1

72 71 YTD 06 YTD 06

(100) (1) (1.00) 0.60 0.60 0.86 0.88 0.01 0.00 104 103 (54) (26) (0.45) (0.23) 1st 2nd 3rd 4th 1st 2nd 3rd 4th Quarter Quarter Attachment 2 CAPP 11 Page 41 of 92 GAZ MÉTRO 2007 Annual Report MANAGEMENT’S DISCUSSION AND ANALYSIS 39 LIVE BETTER WITH BLUE

Q4 RESULTS FOR FISCAL 2007 – OVERVIEW The net loss for the fourth quarter of the 2007 fiscal year is up $28.1 million to $54.4 million, compared to $26.3 million for the same period last year. Had it not been for the $26.2 million non-monetary impact from the recording of a future income tax liability related to Intragaz’s activities as at September 30, 2007, as explained before, the net loss would have been $28.2 million, which is comparable to the previous year.

The net loss per unit, excluding the non-monetary impact from recording the tax liability relating to Intragaz’s activities, is $0.23, which is the same as the fourth quarter in 2006.

The $28.1 million increase in the net loss can be explained primarily by: the recording as at September 30, 2007 of a future income tax liability of $26.2 million related to Intragaz’s activities; the collection of a larger amount in the fourth quarter of 2006 than in 2007 related to the settlement of the bankruptcy of a former customer of PNGTS ($3.5 million in 2006 versus $0.5 million in 2007); the favourable settlement in Intragaz ($1.0 million) of a dispute during the fourth quarter of the previous year; and the $0.7 million increase in interest expense related to the financing of its investments in the various Sectors; partially offset by: the consolidation of GMP’s results since April 12, 2007; the recording in the fourth quarter of 2006 of an $0.8 million goodwill write-off in one of the subsidiaries in the Energy Services and Other Sector; and a reduction in development expenditures and non-allocated expenses.

K) OUTLOOK Taxation of flow-through entites On June 22, 2007, the House of Commons adopted Bill C-52 enacting the Income Tax Act amendments implementing the proposals in the Minister of Finance’s Tax Fairness Plan tabled on October 31, 2006 with respect to income trusts and limited partnerships (flow-through entities). The amendments transfer the payment of income tax (presently paid by each Partner) on Gaz Métro’s income to the partnership level at the corporate tax rate, effective October 1, 2010, and treat the after-tax income distributions as dividends for tax purposes.

In its present form, the amendments would reduce income that can be distributed because it would be after tax. During the 2007 fiscal year, approximately 85% of Gaz Métro’s pre-tax income came from entities that were not taxable at the Partnership level. Only that portion would be affected by the change in the law as of October 1, 2010. The impact on the Partners would depend on their individual tax status. Gaz Métro is analyzing its various alternatives.

Gaz Métro-QDA The challenge for the current and future years will be to continue the profitable development of Gaz Métro-QDA by increasing the customer base in the commercial and residential markets, controlling costs and ensuring the gas system is safe and reliable. The Régie’s acceptance of the changes to the performance incentive mechanism proposed by Gaz Métro and the interested parties is positive for the future. Even though the Régie’s October 15, 2007 decision on the 2008 rate application did not change the formula for establishing the allowed rate of return, it did increase the risk premium by 14 basis points and, consequently, increase the authorized rate of return on Partners’ deemed common equity. Attachment 2 CAPP 11 Page 42 of 92 40 MANAGEMENT’S DISCUSSION AND ANALYSIS 2007 Annual Report GAZ MÉTRO LIVE BETTER WITH BLUE

The Régie also accepted a number of changes requested by Gaz Métro to further its profitable development while reducing the volatility of its results. Financial results continue to be dependent on the health of the economy and the demand for natural gas.

Gaz Métro recovers through its rates the income taxes that will be subsequently paid by its partners. The reduction in the corporate tax rate announced on October 30, 2007, by the Minister of Finance, effective January 1, 2008, will reduce the amount that will be recovered from customers and, consequently, net income related to the Quebec distribution activity.

On December 13, 2006, an Act respecting the implementation of the Quebec Energy Strategy and amending certain legislative provisions (also referred to as Bill 52) came into force. The statute provides that a distributor of natural gas, fuel or combustibles for energy purposes shall pay an annual royalty to the Ministre du Développement durable, de l’Environnement et des Parcs du Québec, which will pay it to the Green Fund it has created. The rate and the calculation of the annual royalty is based on carbon dioxide emissions (CO2) generated by these combustibles. On June 20, 2007, the draft regulation, which establishes the rate and the method of calculating the annual royalty, was published for consultation for a period of 45 days. To date, the final regulation has not been published. Gaz Métro is waiting for confirmation of the date the first payment will have to be made and plans to include the royalty in its rates.

Green Mountain Power Corporation The year just starting will be the first full year GMP will contribute to Gaz Métro’s results.

Other activities For the Transportation Sector, the treatment of rate applications submitted to the NEB by TQM (winter of 2008) and to the FERC by PNGTS (spring of 2008) is the key issue for next year and should make it possible to secure and even improve the profitability of the Sector.

In the Energy Services and Other Sector, Gaz Métro will continue its efforts to improve profitability by consolidating activities and increasing sales.

Development Gaz Métro will continue to look for investment opportunities in the energy sector that will enable it to increase its profitability without affecting its risk profile.

With respect to Rabaska, Gaz Métro will continue its efforts to secure long-term liquefied natural gas supplies in order to start construction of the terminal as soon as possible.

The results of the bids in connection with the Seigneurie de Beaupré wind power project will be known by the spring of 2008.

Management’s Discussion and Analysis has been prepared as of November 19, 2007. Additional information about Gaz Métro, including its audited consolidated financial statements for the fiscal year ended September 30, 2007, and eventually its 2007 Annual Information Form, can be found on SEDAR at www.sedar.com. Attachment 2 CAPP 11 Page 43 of 92 GAZ MÉTRO 2007 Annual Report 41 LIVE BETTER WITH BLUE

CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED SEPTEMBER 30, 2007 AND 2006

42 43 44 44 Management’s Consolidated Consolidated Consolidated report and income comprehensive partners’ Auditors’ report income equity

45 46 47 Consolidated Consolidated Notes to balance sheets cash flows consolidated financial statements Attachment 2 CAPP 11 Page 44 of 92 42 2007 Annual Report GAZ MÉTRO LIVE BETTER WITH BLUE

MANAGEMENT’S REPORT AND AUDITORS’ REPORT

MANAGEMENT’S REPORT On the Consolidated Financial Statements of Gaz Métro Limited Partnership The consolidated financial statements of Gaz Métro Limited Partnership and all of the information in this report are the responsibility of the management of Gaz Métro inc., acting in its capacity as General Partner of Gaz Métro Limited Partnership. It is management’s responsibility to select the appropriate accounting policies and to exercise its best judgement in determining reasonable and fair estimates based on Canadian generally accepted accounting principles and decisions by bodies that govern the various regulated activities of the Partnership. Financial information found elsewhere in this report is consistent with the consolidated financial statements. This information and the consolidated financial statements are published with the Board of Directors’ approval. Management maintains accounting and internal control systems that are designed to provide reasonable assurance that accounting records are reliable and assets are safeguarded. The Board of Directors assumes its responsibilities for the financial statements primarily through the Audit Committee, made up solely of outside directors. The Audit Committee has reviewed all of the information in this report as well as the annual financial statements and has recommended they be approved by the Board. The Audit Committee also examines on a continuous basis the quarterly financial results and the results of internal and external audits of accounting methods and the system of internal controls. The Audit Committee also recommends to the Board the choice of external auditors. The external and internal auditors are free to communicate with the Audit Committee. Raymond Chabot Grant Thornton LLP, Chartered Accountants, have been given the mandate to audit the consolidated financial statements of Gaz Métro Limited Partnership in accordance with Canadian generally accepted auditing standards. Their audit included the tests and other procedures they deemed necessary under the circumstances. Their independent opinion on the financial statements is presented hereinafter.

SOPHIE BROCHU PIERRE DESPARS, CA President and Executive Vice President and Chief Executive Officer Chief Financial Officer Gaz Métro inc. Gaz Métro inc. Montreal, Canada November 19, 2007

AUDITORS’ REPORT To the Partners of Gaz Métro Limited Partnership We have audited the consolidated balance sheets of Gaz Métro Limited Partnership as at September 30, 2007 and 2006, and the consolidated statements of income, comprehensive income, Partners’ equity and cash flows for the years then ended. These financial statements are the responsibility of the management of Gaz Métro inc., acting in its capacity as General Partner of the Partnership. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Partnership as at September 30, 2007 and 2006 and the results of its operations and its cash flows for the years then ended in accordance with Canadian generally accepted accounting principles.

RAYMOND CHABOT GRANT THORNTON LLP Chartered Accountants Montreal, Canada November 19, 2007 Attachment 2 CAPP 11 Page 45 of 92 GAZ MÉTRO 2007 Annual Report 43 LIVE BETTER WITH BLUE

CONSOLIDATED INCOME

Years ended September 30, (in thousands of dollars and thousands of units) 2007 2006

REVENUES $1,957,469 $2,003,766 DIRECT COSTS 1,333,851 1,427,455 GROSS MARGIN 623,618 576,311

EXPENSES Operations and maintenance 220,664 206,855 Amortization (Notes 7, 9 and 19) 155,375 137,729 Interest on long-term debt 101,555 90,877 Financial and other 6,179 3,855 483,773 439,316 INCOME BEFORE SHARE OF INCOME OF COMPANIES SUBJECT TO SIGNIFICANT INFLUENCE AND INCOME TAXES 139,845 136,995 Share of income of companies subject to significant influence 15,474 22,106 INCOME BEFORE INCOME TAXES 155,319 159,101 Income taxes (Note 18) 32,478 11,894 NET INCOME $ 122,841 $ 147,207

NET INCOME PER UNIT (in dollars) Basic $ 1.02 $ 1.25 Diluted $ 1.02 $ 1.25 WEIGHTED AVERAGE NUMBER OF OUTSTANDING UNITS (Note 14) Basic 120,433 117,507 Diluted 120,435 117,516

The accompanying notes to the consolidated financial statements are an integral part of these statements. Attachment 2 CAPP 11 Page 46 of 92 44 2007 Annual Report GAZ MÉTRO LIVE BETTER WITH BLUE

CONSOLIDATED COMPREHENSIVE INCOME

Years ended September 30, (in thousands of dollars) 2007 2006

NET INCOME $ 122,841 $ 147,207 OTHER CONSOLIDATED COMPREHENSIVE INCOME Latent exchange losses on translation of financial statements of self-sustaining foreign operations (27,194) (4,838)

CONSOLIDATED COMPREHENSIVE INCOME $ 95,647 $ 142,369

CONSOLIDATED PARTNERS’ EQUITY

Years ended September 30, (in thousands of dollars) 2007 2006

CAPITAL Balance, beginning of year $ 951,933 $ 960,949 Unit issues (Notes 14a) and 14b)) 50,087 60 Net income 122,841 147,207 1,124,861 1,108,216 Distributions to Partners (Note 14c)) (148,430) (156,283) Balance, end of year 976,431 951,933

OTHER CONSOLIDATED COMPREHENSIVE INCOME, CUMULATIVE Balance, beginning of year (27,345) (22,507) Change (27,194) (4,838) Balance, end of year (54,539) (27,345)

CONSOLIDATED PARTNERS’ EQUITY $ 921,892 $ 924,588

The accompanying notes to the consolidated financial statements are an integral part of these statements. Attachment 2 CAPP 11 Page 47 of 92 GAZ MÉTRO 2007 Annual Report 45 LIVE BETTER WITH BLUE

CONSOLIDATED BALANCE SHEETS

As at September 30, (in thousands of dollars) 2007 2006

ASSETS

CURRENT ASSETS Cash and cash equivalents $ 30,489 $ 31,962 Trade and other receivables (Note 6) 125,997 102,406 Inventories 213,539 250,371 Prepaid expenses 6,719 5,894 376,744 390,633 PROPERTY, PLANT AND EQUIPMENT (Note 7) 2,148,384 1,923,569

OTHER ITEMS Investments and other (Note 8) 144,607 124,233 Deferred charges (Note 9) 340,378 271,830 Intangible assets 10,963 11,163 Goodwill (Note 19) 113,201 43,047 Derivative financial instruments (Note 21) 8,183 18,722 617,332 468,995 $3,142,460 $2,783,197

LIABILITIES

CURRENT LIABILITIES Bank borrowings (Note 11) $ 40,805 $ 37,134 Accounts payable and accrued liabilities 275,175 243,067 Long-term debt maturing within one year 9,446 80,964 325,426 361,165

LONG-TERM DEBT (Note 12) 1,644,154 1,314,855 DEFERRED CREDITS (Note 13) 59,875 73,845 FUTURE INCOME TAXES (Note 18) 108,621 51,829 DERIVATIVE FINANCIAL INSTRUMENTS (Note 21) 82,492 56,915 2,220,568 1,858,609

PARTNERS’ EQUITY (Note 14) CAPITAL 976,431 951,933 OTHER CONSOLIDATED COMPREHENSIVE INCOME, CUMULATIVE (54,539) (27,345) 921,892 924,588 $3,142,460 $2,783,197

The accompanying notes to the consolidated financial statements are an integral part of these statements.

On behalf of the Board of Directors of Gaz Métro inc. in its capacity as General Partner

SOPHIE BROCHU RÉAL SUREAU, FCA Director Director Attachment 2 CAPP 11 Page 48 of 92 46 2007 Annual Report GAZ MÉTRO LIVE BETTER WITH BLUE

CONSOLIDATED CASH FLOWS

Years ended September 30, (in thousands of dollars) 2007 2006

OPERATING ACTIVITIES Net income $ 122,841 $ 147,207 Distributions received from companies subject to significant influence 17,902 1,778 Non-cash items: Amortization of property, plant and equipment 112,519 98,632 Amortization of deferred charges, financing costs and intangible assets 47,194 42,063 Reduction in deferred charges related to energy supply cost 57,980 54,474 Rate stabilization accounts (21,832) (37,120) Share of income of companies subject to significant influence (15,474) (22,106) Gain on sale of investment (2,002) – Write-off of goodwill – 768 Future income taxes 28,540 11,604 347,668 297,300 Change in non-cash working capital items (Note 15a)) 48,872 12,126 CASH FLOWS RELATED TO OPERATING ACTIVITIES 396,540 309,426

INVESTING ACTIVITIES Purchases of property, plant and equipment (124,793) (153,892) Variations in deferred charges and credits (108,863) (37,012) Acquisition of a subsidiary (Note 5) (224,312) – Sale of commercial activities and other 504 14,585 CASH FLOWS RELATED TO INVESTING ACTIVITIES (457,464) (176,319)

FINANCING ACTIVITIES Change in bank borrowings 2,294 7,286 Change in term loans 124,552 (258,254) Other long-term debt: Issues 106,936 311,571 Repayments (75,988) (27,693) Unit issues 50,087 60 Distributions to Partners (148,430) (156,283) CASH FLOWS RELATED TO FINANCING ACTIVITIES 59,451 (123,313)

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (1,473) 9,794 CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR 31,962 22,168 CASH AND CASH EQUIVALENTS, END OF YEAR $ 30,489 $ 31,962

The accompanying notes to the consolidated financial statements are an integral part of these statements. Attachment 2 CAPP 11 Page 49 of 92 GAZ MÉTRO 2007 Annual Report NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 47 LIVE BETTER WITH BLUE

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (ALLTABULARAMOUNTSAREINTHOUSANDSOFDOLLARS)

1. NATURE OF OPERATIONS Gaz Métro Limited Partnership (the Partnership or Gaz Métro) is a company whose core business is the distribution of natural gas in Quebec. Gaz Métro is also, indirectly, the sole shareholder of Vermont Gas Systems, Inc. (VGS), the sole gas distributor in the State of Vermont (U.S.A.), and since April 12, 2007, of Green Mountain Power Corporation (GMP), the second largest electricity distributor in Vermont. In addition, through its subsidiaries, joint ventures and companies subject to significant influence, Gaz Métro is involved in other mostly regulated activities relating to the transportation and storage of natural gas as well as energy and other services.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES The consolidated financial statements of Gaz Métro are prepared in accordance with Canadian generally accepted accounting principles. In preparing the consolidated financial statements, the Partnership’s management has to make estimates and assumptions that have an impact on the assets and liabilities shown in the balance sheet, the contingent liabilities noted as at the date of the consolidated financial statements and the revenues and expenses presented in the Statement of Consolidated Income for the year. Actual results may differ from these estimates.

PRINCIPLES OF CONSOLIDATION The consolidated financial statements of the Partnership include the accounts of Gaz Métro and its subsidiaries. In addition, the investments in joint ventures are accounted for under the proportionate consolidation method. Investments in companies subject to significant influence are recorded at equity value. Other investments are recorded at cost.

REGULATION Gaz Métro is engaged primarily in the distribution of natural gas by pipeline in Quebec, an activity that is regulated by the Régie de l’énergie (the Régie).

Through certain subsidiaries, joint ventures and companies subject to significant influence, it also carries on other “regulated” activities that are regulated by other bodies. Trans Québec & Maritimes Pipeline Inc. (TQM) and Champion Pipeline Corporation Limited (Champion) are regulated by the National Energy Board (NEB). Portland Natural Gas Transmission System (PNGTS) is regulated by the Federal Energy Regulatory Commission (FERC), and VGS and GMP are regulated by the Vermont Public Service Board (VPSB).

In exercising their authority, the regulatory bodies render decisions on, among other things, system development, rate setting and the utilization of certain underlying accounting practices that are different from those otherwise applied by non-regulated enterprises. The impact of rate regulation on the Partnership is presented in Note 4.

CASH AND CASH EQUIVALENTS Cash and cash equivalents consist of cash and very liquid short-term investments with a maturity of three months or less when purchased.

INVENTORIES Inventories are composed primarily of natural gas used by the Quebec distribution activity and recorded at a price equal to the supply rate approved by the Régie. The rate is adjusted every month in accordance with a method approved by the Régie whereby all costs are billed entirely to customers, including the impact of the risk management activities related to the price of natural gas. Materials and supplies inventories are valued at average cost. Attachment 2 CAPP 11 Page 50 of 92 48 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 2007 Annual Report GAZ MÉTRO LIVE BETTER WITH BLUE

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment consist primarily of assets used in “regulated” activities. Acquisitions, replacements and improvements are recorded at cost, including direct costs and general expenses, and an allowance on funds used for certain construction projects that includes both an interest and an equity component as accepted by regulatory authorities. The historical cost of retired properties related to the distribution system and the retirement costs are applied against accumulated amortization when the properties are retired. Under this method, no gain or loss on disposal of assets is recognized in results.

Amortization is calculated using mainly the straight-line method based on the residual useful lives of the existing assets. The rates are periodically revised and approved by the regulatory bodies and include recovery of the unamortized cost of existing assets, estimates of the future costs of retiring the properties in certain cases and the profit and loss upon disposal of properties already retired.

DEFERRED CHARGES Certain charges are deferred and then amortized and recovered in rates over various periods not exceeding 12 years depending on the nature of such charges (Note 4).

INTANGIBLE ASSETS The intangible assets represent almost entirely the value of the clientele acquired on the acquisition of a joint venture. They are carried at cost, net of accumulated amortization, and are amortized using the straight-line method over 25 years. Each year, or more often if events or changes in circumstances indicate they might not be recoverable, they are subjected to an impairment test.

GOODWILL Goodwill represents the excess of the cost over the net amount of the values assigned to the assets acquired and liabilities assumed when an enterprise is acquired. Goodwill, which is not amortized, is subject to an annual impairment test. Such tests are also performed if events have occurred or circumstances changed indicating it might not be recoverable. The impairment test compares the carrying amount and the fair value of the Partnership’s reporting units. If the carrying amount of a reporting unit is greater than its fair value, amortization of goodwill is measured on the basis of the excess of the carrying amount of goodwill over its fair value. The fair value of a reporting unit is calculated based on discounted cash flows or external valuations.

DEVELOPMENT ACTIVITIES The costs related to development activities are capitalized except in cases where Gaz Métro does not have reasonable assurance that these costs will be recovered in the future.

FOREIGN CURRENCY TRANSLATION Foreign currency monetary assets and liabilities of Canadian enterprises are translated at the rate of exchange prevailing at the balance sheet date. Foreign currency revenues and expenses are translated at the average rate prevailing during the fiscal year. Gains and losses arising from translation are included in the results for the current year.

The assets and liabilities of foreign subsidiaries that are self-sustaining with respect to financing and operations are translated into Canadian dollars at the rate of exchange prevailing at the balance sheet date. Revenues and expenses are translated at the average rate prevailing during the fiscal year. The resulting gains and losses are shown under “Other comprehensive income, cumulative” in consolidated Partners’ equity.

REVENUE RECOGNITION In general, operating revenues are recorded when the goods have been delivered or the services rendered. Attachment 2 CAPP 11 Page 51 of 92 GAZ MÉTRO 2007 Annual Report NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 49 LIVE BETTER WITH BLUE

However, as a significant portion of the activities are regulated, revenues may be recognized in accordance with underlying agreements approved by the various regulatory bodies even though such amounts do not correspond to the amounts billed. The differences between revenues recorded and revenues billed result in amounts receivable or payable that can be described as regulatory assets or liabilities.

INCOME TAXES Gaz Métro as well as its subsidiaries and joint ventures formed as limited partnerships do not show current income tax expense since under existing legislation, it is the Partners who are taxable.

On October 1, 2007, the Canadian Institute of Chartered Accountants (CICA) published new recommendations that require flow-through entities, like Gaz Métro, to recognize the impacts of amendments to the Income Tax Act that are substantively enacted. On June 22, 2007, the House of Commons adopted Bill C-52 implementing the proposed amendments to the Income Tax Act in the Minister of Finance’s Tax Fairness Plan tabled on October 31, 2006 and affecting certain income trusts and limited partnerships (flow-through entities). The application of these amendments as at September 30, 2007 results in the recording of a future income tax liability related to a joint venture whose activities do not meet the definition of “enterprise subject to rate regulation” within the meaning of the CICA Handbook (Handbook).

Subsidiaries and joint ventures formed as corporations use the tax liability method to record income taxes. Under this method, future income tax assets and liabilities are determined according to differences between the carrying amounts and the tax bases of assets and liabilities. They are measured by applying enacted or substantively enacted tax rates and laws at the date of the financial statements for the years in which the temporary differences are expected to reverse.

EMPLOYEE FUTURE BENEFITS The Quebec distribution activity recognizes the costs related to pension contributions and other post-employment benefits in income as the amounts are disbursed in accordance with actuarial valuations based on long-term assumptions with respect to the forecast return on the plan’s assets, salary increases and retirement age.

Gaz Métro’s subsidiaries and joint ventures record other post-employment benefits in accordance with the accounting practices prescribed by the CICA. The pension costs for defined contribution plans correspond to the amount of the contributions. The pension costs for defined benefit plans and other post-employment benefits are determined by actuarial calculation based on a projected benefit method prorated according to eligible years of service and are expensed as the services are rendered by the employees.

The assets of the pension plans are valued at fair value, which is based on present market values. The fair value method is used to calculate the expected return on the assets of the plans.

Actuarial gains and losses that exceed 10% of the maximum between the accrued benefit obligation and the fair value of the assets at the beginning of the period are amortized over the remaining estimated working career of the group of employees, which is 12 years for employees covered by the pension plan and 11 years for employees covered by other post-employment benefits. Actuarial gains and losses that are less than the 10% corridor are not amortized.

The past services cost arising from changes to the plans is amortized using the straight-line method over the remaining estimated working career of the group of employees at the date of the changes.

The transitional assets and liabilities recognized when the new accounting standards were adopted and applied prospectively are amortized using the straight-line method over 14 years, which corresponds to the remaining estimated working career of the group of employees that should receive benefits under the plans. Attachment 2 CAPP 11 Page 52 of 92 50 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 2007 Annual Report GAZ MÉTRO LIVE BETTER WITH BLUE

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING RELATIONSHIPS The Partnership uses derivative financial instruments to reduce or eliminate the risk inherent in certain transactions and identifiable balances that arise in the normal course of business. These inherent risks arise from fluctuations in natural gas and electricity prices, and interest and exchange rates. Accordingly, the Partnership uses derivative financial instruments to ensure that unfavourable variations in cash flows as a result of such transactions and balances are offset by fluctuations in the cash flows of the derivative financial instruments. The Partnership does not hold or use derivative financial instruments for speculative purposes.

The Partnership uses energy-related derivative financial instruments to manage its exposure to the volatility of natural gas and electricity prices. The prices paid are based on indices and therefore vary. The instruments used make it possible to fix, or define, the prices based on temporal, volumetric and financial limits approved by the Régie for the Quebec distribution activity, or by management, if necessary, in other cases. The gains or losses on these instruments are included in energy supply costs as these costs are recognized. In addition, in the case of the distribution utilities, these costs are reimbursed or recovered through the energy supply rate in accordance with the method approved by the Régie and the VPSB.

The Partnership uses interest rate swaps to fix interest rates on a portion of floating rate borrowings. This results in the periodic swap of interest payments without any swap of the notional amount on which the payments are based and are recorded as an adjustment of interest receivable on the hedged borrowing instrument. The corresponding amount of interest payable to or receivable from counterparties is periodically included as an adjustment of accrued interest.

The Partnership also uses futures and currency swaps to manage its exchange risk exposure with respect to certain foreign currency debts or to protect cash flows in a foreign currency other than the measurement currency. The gains and losses attributable to these financial instruments are deferred and recognized in income under the revenue and expense items relating to the corresponding positions covered for the hedge period of the items covered.

If the financial instruments acquired to hedge are cancelled before the date initially designated, the gain or loss is recognized as a deferred gain or loss and recognized over the same period as the item originally covered.

All derivative instruments are recorded at fair value and all gains and losses arising on revaluations are recognized in income, with the exception of gains or losses from those related to the distribution utilities, for which specific regulatory treatment applies (see Note 4) and except gains or losses on financial instruments designated as a hedge item.

To be recorded as a hedge item, a derivative instrument has to be designated as such and be effective. Since October 1, 2006 (see Note 3), these derivative instruments should always be recorded at fair value. However, if a derivative instrument does not meet either the designation criterion or the effectiveness criterion, any resulting realized or unrealized gains and losses are included in income. The Partnership applies hedge accounting to some of its financial instruments, mainly cash flow hedges.

UNIT OPTION PLAN Gaz Métro offers a unit option plan to named executives. The Partnership has been recording attributions using the fair value method whereby the compensation cost is measured at the date of attribution based on its fair value and is expensed over the period the options are acquired. Attachment 2 CAPP 11 Page 53 of 92 GAZ MÉTRO 2007 Annual Report NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 51 LIVE BETTER WITH BLUE

NET INCOME PER UNIT Net income per unit is calculated on the basis of the weighted average number of outstanding units. The treasury stock method is used to determine the dilutive effect of outstanding unit options.

3. ACCOUNTING CHANGES APPLIED IN 2007 A) FINANCIAL INSTRUMENTS – RECOGNITION, MEASUREMENT, DISCLOSURE AND PRESENTATION On October 1, 2006, the Partnership adopted the recommendations in the following Sections of the Handbook - Section 3855, Financial Instruments–Recognition and Measurement and Section 3861, Financial Instruments–Disclosure and Presentation. These new Sections of the Handbook contain, among other things, comprehensive standards for the recognition, measurement, presentation and disclosure for financial instruments. Retroactive adoption without restating prior years is required. As a result, a net liability of $15,600,000 was recognized with respect to the financial instruments in the balance sheet, as at October 1, 2006, with a corresponding adjustment to deferred charges recoverable from customers in accordance with specific regulatory treatment.

In short, these new rules: require an entity to record its financial assets and liabilities at fair value at each closing date, apart from exception; establish rules determining when a financial asset or liability should be recognized in the balance sheet; and establish specific standards for the recognition and presentation of transaction costs relating to long-term debt, as well as the subsequent expensing thereof.

The adoption of these standards requires classifying all of the Partnership’s financial assets and liabilities in categories for which clearly defined rules determine the standards to be applied. However, the rules may differ when a different regulatory treatment is applied. The Partnership made the following classifications: 1. Cash and cash equivalents, grants receivable, redemption value of life insurance policies and derivative financial instruments that are not hedges have been classified as “Assets or liabilities held for trading”. They are presented at their fair value and the gains/losses arising on the revaluation at the end of each period are included in consolidated income. 2. Derivative financial instruments that are designated as treasury hedges are presented at their fair value and the gains/ losses relating to the effective portion of the hedge arising from the revaluation at the end of each period are included in comprehensive income. 3. Receivables from customers are classified under “Loans and receivables”. They are normally valued at cost net of amortization, which was their fair value when recognized initially. 4. Bank borrowings, amounts to be returned to customers, accounts payable and accrued liabilities and long-term debt are classified under “Other financial liabilities”. They are initially presented at their fair value. Subsequent measurements are at cost, net of amortization, using the effective interest rate method. For the Partnership, that value corresponds to cost.

Transaction costs The transaction costs relating to the long-term debt of the regulated activities will continue to be presented as deferred charges and amortized on a straight-line basis, in accordance with the requirements of the regulatory bodies. In the absence of regulatory accounting for entities subject to rate regulation, these costs would have reduced long-term debt and been amortized using the effective interest rate method. Deferred charges and long-term debt would have been reduced by $9,604,000 as at September 30, 2007, and $9,577,000 as at September 30, 2006. The impact related to the use of a different expensing method is not significant.

The transaction costs with respect to instruments related to activities not subject to rate regulation and that will not be classified as held for trading are recognized as an adjustment of the cost of the underlying instrument in the balance sheet, when it is recognized and amortized in accordance with the effective interest rate method. Attachment 2 CAPP 11 Page 54 of 92 52 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 2007 Annual Report GAZ MÉTRO LIVE BETTER WITH BLUE

3. ACCOUNTING CHANGES (CONTINUED) APPLIED IN 2007 (CONTINUED) A) FINANCIAL INSTRUMENTS – RECOGNITION, MEASUREMENT, DISCLOSURE AND PRESENTATION (CONTINUED)

Embedded derivatives An embedded derivative is a component of a hybrid (combined) instrument or another contract that also includes a non- derivative host contract, with the effect that some of the cash flows of the combined instrument vary in a way similar to a stand-alone derivative.

The Handbook recommends that an embedded derivative be separated from the host contract and recognized at its fair value in the balance sheet if certain predetermined conditions are met. Gaz Metro has decided to recognize in its balance sheet all the embedded derivatives when applicable. This rule did not have any impact on the financial statements of Gaz Métro.

B) COMPREHENSIVE INCOME On October 1, 2006, the Partnership adopted Section 1530 of the Handbook, Comprehensive Income. The Section establishes standards for reporting and display of comprehensive income, which is the change in equity (net assets) of an enterprise during a period from certain factors that are beyond the owners’ control. The adoption of these recommendations resulted in a new “comprehensive income” statement.

C) HEDGES On October 1, 2006, the Partnership adopted Section 3865 of the Handbook, Hedges. This Section establishes standards for when and how hedge accounting may be applied. Hedging is an activity designed to modify an entity’s exposure to one or more risks. Hedge accounting modifies the normal basis for recognizing the gains, losses, revenues and expenses associated with a hedged item or a hedging item in an entity’s income statement. It ensures that counterbalancing gains, losses, revenues and expenses are recognized in the same period. The adoption of these recommendations did not have any impact on the financial statements of the Partnership.

D) EQUITY On October 1, 2006, the Partnership adopted Section 3251 of the Handbook, Equity. This section establishes standards for the presentation of equity and changes in equity during the reporting period. The adoption of these recommendations modified the presentation of consolidated Partners’ equity.

APPLIED IN 2006 E) DISCLOSURE BY ENTITIES SUBJECT TO RATE REGULATION In May 2005, the CICA issued new Accounting Guideline AcG-19, Disclosure by Entities Subject to Rate Regulation. AcG-19 provides guidance about certain aspects of the disclosure and presentation of information of entities providing services or products for which customer rates are established or approved by a regulator. The objective is to ensure that financial statement users are better informed about the nature and economic effects of all forms of rate regulation and the impact thereof on the entity’s financial statements. The Partnership adopted AcG-19 for the fiscal year ended September 30, 2006 (see Note 4).

APPLICABLE IN 2008 F) ACCOUNTING CHANGES In July 2006, the CICA modified Section 1506 of the Handbook, Accounting changes. The revised section, which applies to years beginning on or after January 1, 2007, establishes criteria for changing accounting policies, together with the accounting treatment and disclosure of changes in accounting policies, changes in accounting estimates and correction of errors. The Partnership does not expect the adoption of this standard will have an impact on its net income or consolidated Partners’ equity. Attachment 2 CAPP 11 Page 55 of 92 GAZ MÉTRO 2007 Annual Report NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 53 LIVE BETTER WITH BLUE

G) CAPITAL DISCLOSURES In December 2006, the CICA adopted Section 1535 of the Handbook, Capital disclosures, which applies to years beginning on or after October 1, 2007. This section establishes standards for disclosing information about an entity’s capital and how it is managed. The Partnership does not expect the adoption of this standard will have an impact on its net income or consolidated Partners’ equity.

H) FINANCIAL INSTRUMENTS – DISCLOSURES AND PRESENTATION In December 2006, the CICA adopted two new sections: Section 3862 of the Handbook, Financial instruments–disclosures and Section 3863 of the Handbook, Financial instruments–presentation. Together, these two sections replace Section 3861 and apply to years beginning on or after October 1, 2007. These Sections bring new requirements concerning disclosures, particularly regarding the documentation of risks. The Partnership does not expect the adoption of these standards will have an impact on its net income or consolidated Partners’ equity.

4. RATE REGULATION APPROVAL OF RATES Establishments regulated in Quebec Quebec distribution activity The activities of the Quebec distribution activity are regulated by the Act respecting the Régie de l’énergie. Rates are established primarily on a cost of service-based method, which allows the Partnership to set its revenues each year so as to recover the expenditures it expects to incur to serve its clientele and earn a reasonable base return on deemed Partners’ equity allocated to this activity. In addition, an incentive return can be earned for improving financial performance. The incentive return stems from a performance incentive mechanism that was implemented in October 2000 and subsequently modified, and that will expire in September 2012.

For regulatory purposes, cost of service includes deemed income and capital taxes. These deemed income and other taxes are computed as though Gaz Métro was a taxable Canadian corporation, notwithstanding the tax status and the tax rate of the Partners.

The Régie has established that the rate of return on the rate base is to be fixed using an “adjusted” capital structure of which Partners’ deemed equity is in the order of 46.0%, including 38.5% that is compensated as if it were common shares of a company and 7.5% as if it were preferred shares.

The authorized base rates of return for the year ending September 30, 2007 are 8.73% on Partners’ deemed common share equity and 5.45% on deemed preferred share equity compared to 8.95% and 5.30% respectively, the preceding year. An incentive return of 0.84% has also been authorized on Partners’ deemed common share equity based on anticipated productivity gains for the fiscal year compared to 0.38% the preceding year.

With respect to supply service, i.e. supplying natural gas, the Act respecting the Régie de l’énergie states that the distributor shall sell natural gas at its actual purchase cost.

Establishments regulated elsewhere in Canada TQM and Champion The main activity of TQM, in which Gaz Métro owns a 50.0% interest, and Champion, which is wholly-owned by Gaz Métro, is the transportation of natural gas. Their activities are regulated by the NEB with respect to revenue determination, tolls, construction and operations. Attachment 2 CAPP 11 Page 56 of 92 54 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 2007 Annual Report GAZ MÉTRO LIVE BETTER WITH BLUE

4. RATE REGULATION (CONTINUED) APPROVAL OF RATES (CONTINUED) Establishments regulated elsewhere in Canada (continued) TQM and Champion (continued)

The NEB approves the tolls based on the annual cost of service, which includes deemed income taxes and capital tax. A toll schedule based on the estimated cost of service is applied for the current year and the differences between estimated and actual cost of service are included in the tolls for the following year.

The rate of return on equity is based on the rate of return formula approved by the NEB and adopted during hearing RH-2-94 on the cost of capital of a number of pipeline companies. The deemed equity ratio is 30.0% of the rate base in the case of TQM and 46.0% in the case of Champion. TQM’s authorized return is 8.46% for its fiscal year ending December 31, 2007 compared to 8.88% for the preceding year. For Champion it is 8.73% for its fiscal year ending September 30, 2007, compared to 8.95% for the preceding year.

Establishments regulated in United States PNGTS PNGTS, in which Gaz Métro owns a 38.3% indirect interest, operates a gas pipeline in the northeastern United States. It is regulated by the FERC in accordance with the terms and conditions of the Natural Gas Act for the regulation of natural gas transportation tolls.

The objective of the FERC regulations is to ensure the proper recovery of expenditures in tolls that also include a reasonable base return on Partners’ equity. The last toll application submitted in October 2001 has been effective since April 1, 2002. The next application is expected to be effective as of April 1, 2008.

VGS and GMP VGS and GMP, two indirectly wholly-owned subsidiaries of Gaz Métro, are regulated by the VPSB. Their rates are established using a cost of service-based method, which enables them to fix their revenues so as to recover the expenditures they expect to incur to serve their clientele and earn a reasonable base return on deemed shareholder’s equity. Deemed shareholder’s equity was 55.0% and 63.6% of the rate base for the 2007 and 2006 fiscal years for VGS and 52.5% in 2007 for GMP. The allowed base rate of return, which is fixed by the VPSB, has been 10.5% since October 1, 2006 for VGS and is 10.25% for GMP since January 1, 2007.

A new rate agreement was approved by the VPSB on September 21, 2006 and came into force on October 1 of that year. It includes a quarterly natural gas price adjustment formula for VGS and the ability to submit an annual rate application for the other items, excluding gas costs. GMP has a similar quarterly adjustment mechanism for the price of electricity and has been allowed an annual rate adjustment for other items since February 1, 2007.

IMPACT OF RATE REGULATION ON CONSOLIDATED FINANCIAL STATEMENTS Because of rate regulation, the accounting policies adopted by the Partnership may differ from the policies that would normally be adopted by a non-regulated enterprise. Set out below is a description of these differences and their impact on the financial statements.

REVENUE RECOGNITION The impact of regulation is described under “Revenue Recognition” in Note 2 on Significant Accounting Policies.

PROPERTY, PLANT AND EQUIPMENT, AND AMORTIZATION The impact of rate regulation on the accounting treatment of these assets is described under “Property, Plant and Equipment” in Note 2. Attachment 2 CAPP 11 Page 57 of 92 GAZ MÉTRO 2007 Annual Report NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 55 LIVE BETTER WITH BLUE

If the accounting standards for entities subject to rate regulation were not used, the capitalized equity component of the return for certain construction projects, the corresponding income and the subsequent amortization of these items would not be recognized.

Realized gains and losses on the disposal of retired properties are, as prescribed by present regulations, recorded mainly as adjustments of accumulated amortization related to property, plant and equipment instead of being included directly in income.

In the absence of regulatory accounting for entities subject to rate regulation, the costs of retiring property, plant and equipment that are capable of being estimated would result in liabilities in the balance sheet. The offset would be recorded as an increase in the costs of property, plant and equipment. The Partnership records these liabilities as an increase of accumulated amortization as the amortization expense, which includes a retirement cost component, is recorded.

The Partnership is unable to make a reasonable estimate of the monetary impact of these practices on the value of property, plant and equipment, amortization expense or other accounts.

EMPLOYEE FUTURE BENEFITS The Quebec distribution activity expenses the costs of retirement and other post-employment benefits when they are disbursed in accordance with the method of recovering costs in rates. Further details about the impact of rate regulation on the accounting treatment of these items are provided under “Employee future benefits” in Notes 2 and 17.

In the absence of regulatory accounting for entities subject to rate regulation, the cost of defined pension plan benefits and other post-employment benefits would be determined by a projected benefit method prorated according to eligible years of service and expensed as the services are rendered by the employees. If this practice had been adopted, an additional pension plan and other post-employment benefit liability of $9,608,000 and $5,307,000 would have been presented in the balance sheet as at September 30, 2007 and 2006, and the costs recorded would have been $3,979,000 and $8,031,000 higher in 2007 and 2006 respectively. However, this amount would have been included in the rate application so as to recover such amount from customers, thereby eliminating the potential impact on income.

REGULATORY ASSETS AND LIABILITIES Regulatory assets represent the costs the Partnership expects to recover from its customers in future years through the rate setting process, as approved by the various regulatory bodies. Regulatory liabilities represent revenues the Partnership expects to return to its customers in future years through the rate setting process.

Regulatory assets and liabilities would not be recorded in the same manner if rates were not regulated. They arise from amounts that were not considered in the initial annual rate application, or that represent actual differences in revenues or costs from estimates initially presented when the application was filed. In accordance with the present regulatory framework, interest is generally accumulated on the account balances for regulatory deferrals and differences, which will be recovered through rates charged to customers in future.

Regulatory assets are included in the balance sheet under “Deferred charges” (see Note 9) and regulatory liabilities are included under “Accounts payable and accrued liabilities” and “Deferred credits” (see Note 13). Attachment 2 CAPP 11 Page 58 of 92 56 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 2007 Annual Report GAZ MÉTRO LIVE BETTER WITH BLUE

4. RATE REGULATION (CONTINUED) REGULATORY ASSETS AND LIABILITIES (CONTINUED)

The following table presents the net carrying amount of the regulatory assets and liabilities as at September 30, 2007 and 2006.

Years recovery or settlement expected 2007 2006

REGULATORY ASSETS (LIABILITIES)

Rate stabilization account related to temperature (a) 2008–2013 $ 54,633 $ 41,634 Rate stabilization account related to inventory variances (a) 2008–2009 $ 8,826 $ 8,247 Credits related to energy supply costs (b) 2008 $ (33,064) $ (60,351) Grants paid (c) 2008–2017 $ 106,834 $ 100,374 Expenses related to financial instruments (d) 2008–2016 $ 74,620 $ 38,545 Expenses related to Global Energy Efficiency Plan (e) 2008–2009 $ 7,261 $ 6,639 Pension funding regulatory assets (f) 2008–2019 $ 13,303 $– Customers’ share of overearnings (g) 2009 $ (22,715) $ (7,396) Reserve related to Energy Efficiency Fund (g) 2008–2011 $ (17,305) $ (16,092) a) To alleviate the unpredictable and uncontrollable impacts of certain events on its activities, the Régie has authorized the Quebec distribution activity to use various rate stabilization accounts. The unpredictable impacts for which the Régie authorizes stabilization accounts include mainly the impact of temperature fluctuations on revenues, as well as the impact on income of natural gas inventory variances during the year. The annual variations are amortized so as to be recovered in rates starting in the second subsequent year over periods of five years for temperature and over one year for inventory variances.

During the 2007 and 2006 fiscal years, revenues were increased respectively by $21,253,000 and $28,873,000 to offset the impacts of warmer temperatures than normal and amortization of deferred charges includes a charge of $8,254,000 in 2007 and of $13,656,000 in 2006 relating to normalized revenues of preceding fiscal years. Adjustments for inventory variances totalling $579,000 in 2007 and $8,247,000 in 2006 have been deferred to the 2009 and 2008 fiscal years respectively instead of being expensed immediately in the Statement of Income under “Direct costs”.

In the absence of regulatory accounting for entities subject to rate regulation, income for the 2007 fiscal year would have been affected by the utilization of a different approach for establishing rates. The impacts of a different approach are impossible to determine a priori. b) The impact of rate regulation on the accounting treatment of these assets is described under “Inventories” in Note 2. The expenses or credits related to energy costs (natural gas and electricity), are composed of offsets related to inventory revaluations and other adjustments to the cost of energy distributed that are necessary to eliminate the impacts from the sale of the commodity on income, as prescribed by the Régie and the VPSB. These amounts are then returned to or recovered from customers in the form of a rate adjustment, over a period of 3 months for electricity and over a period of 12 months for natural gas. In the absence of regulatory accounting for entities subject to rate regulation, a customer account receivable or account payable would have been recorded in the balance sheet in place of the deferred charges or credit balances because these costs are, by law, fully borne by customers who must ultimately pay for the costs incurred. In substance, these accounts only represent differences in billings to customers that are corrected within a maximum period of 12 months. Attachment 2 CAPP 11 Page 59 of 92 GAZ MÉTRO 2007 Annual Report NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 57 LIVE BETTER WITH BLUE

c) Grants paid are mainly amounts given to customers to convert their equipment to natural gas so they can sign a service contract with Gaz Métro. These amounts are deferred and then amortized over the periods covered by the contracts (generally five years) or longer (10 years) when the customers in question do not have the flexibility to switch to an alternative energy without making a substantial investment. In the absence of regulatory accounting, the amortization period for grants would always be matched to the periods covered by the underlying service contracts and an additional amortization of deferred charges of $6,106,000 in 2007 and $6,015,000 in 2006 would have been recorded and included in the rate application. d) Unrealized gains or losses on financial instruments represent the net impacts of revaluations of those instruments related to the distribution utilities. The financial instruments mature over nine years. Since October 1, 2006, derivative financial instruments have to be presented in the balance sheet at their fair value. In the absence of regulatory accounting for entities subject to rate regulation, the offset of these revaluations, which is presently included in deferred charges, should be recorded directly in the Statement of Income. If regulatory treatment had not been applied the Partnership would have modified its hedge strategies so that the change in fair value of the financial instruments related to this sector, which amount to $3,162,000 during the 2007 fiscal year, would not affect results. It is therefore impossible to determine what the impact would have been on results. e) The deferred charges related to the Global Energy Efficiency Plan are composed of the differences between the actual net impact on income and the amount projected at the beginning of the year in the rate application. These amounts are deferred and then completely amortized in the second fiscal year following the year they were incurred. If regulatory treatment had not been applied, these differences would have been included in income when incurred and no amortization expense would have been recorded. Net income for 2007 and 2006 would have been $622,000 and $3,120,000 lower respectively. f) VGS and GMP record previously unamortized net actuarial losses, unamortized past service costs and the remaining transitional obligation as a regulatory asset reflective of the recovery mechanism for pension and other post-employment benefits costs in the utility’s jurisdiction. g) The customers’ share of overearnings is composed of amounts relating to the Quebec distribution activity and GMP. Additional information about the Quebec distribution activity’s performance incentive mechanism is provided under “Results and Balance Sheet” in Note 16. Under that mechanism, the Régie requires the customers’ share of the overearnings to be returned to them, primarily in the form of rate reductions in the year following the approval of such overearnings. Part of the customers’ share of the overearnings is also transferred to a fund for energy efficiency projects. Customers’ share of GMP’s excess return is returned to them in the form of a rate reduction over 36 months after it is approved by the VPSB. These liabilities are recorded in the years they arise, as recommended by the CICA in the absence of regulatory accounting.

RISKS AND UNCERTAINTIES The risks and uncertainties related to the aforementioned regulatory assets and liabilities are periodically monitored and assessed. If the Partnership considered that certain amounts would probably not be recovered or returned through future rate adjustments, following interventions by the Régie that differ from the Partnership’s expectations, for example, the value of the underlying asset or liability would be consequently adjusted. Attachment 2 CAPP 11 Page 60 of 92 58 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 2007 Annual Report GAZ MÉTRO LIVE BETTER WITH BLUE

5. ACQUISITION OF A SUBSIDIARY On April 12, 2007, Gaz Métro, through its wholly-owned subsidiary, Northern New England Energy Corporation (NNEEC), acquired all of the issued and outstanding shares of GMP for a net consideration of $224,312,000 (US$195,470,000) including the related costs. As a result, GMP became a wholly-owned subsidiary of the Partnership. Gaz Métro recorded this acquisition using the purchase method and consolidates GMP’s results since April 12, 2007 in its Distribution Sector (Note 19). Gaz Métro arranged bridge financing and new long-term debt to conclude the transaction (Note 12).

The allocation of the purchase price based on the fair values of the assets acquired less the liabilities assumed by the Partnership is as follows:

2007

Assets acquired Trade and other receivables $ 34,177 Inventories and prepaid expenses 9,291 Deferred charges 45,542 Fixed assets 258,922 Investments 43,011 390,943 Liabilities assumed Bank borrowings 1,377 Accounts payable and accrued liabilities 59,237 Long-term debt 129,000 Future income taxes 34,842 Derivative financial instruments 23,634 248,090 Net value of assets acquired 142,853 Net consideration paid: Cash 225,212 Cash available in GMP on acquisition date (900) 224,312 Goodwill $ 81,459

6. TRADE AND OTHER RECEIVABLES TRANSFER OF RECEIVABLES The Partnership renegotiated an agreement that terminates on September 30, 2010 for the regular transfer of receivables to a securitization trust. Receivables transferred in excess of amounts received in cash represent the subordinated rights retained by the Partnership that are included in “Trade and other receivables” in the balance sheet.

The securitization trust has no recourse against the other assets of the Partnership in the event debtors fail to pay amounts owing when they become due. Gaz Métro retained responsibility for the management, administration and collection of the receivables sold. No asset or liability with respect to the management of the receivables has been recorded given that the monetary benefits that the Partnership derives in this regard are almost equal to the value of the services provided.

The expense recorded in respect of the sale of receivables is $1,675,000 in 2007 and $1,781,000 in 2006.

As at September 30, 2007 and 2006, the amount of the receivables transferred, net of the subordinated rights retained by the Partnership, amounts to $35,000,000, the maximum authorized being $85,000,000. Attachment 2 CAPP 11 Page 61 of 92 GAZ MÉTRO 2007 Annual Report NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 59 LIVE BETTER WITH BLUE

No net cash consideration received or paid relating to the transfers and sales of receivables has been presented as a change in “Trade and other receivables” in the consolidated Statement of Cash Flows in 2007. In 2006, the net cash consideration paid was $7,500,000.

7. PROPERTY, PLANT AND EQUIPMENT

2007 Average Accumulated Net book amortization rate Cost Amortization (b) value Storage 2.85% $ 163,258 $ 34,254 $ 129,004 Transportation 4.00% 762,441 465,838 296,603 Distribution 3.06% 2,538,444 943,335 1,595,109 General plant 9.75% 318,101 102,721 215,380 Production (a) 2.44% 56,955 11,873 45,082 3,839,199 1,558,021 2,281,178 Government grants 3.50% (452,964) (320,170) (132,794) $3,386,235 $1,237,851 $2,148,384

2006 Average Accumulated Net book amortization rate Cost Amortization value Storage 3.04% $ 148,927 $ 17,730 $ 131,197 Transportation 4.00% 731,154 438,170 292,984 Distribution 3.00% 2,334,684 869,556 1,465,128 General plant 8.56% 272,845 89,915 182,930 3,487,610 1,415,371 2,072,239 Government grants 3.50% (452,964) (304,294) (148,670) $ 3,034,646 $ 1,111,077 $ 1,923,569

Amortization is $112,519,000 in 2007 and $98,632,000 in 2006. a) Property, plant and equipment included under Production were acquired as part of the acquisition of GMP. b) A liability of $21,315,000 related to the cost of retiring property, plant and equipment of GMP is included in accumulated amortization in 2007.

8. INVESTMENTS AND OTHER

2007 2006

Interest in companies subject to significant influence PNGTS (38.3%) (a) $102,103 $118,743 Vermont Transco LLC (21.9%) (b) 18,461 – Vermont Electric Power Company, Inc. (29.2%) (b) 7,109 – Other (b) 2,753 – 130,426 118,743

Redemption value of life insurance policies (b), (c) 8,815 – Grants receivable in five equal payments up to 2012 4,717 5,490 Other (b) 649 – $144,607 $124,233 Attachment 2 CAPP 11 Page 62 of 92 60 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 2007 Annual Report GAZ MÉTRO LIVE BETTER WITH BLUE

8. INVESTMENTS AND OTHER (CONTINUED) a) The investment in PNGTS has been pledged as security for a preferred note of $213,648,000 (US$214,765,000) of this company. b) Investments owned through GMP, which was acquired on April 12, 2007. c) These are life insurance policies on the lives of active and retired officers of GMP.

9. DEFERRED CHARGES

2007 2006

Rate stabilization account related to temperature $ 54,633 $ 41,634 Rate stabilization account related to inventory variances 8,826 8,247 Development of information technology 52,902 60,420 Financing costs 9,604 9,577 Grants paid 106,834 100,374 Expenses related to financial instruments (Note 21) 74,620 38,545 Expenses related to Global Energy Efficiency Plan 7,261 6,639 Pension funding regulatory asset 13,303 – Other 12,395 6,394 $340,378 $271,830

Amortization of deferred charges is $42,387,000 in 2007 and $37,860,000 in 2006 and the amortization of financing costs included in interest on long-term debt is $4,338,000 in 2007 and $3,734,000 in 2006. The reduction in deferred charges related to energy supply costs, including natural gas transportation and storage, is $57,980,000 in 2007 and $54,474,000 in 2006.

10. INTEREST IN JOINT VENTURES

2007 2006

TQM 50.0% 50.0% TQM Services, Inc. 50.0% 50.0% Rabaska Limited Partnership (Rabaska) 33.3% 33.3% CDH Solutions & Opérations Inc. (CDH) (a) 50.0% 50.0% MTO Télécom Inc. (1) 49.8% 49.8% Intragaz group 40.0 to 60.0% 40.0 to 60.0% HydroSolution, L.P. 51.0% 51.0%

(1) Representing 48.8% of the Company’s participating shares Attachment 2 CAPP 11 Page 63 of 92 GAZ MÉTRO 2007 Annual Report NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 61 LIVE BETTER WITH BLUE

Gaz Métro’s share of the consolidated financial statement components of the joint ventures is as follows:

2007 2006

INCOME Revenues $ 75,423 $ 76,447 Expenses 53,497 57,495 Net income $ 21,926 $ 18,952

BALANCE SHEET Current assets $ 38,935 $ 39,961 Long-term assets 410,566 418,775 Current liabilities (4,642) (19,641) Long-term liabilities (229,104) (221,078) Net assets $ 215,755 $ 218,017

CASH FLOWS RELATED TO: Operating activities $ 36,329 $ 34,424 Investing activities (13,127) (32,837) Financing activities (22,350) 13,000 Increase in cash and cash equivalents $ 852 $ 14,587 a) On February 14, 2006, the Partnership transferred the units it owned in Climatisation et Chauffage Urbains de Montréal s.e.c. (CCUM) to a newly formed joint venture, CDH, jointly controlled by the Partnership and a new partner, for cash. Since that date, Gaz Métro, therefore, exercises joint control over CCUM’s activities and uses the proportionate consolidation method to account for its investment interest.

The share of the assets and liabilities of CCUM transferred and reflected in the Partnership’s balance sheet is as follows:

2006

Current assets $ 2,583 Long-term assets (including goodwill of $1,149,000) 10,488 13,071 Current liabilities (1,560) Long-term liabilities (3,736) (5,296) Net value of assets transferred 7,775 Net consideration 13,873 Deferred gain on transfer included in “Deferred credits” in balance sheet (i) $ 6,098 Net consideration: Cash $13,005 Share of bank overdraft transferred on disposition 868 $13,873

(i) The Partnership did not include the $6,098,000 gain on the transfer in income when the units were transferred because the cash consideration remained in the newly formed joint venture. The gain has been deferred and is amortized over the estimated remaining life of the transferred assets or taken into income on a pro rata basis as the cash consideration for the transfer is received by the Partnership. As at September 30, 2007, a gain of $2,002,000 has been included in income. Attachment 2 CAPP 11 Page 64 of 92 62 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 2007 Annual Report GAZ MÉTRO LIVE BETTER WITH BLUE

11. BANK BORROWINGS

Maximum authorized Interest Year of amounts rate maturity 2007 2006

GAZ MÉTRO (a) (4.50% in 2006) $100,000 4.90% 2008 $15,500 $20,000 GMP (a), (b) 30,341 6.01% 2008 2,125 – VGS (a), (c), (d) (5.26% in 2006) 29,844 5.67% 2008 23,180 17,101 TQM (a) 2,500 –% 2008 – – OTHER (6.00% in 2006) 5,944 –% 2008 – 33 $168,629 $40,805 $37,134 a) The borrowings are unsecured. b) The maximum authorized amount under the short-term credit facilities of GMP, a wholly-owned subsidiary of NNEEC, which is in turn wholly-owned by Gaz Métro, is US$30,500,000. c) An interest rate swap covering an average borrowing of $9,836,000 (US$9,888,000) fixes the rate at 4.86% until October1,2008. d) The maximum authorized amount under the short-term credit facilities of VGS, a wholly-owned subsidiary of NNEEC, which is in turn wholly-owned by Gaz Métro, is US$30,000,000.

Under the terms of the various short-term credit facilities, the Partnership and certain of its subsidiaries and joint ventures have to comply with certain covenants concerning financial ratios or other conditions at all times. Attachment 2 CAPP 11 Page 65 of 92 GAZ MÉTRO 2007 Annual Report NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 63 LIVE BETTER WITH BLUE

12. LONG-TERM DEBT

Interest rate Year of maturity 2007 2006

GAZ MÉTRO (a) First mortgage bonds Series 10.75% 2007 $–$ 75,000 Series “D” (b) 10.45% 2017 125,000 125,000 Series “E” (b) 9.00% 2025 100,000 100,000 Series “F” (b) 7.20% 2028 50,000 50,000 Series “H” (b) 6.05% 2009 100,000 100,000 Series “H” (b) 6.95% 2010 100,000 100,000 Series “I” (b) 7.05% 2031 125,000 125,000 Series “I” (b) 6.30% 2034 125,000 125,000 Series “J” (b) 5.45% 2021 150,000 150,000 Series “J” (b) 5.70% 2036 150,000 150,000 1,025,000 1,100,000 Term loans 2009 (5.05% in 2006) (c) 5.25% and 2012 160,059 38,736 Other (4.79% in 2006) 5.00% 2008 311 1,292 1,185,370 1,140,028 NNEEC

Unsecured senior notes (d) Series “A” (US$50,000) 5.93% 2017 49,740 – Series “B” (US$50,000) 6.12% 2022 49,740 – 99,480 – VGS Unsecured preferred notes 2028 (US$20,000) 7.03% and 2036 19,896 22,354 GMP

First mortgage bonds (e) Series 6.04% (US$42,000) 6.04% 2018 41,782 – Series 6.70% (US$15,000) 6.70% 2019 14,922 – Series 9.64% (US$9,000) 9.64% 2020 8,953 – Series 8.65% (US$13,000) 8.65% 2022 12,932 – Series 6.53% (US$30,000) 6.53% 2036 29,844 – 108,433 – Other 2017 3,209 – 111,642 – TQM

Bonds (f) Series “H” 6.50% 2009 50,000 50,000 Series “I” 7.05% 2010 50,000 50,000 Series “J” 3.91% 2010 37,500 37,500 137,500 137,500 Term loan (4.80% in 2006) (g) 4.72% 2011 28,250 32,100 165,750 169,600 OTHER Non-recourse term loan 2008 and other (5.61% in 2006) (h) 5.77% to 2017 71,462 63,837 1,653,600 1,395,819 CURRENT PORTIONS 9,446 80,964 $1,644,154 $1,314,855 Attachment 2 CAPP 11 Page 66 of 92 64 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 2007 Annual Report GAZ MÉTRO LIVE BETTER WITH BLUE

12. LONG-TERM DEBT (CONTINUED)

ANNUAL CAPITAL REPAYMENTS: Annual capital repayments required during the next five years to meet maturities and sinking fund requirements, excluding redemptions before maturity at the Partnership’s option, are:

2008: $9,446,000 2009: $233,309,000 2010: $228,241,000 2011: $35,620,000 2012: $78,553,000 a) The first mortgage bonds and the authorized $400,000,000 term loan are secured under a trust deed which contains an hypothec on the universality of movable and immovable property, present and future, of Gaz Métro situated in the province of Quebec. The creditors are also covered by a first immovable hypothec on the Partnership’s present and future pipelines and gas system. b) Gaz Métro’s first mortgage bonds are retractable at its option at the greater of their face value or market value. c) On December 21, 2004, the Partnership, through its General Partner, signed a Credit Agreement providing a credit facility of $400,000,000. Every year, subject to the approval of the lenders, the maturity can be extended for one year. The maturity is now December 21, 2011. A portion of this term loan is in U.S. dollars, i.e. $25,865,000 (US$26,000,000) as at September 30, 2007 and $29,060,000 (US$26,000,000) as at September 30, 2006.

On April 10, 2007, the Partnership executed a bridge financing agreement under which it used US$100,000,000 and the equivalent of US$78,000,000 (which represented $89,509,000 at that time) in connection with the acquisition of GMP. On June 19, 2007, US$100,000,000 was repaid. Most of the balance of $89,509,000 as at September 30, 2007 matures on October 9, 2008. d) On June 19, 2007, NNEEC issued two series of unsecured senior notes to a consortium of investors, in connection with the acquisition of GMP. e) Substantially all of the property of GMP is subject to the lien of indenture under which the first mortgage bonds were issued. f) There are no hypothecs on the series of bonds. g) TQM’s term loan, originally obtained for the extension of its gas pipeline system, was refinanced for a five-year period until September 22, 2011 and is unsecured. The Partnership’s interest in the authorized amount of this loan is $42,750,000 as at September 30, 2007 and 2006. h) Gaz Métro’s other subsidiaries and joint ventures can borrow up to $88,919,000 under term loan agreements, secured by first ranking hypothecs. The term loans are composed of bankers’ acceptances. As at September 30, 2007, interest rate swaps concluded by certain subsidiaries and joint ventures cover the period up to February 21, 2011 and fix the interest rate on a nominal amount of $28,128,000.

As at September 30, 2007 and 2006, interests in non-regulated activities, both related and unrelated to the energy sector, owned by Gaz Métro represent 3.5% and 3.2% respectively, of its total non-consolidated assets. Of these investments, 1.1% of its total non-consolidated assets as at September 30, 2007 and 2006 relates to non-regulated activities that are unrelated to the energy sector. GMi and Gaz Métro have jointly undertaken, pursuant to its trust deeds, not to increase Gaz Métro’s interests in non-regulated activities above 10% of Gaz Métro’s total non-consolidated assets, or above 5% in the case of non-regulated activities that are not related to the energy sector.

As at September 30, 2007 and 2006, interest coverage on consolidated long-term debt is respectively 2.53 times and 2.75 times. Attachment 2 CAPP 11 Page 67 of 92 GAZ MÉTRO 2007 Annual Report NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 65 LIVE BETTER WITH BLUE

13. DEFERRED CREDITS

2007 2006

Credits related to energy supply costs $33,064 $60,351 Customers’ share of overearnings 22,715 7,396 Gain on transfer (Note 10a)) 4,096 6,098 $59,875 $73,845

14. PARTNERS’ EQUITY AUTHORIZED Unlimited number of units; each ranks equally with any other unit and is entitled to the same rights, privileges and obligations.

ISSUED AND FULLY PAID

2007 2006

Number of units as at September 30 (in thousands of units) 120,437 117,509

As at September 30, 2007 and 2006, Consolidated Partners’ Equity includes 120,437,400 units and 117,509,139 units issued for $1,011,737,000 and $961,650,000 respectively. a) In 2007, Gaz Métro issued 14,508 units at $15.04 per unit under the unit option plan for a cash consideration of $218,000. During the 2006 year, 4,000 units were issued at $15.04 per unit for a cash consideration of $60,000. b) On October 10, 2006, the Partnership issued 2,913,753 units to one of the ultimate beneficiaries of its General Partner, at a price of $17.16 per unit, for a net consideration of $49,869,000. c) The agreements relating to the various long-term debt trust deeds provide that Gaz Métro will not make a distribution to its Partners if, taking the distribution into account, long-term debt would exceed 75% of total capitalization. The agreements also provide that the Partnership will not issue any new long-term debt if such debt would increase the long- term debt ratio to more than 65% of total Partnership’s capitalization, on a non-consolidated financial statements basis.

UNIT OPTION PLAN The Partnership has reserved 1,000,000 units for a unit option plan for named executives. During the year, 14,508 options (Note 14a)) were exercised (4,000 in 2006) and 11,754 options were granted (34,666 in 2006). Options cannot be exercised before the first anniversary of a grant unless the Board of Directors determines otherwise when an option is granted. Options can be exercised at a cumulative rate of 25% on each of the anniversaries of the grant. Options expire seven years after the grant date. Attachment 2 CAPP 11 Page 68 of 92 66 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 2007 Annual Report GAZ MÉTRO LIVE BETTER WITH BLUE

14. PARTNERS’ EQUITY (CONTINUED) UNIT OPTION PLAN (CONTINUED)

As at September 30, 2007 and 2006 respectively, there were 92,111 options and 94,865 options outstanding at a weighted average exercise price of $16.17 and $15.94. The remaining weighted average contract term is 3.5 years as at September 30, 2007 and 3.6 years as at September 30, 2006. During the 2007 and 2006 fiscal years, no options were cancelled in respect of employees who left.

Of the total outstanding options, 52,310 options and 56,103 options could be exercised as at September 30, 2007 and 2006 respectively at a weighted average exercise option price of $16.02 and $15.64.

15. CASH FLOWS a) Change in non-cash working capital items:

2007 2006

Trade and other receivables $ 12,010 $(17,978) Inventories 44,339 36,920 Prepaid expenses 959 (430) Accounts payable and accrued liabilities (7,012) (4,783) Income taxes (1,424) (1,603) $ 48,872 $ 12,126 b) Other information:

2007 2006

Interest received $ 12,130 $ 15,879 Interest paid $104,398 $ 90,317 Income taxes paid $ 5,361 $–

16. RESULTS AND BALANCE SHEET The incentive return of $11,548,000 for the Quebec distribution activity in 2007 includes a $3,240,000 share in the return in excess of the return authorized by the Régie. Overearnings of $12,959,000 were generated for the fiscal year ended September 30, 2007. In accordance with the sharing arrangement established in Decision D-2004-51 with respect to the performance incentive mechanism, the distributor included its $3,240,000 share of the incentive return in revenues. The amount of the incentive return is subject to the final approval of the Régie based on its review of the regulatory report that should be submitted in December 2007. Of the balance of the overearnings, $7,449,000 was included in “Deferred credits” and will be returned to customers in the form of a rate reduction in the 2009 fiscal year, and $2,270,000 was contributed to the Energy Efficiency Fund.

The incentive return was $6,768,000 in 2006, including a $3,213,000 share in the return in excess of the return authorized by the Régie. Attachment 2 CAPP 11 Page 69 of 92 GAZ MÉTRO 2007 Annual Report NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 67 LIVE BETTER WITH BLUE

Following the review of the regulatory report for the fiscal year ended September 30, 2006, the Régie approved the overearnings calculation of $12,852,000 and authorized the distributor to retain $3,213,000 as a performance incentive, which was included in income for the 2006 year. Of the balance, $7,396,000 has been included in deferred credits and $2,243,000 was contributed to the Energy Efficiency Fund.

17. EMPLOYEE FUTURE BENEFITS The Partnership maintains defined benefit and defined contribution pension plans that cover virtually all of its employees. The defined benefit plans are funded, which ensures that employees will receive a pension determined according to length of service and salaries during their highest earning years. For defined contribution pension plans, employer contributions are based on employees’ contributions.

The effective dates of the most recent actuarial valuations and the next required actuarial valuations for purposes of funding the funded plans are as follows:

Date of most recent Date of next required actuarial valuation actuarial valuation

Gaz Métro-Quebec distribution activity December 31, 2006 December 31, 2009 Gaz Métro Plus Limited Partnership December 31, 2006 December 31, 2009 TQM December 31, 2006 December 31, 2007 VGS January 1, 2007 January 1, 2008 GMP December 31, 2006 December 31, 2007

The Partnership also provides post-employment benefits other than pensions, including supplementary health care and life insurance, for virtually all of its employees, their spouses and qualified dependants. These benefits are not funded, except in the case of GMP.

The following tables describe the Partnership’s employee future benefits-related obligations and costs in accordance with the standards in Section 3461 of the Handbook as well as the impact of the unrecorded transitional obligations of the Quebec distribution activity. The measurement date is June 30, except for VGS, GMP and TQM for which the measurement date is September 30. Attachment 2 CAPP 11 Page 70 of 92 68 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 2007 Annual Report GAZ MÉTRO LIVE BETTER WITH BLUE

17. EMPLOYEE FUTURE BENEFITS (CONTINUED)

COMPONENTS OF ACCRUED BENEFIT ASSET (OBLIGATION)

2007 2006 2007 2006

Other post- Other post- Pension Pension employment employment plans plans benefits benefits

ACCRUED BENEFIT OBLIGATION BALANCE, BEGINNING OF YEAR $347,354 $369,561 $ 49,414 $ 50,258 Current service cost 12,204 12,693 2,049 1,997 Interest cost 22,410 19,606 3,587 2,700 Employee contributions 2,370 2,240 100 – Other contributions and employee transfers 2,101 1,479 – – Benefits paid (17,212) (15,035) (2,279) (1,560) Plan amendments 2,678 – 176 – Actuarial losses (gains) 23,411 (39,017) 3,612 (3,981) Acquisition of a subsidiary (Note 5) 52,367 – 21,259 – Impact of share of transferred assets and liabilities of CCUM – (3,742) – – Foreign exchange variations (8,315) (431) (2,818) – BALANCE AS AT MEASUREMENT DATE 439,368 347,354 75,100 49,414

PLAN ASSETS AT FAIR VALUE BALANCE, BEGINNING OF YEAR 331,929 310,570 – – Actual return on plan assets 46,108 26,409 370 – Employer contributions 10,439 9,368 1,657 1,560 Employee contributions 2,370 2,240 – – Other contributions and employee transfers 2,101 1,479 – – Benefits paid (17,212) (15,035) (1,728) (1,560) Acquisition of a subsidiary (Note 5) 43,835 – 15,802 – Impact of share of transferred assets and liabilities of CCUM – (2,823) – – Foreign exchange variations (7,047) (279) (2,125) – BALANCE AS AT MEASUREMENT DATE 412,523 331,929 13,976 –

DEFICIENCY OF ASSETS VERSUS OBLIGATIONS (26,845) (15,425) (61,124) (49,414) Unamortized past service costs 16,554 15,865 – – Unamortized net actuarial losses 50,818 53,412 15,249 11,739 Unamortized transitional obligation (asset) (40,535) (46,295) 11,079 12,928

ACCRUED BENEFIT ASSET (OBLIGATION) AS AT MEASUREMENT DATE (8) 7,557 (34,796) (24,747) Employer contributions between measurement date and year-end 1,536 2,111 439 416 ACCRUED BENEFIT ASSET (OBLIGATION) END OF YEAR $ 1,528 $ 9,668 $(34,357) $(24,331) Representing: Unrecognized accrued benefit asset (obligation) of Quebec distribution activity $ 17,752 $ 17,124 $(27,360) $(22,431) Accrued benefit obligation recognized and included in accounts payable and accrued liabilities (16,224) (7,456) (6,997) (1,900) $ 1,528 $ 9,668 $(34,357) $(24,331) Attachment 2 CAPP 11 Page 71 of 92 GAZ MÉTRO 2007 Annual Report NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 69 LIVE BETTER WITH BLUE

The following table shows the allocation of the pension plans assets at the measurement date:

2007 2006

ASSET CATEGORIES Fixed income securities 38.3% 40.2% Equity securities 61.7% 59.8% 100.0% 100.0%

COMPONENTS OF GAZ MÉTRO’S DEFINED BENEFIT COST FOR THE 12-MONTH PERIOD ENDED AT THE MEASUREMENT DATE

2007 2006 2007 2006

Other post- Other post- Pension Pension employment employment plans plans benefits benefits

Current service cost $ 12,204 $ 12,693 $ 2,049 $ 1,997 Interest cost 22,410 19,606 3,587 2,700 Actual return on plan assets (46,108) (26,409) (370) – Actuarial losses (gains) 23,411 (39,017) 3,612 (3,981) Plan amendments 2,678 – 176 – Cost (revenue) before adjustments to recognize the long-term nature of employee future benefits 14,595 (33,127) 9,054 716 Difference between expected return and actual return on plan assets for period 22,178 5,575 (178) – Difference between actuarial losses (gains) recognized for period and actual actuarial losses on accrued benefit obligation for period (21,706) 44,738 (2,890) 4,814 Difference between amortization of past service costs for period and plan amendments for period (672) 1,894 (283) – Amortization of transitional obligation (asset) (5,760) (5,770) 2,015 1,852 Defined benefit cost $ 8,635 $ 13,310 $ 7,718 $ 7,382 Representing: Unrecognized cost (revenue) of Gaz Métro-Quebec Distribution $ (1,503) $ 2,324 $ 5,482 $ 5,707 Recognized cost 10,138 10,986 2,236 1,675 $ 8,635 $ 13,310 $ 7,718 $ 7,382

The Quebec distribution activity’s defined benefits cost recognized for pension plans is $8,111,000 in 2007 and $9,291,000 in 2006 and, for other post-employment benefits, is $1,641,000 in 2007 and $1,370,000 in 2006.

The cost recognized for defined contribution and other pension plans is $794,000 in 2007 and $374,000 in 2006. Attachment 2 CAPP 11 Page 72 of 92 70 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 2007 Annual Report GAZ MÉTRO LIVE BETTER WITH BLUE

17. EMPLOYEE FUTURE BENEFITS (CONTINUED)

MAIN ACTUARIAL ASSUMPTIONS

2007 2006 2007 2006

Other post- Other post- Pension Pension employment employment plans plans benefits benefits

ACCRUED BENEFIT OBLIGATION RECOGNIZED AT THE MEASUREMENT DATE Discount rate 5.50% 6.00% 5.50% 6.00% Rate of compensation increase 3.50% 3.50% 3.50% 3.50% BENEFIT COSTS FOR 12-MONTH PERIOD ENDED AT THE MEASUREMENT DATE Discount rate 6.00% 5.25% 6.00% 5.25% Expected long-term rate of return on plan assets 6.75% 6.75% 8.00% –% Rate of compensation increase 3.50% 3.50% 3.50% 3.50%

The assumed health care cost trend rate used to project costs for the 2008 fiscal year is 8.50% and is decreasing gradually to 5.00% in 2014 and remaining at that level thereafter. A 1% change in assumed health care cost trend rates would have the following effects:

1% increase 1% decrease

SENSITIVITY ANALYSIS OF OTHER POST-EMPLOYMENT BENEFITS Effect on current service and interest costs $ 875 $ (696) Effect on accrued benefit obligation $8,291 $(6,753)

CASH PAYMENTS Total cash payments for employee future benefits are $12,777,000 in 2007 and $11,257,000 in 2006 consisting of cash contributed by Gaz Métro to its funded pension plans, cash payments in respect of other post-employment benefits and cash contributed to its defined contribution and other pension plans. Attachment 2 CAPP 11 Page 73 of 92 GAZ MÉTRO 2007 Annual Report NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 71 LIVE BETTER WITH BLUE

18. INCOME TAXES GEOGRAPHIC BREAKDOWN

2007 2006

Income before income taxes Canada $135,467 $130,750 United States 19,852 28,351 $155,319 $159,101 Current income taxes Canada $ 536 $ 290 United States 3,402 – $ 3,938 $ 290 Future income taxes Canada $ 24,977 $32 United States 3,563 11,572 $ 28,540 $ 11,604 Total current and future income taxes Canada $ 25,513 $ 322 United States 6,965 11,572 $ 32,478 $ 11,894

RECONCILIATION OF INCOME TAX RATES

2007 2006

Income before income taxes $155,319 $159,101 Income from limited partnerships (1) 131,777 129,312 23,542 29,789 Combined statutory tax rate 32.0% 30.7% Income taxes at statutory rate 7,533 9,145 Add: Higher tax rate in United States 1,588 2,637 Impact of EIC-167 (2) 26,192 – Net impact of non-deductible and other items (2,835) 112 Income taxes $ 32,478 $ 11,894 Effective tax rate (3) 137.96% 39.93%

(1) Includes Gaz Métro Limited Partnership, Gaz Métro Plus Limited Partnership, CDH Solutions & Operations Limited Partnership, Servitech, L.P., Sogener L.P., TQM Pipeline and Company, Limited Partnership, Gaz Métro Plus Finance Limited Partnership, Rabaska Limited Partnership, Intragas, L.P., Intragas Exploration, Intragas Energy, Intragas Holding and HydroSolution, L.P. (2) On October 1, 2007, the CICA published new recommendations that require flow-through entities, like Gaz Métro, to recognize the impacts of amendments to the Income Tax Act that are substantively enacted. On June 22, 2007, the House of Commons adopted Bill C-52 implementing the proposed amendments to the Income Tax Act in the Minister of Finance’s Tax Fairness Plan tabled on October 31, 2006 and affecting certain income trusts and limited partnerships (flow-through entities). The application of these amendments as at September 30, 2007 results in the recording of a future income taxes liability of $26,192,000 related to a joint venture whose activities do not meet the definition of “enterprise subject to rate regulation” within the meaning of the Handbook. (3) Excluding the portion of the various limited partnerships’ income. Attachment 2 CAPP 11 Page 74 of 92 72 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 2007 Annual Report GAZ MÉTRO LIVE BETTER WITH BLUE

18. INCOME TAXES (CONTINUED)

FUTURE INCOME TAXES

2007 2006

Future income tax liabilities (assets): Differences between accounting and tax amortization on property, plant and equipment and other assets Canadian companies $ (1,913) $ (106) Canadian limited partnerships 26,192 – U.S. companies 84,342 51,935 $108,621 $ 51,829

In computing the taxable income allocated to the Partners, the Partnership has claimed capital cost allowance and certain other deductions relating to deferred charges that reduce the income allocation to the Partners, thereby deferring to future years income taxes otherwise payable by them.

Future income taxes, relating to the activities carried on by the various limited partnerships in the group and calculated in accordance with the tax liability method in Section 3465 of the Handbook are $139,607,000 as at September 30, 2007 and $142,332,000 as at September 30, 2006. Under this method, future income taxes are determined based on the differences between the accounting and tax bases of assets and liabilities. The future income tax assets and liabilities are calculated at the tax rate for a taxable Canadian corporation that should be in effect during the year in which the temporary differences should be realized or settled. The decrease during the fiscal year ended September 30, 2007 can be explained primarily by the reduction in the substantially enacted tax rate and a net reversal of temporary differences, which reduced the liability by $2,353,000 and by $372,000 respectively.

19. SEGMENTED INFORMATION The business sectors presented are segmented in line with the way management organizes the various segments within the Partnership for purposes of operational decision-making and performance assessment.

The Partnership has the four following reportable segments: DISTRIBUTION: Delivers natural gas and electricity to users; TRANSPORTATION: Transports natural gas, generally from the producers to the distributors; STORAGE: Stores natural gas; ENERGY SERVICES AND OTHER: Includes non-regulated activities of energy and technology services, sale, leasing, maintenance of gas appliances, water and waste water systems diagnoses and repairs, fibre optics and leasing of water heaters.

The accounting policies for these segments are the same as those described in Note 2.

The Partnership records inter-segment sales and transfers as though they were made to a third party, i.e. at market value. Attachment 2 CAPP 11 Page 75 of 92 GAZ MÉTRO 2007 Annual Report NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 73 LIVE BETTER WITH BLUE

2007 Energy Non-allocated services expenses and Distribution Transportation Storage and Other eliminations Total

VGS and QDA GMP Total (a)

Customer revenues $1,580,872 $ 247,489 $1,828,361 $ 40,278 $ 1,071 $ 84,522 $ – $1,954,232 Inter-segment revenues 317 – 317 539 11,963 5,348 (18,167) – Interest income (b) 3,237 – 3,237 – – – – 3,237 Total revenues 1,584,426 247,489 1,831,915 40,817 13,034 89,870 (18,167) 1,957,469 Direct costs 1,111,093 187,251 1,298,344 – – 53,415 (17,908) 1,333,851 Gross margin 473,333 60,238 533,571 40,817 13,034 36,455 (259) 623,618 Operations and maintenance expenses 161,989 25,807 187,796 7,879 3,062 17,900 4,027 220,664 Earnings before interest, taxes and amortization (EBITA) 311,344 34,431 345,775 32,938 9,972 18,555 (4,286) 402,954 Amortization 121,355 13,418 134,773 11,869 2,120 6,613 (c) – 155,375 Interest and other financial expenses 69,091 14,362 83,453 14,862 4,585 4,834 – 107,734 Share of income of companies subject to significant influence – (2,347) (2,347) (13,024) – (103) – (15,474) Income taxes – 4,364 4,364 5,233 26,277 (810) (2,586) 32,478 Net income (loss) $ 120,898 $ 4,634 $ 125,532 $ 13,998 $ (23,010) $ 8,021 $ (1,700) $ 122,841

Assets $1,969,303 $ 551,113 $2,520,416 $353,485 $127,686 $148,635 $ (7,762) $3,142,460

Additions to Property, plant and equipment $85,407 $ 25,454 $ 110,861 $ 2,629 $ 326 $ 10,977 $ – $ 124,793 Deferred charges 102,612 110 102,722 4,433 – 1,708 – 108,863 $ 188,019 $ 25,564 $ 213,583 $ 7,062 $ 326 $ 12,685 $ – $ 233,656

Goodwill Balance, beginning $–$6,640 $ 6,640 $ 7,596 $ – $ 28,811 $ – $ 43,047 Translation adjustment and other – (11,574) (11,574) – – 269 – (11,305) Acquisition of a subsidiary (Note 5) – 81,459 81,459 – – – – 81,459 Balance, end $–$76,525 $ 76,525 $ 7,596 $ – $ 29,080 $ – $ 113,201 Attachment 2 CAPP 11 Page 76 of 92 74 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 2007 Annual Report GAZ MÉTRO LIVE BETTER WITH BLUE

19. SEGMENTED INFORMATION (CONTINUED) 2006

Energy Non-allocated services expenses and Distribution Transportation Storage and Other eliminations Total

VGS and QDA GMP Total (a)

Customer revenues $1,777,541 $ 108,037 $1,885,578 $ 43,042 $ 2,932 $ 69,606 $ – $2,001,158 Inter-segment revenues 754 – 754 828 12,887 5,829 (20,298) – Interest income (b) 2,608 – 2,608 – – – – 2,608 Total revenues 1,780,903 108,037 1,888,940 43,870 15,819 75,435 (20,298) 2,003,766 Direct costs 1,329,402 74,328 1,403,730 – – 43,121 (19,396) 1,427,455 Gross margin 451,501 33,709 485,210 43,870 15,819 32,314 (902) 576,311 Operations and maintenance expenses 155,304 12,766 168,070 9,227 4,064 16,748 8,746 206,855 Earnings before interest, taxes and amortization (EBITA) 296,197 20,943 317,140 34,643 11,755 15,566 (9,648) 369,456 Amortization 111,111 5,651 116,762 11,422 2,085 7,460 (c) – 137,729 Interest and other financial expenses 67,966 4,935 72,901 13,526 4,035 4,270 – 94,732 Share of income of companies subject to significant influence – – – (21,931) – (175) – (22,106) Income taxes – 4,367 4,367 9,316 – 269 (2,058) 11,894 Net income (loss) $ 117,120 $ 5,990 $ 123,110 $ 22,310 $ 5,635 $ 3,742 $ (7,590) $ 147,207

Assets $2,016,780 $ 133,465 $2,150,245 $375,851 $119,910 $138,907 $ (1,716) $2,783,197

Additions to Property, plant and equipment $ 115,591 $ 11,146 $ 126,737 $ 16,958 $ 1,592 $ 8,605 $ – $ 153,892 Deferred charges 31,420 2,394 33,814 1,502 – 1,696 – 37,012 $ 147,011 $ 13,540 $ 160,551 $ 18,460 $ 1,592 $ 10,301 $ – $ 190,904

Goodwill Balance, beginning $–$6,908 $ 6,908 $ 7,596 $ – $ 30,738 $ – $ 45,242 Translation adjustment – (268) (268) – – (10) – (278) Disposal, net (Note 10a)) – – – – – (1,149) – (1,149) Write-off – – – – – (768) – (768) Balance, end $–$6,640 $ 6,640 $ 7,596 $ – $ 28,811 $ – $ 43,047 a) Since April 12, 2007, this Sector includes the distribution of electricity in Vermont by GMP in addition to the natural gas distribution activities in Quebec and Vermont. b) Distribution Sector interest income arises from, among other things, interest on overdue accounts receivable and the capitalized return on assets not included in the rate base in accordance with regulatory provisions. c) Includes $469,000 of amortization of intangible asset. Attachment 2 CAPP 11 Page 77 of 92 GAZ MÉTRO 2007 Annual Report NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 75 LIVE BETTER WITH BLUE

Only the Distribution Sector includes significant items other than amortization that have no impact on cash flows, i.e. rate stabilization accounts and reduction in deferred charges related to energy supply cost as specifically shown in the cash flow statement.

GEOGRAPHIC INFORMATION

2007 2006

Property, Property, plant, plant, Customer equipment Customer equipment revenues and goodwill revenues and goodwill

Canada $1,706,743 $1,866,461 $1,893,121 $1,867,580 United States 247,489 395,124 108,037 99,036 Total $1,954,232 $2,261,585 $2,001,158 $1,966,616

20. RELATED PARTY TRANSACTIONS Gaz Métro incurred in the normal course of business, gas storage costs of $19,998,000 and $21,132,000 during the fiscal years ended September 30, 2007 and 2006 with Intragaz, a joint venture of the Partnership owned jointly with an ultimate shareholder. The Partnership’s share of Intragaz’s revenues, which is eliminated on consolidation, is $11,963,000 in 2007 and $12,887,000 in 2006. These transactions were authorized by the Régie and the amounts paid were determined in accordance with the terms of the contracts signed by the parties establishing the value of the services rendered at the exchange amount.

As at September 30, 2007 and 2006, transactions with GMi, and companies owned by its ultimate shareholders, represent respectively an amount receivable of $116,000 and $1,252,000 included in “Trade and other receivables”. Under the Partnership Agreement, Gaz Métro pays management fees of $50,000 annually to GMi.

21. FINANCIAL INSTRUMENTS The fair value of the financial instruments represents the estimated amounts that the Partnership would receive or pay to resiliate these financial instruments as at the date of the financial statements.

FINANCIAL INSTRUMENTS INCLUDED IN BALANCE SHEET Cash and cash equivalents, trade and other receivables, bank borrowings as well as accounts payable and accrued liabilities are short-term financial instruments whose fair value approximates the carrying amount given that they will mature shortly.

The fair value of the investment in a private company cannot be easily determined because the securities are not publicly traded.

FAIRVALUEOFLONG-TERMDEBT The fair value of the long-term debt, including current instalments, is calculated using market prices at the end of the year or discounted cash flows using interest rates which Gaz Métro, its subsidiaries and its joint ventures could have obtained as at the balance sheet date for loans with similar terms, conditions and maturity dates. Attachment 2 CAPP 11 Page 78 of 92 76 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 2007 Annual Report GAZ MÉTRO LIVE BETTER WITH BLUE

21. FINANCIAL INSTRUMENTS (CONTINUED) FAIR VALUE OF LONG-TERM DEBT (CONTINUED) 2007 2006 Carrying Fair Carrying Fair amount value amount value

LONG-TERM DEBT GAZ MÉTRO $1,185,370 $1,319,909 $1,140,028 $1,347,572 NNEEC 99,480 101,235 – – VGS 19,896 22,367 22,354 25,692 GMP 111,642 110,961 – – TQM 165,750 168,800 169,600 176,548 OTHER 71,462 71,462 63,837 63,837 $1,653,600 $1,794,734 $1,395,819 $1,613,649

FAIR VALUE OF DERIVATIVE INSTRUMENTS The Partnership obtains an independent valuation of the fair value of derivative financial instruments used to stabilize the cost of gas and electricity and swaps used to hedge against fluctuations in interest and exchange rates. The valuation is based on published indices at the closing date and on volatility and expiration dates of the financial instruments. Since October 1, 2006, all derivative instruments are recorded on the balance sheet at fair value (Note 3a)).

2007 2006 Fair value Fair value receivable receivable (payable) (payable)

Balance sheet Balance sheet Off-balance sheet Total

Swaps (a) $ 327 $ 352 $ 106 $ 458 Forwards (b) 2,029 – 1,038 1,038 Instruments related to energy (c) “Fixed-price swaps” (8,590) 2,047 (16,749) (14,702) “Maximum payout swaps” (42,100) (40,768) – (40,768) “Collars” (575) 993 – 993 “Three-way collars” (6,212) (817) – (817) “9701 agreement” (d) (19,188) – – – (76,665) (38,545) (16,749) (55,294) TOTAL $(74,309) $(38,193) $(15,605) $(53,798) Portion presented in assets $ 8,183 $ 18,722 Portion presented in liabilities (82,492) (56,915) NET $(74,309) $(38,193) Volumes covered by instruments related to: natural gas (in thousands of gigajoules) 129,055 132,758 7,643 140,401 electricity (in megawatthours) 83,200 – – – Attachment 2 CAPP 11 Page 79 of 92 GAZ MÉTRO 2007 Annual Report NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 77 LIVE BETTER WITH BLUE

a) These instruments, which are sensitive to interest rates, fix interest rates on certain floating rate debt (Notes 11c) and 12h)). b) These instruments, which are sensitive to exchange rates, allow the Partnership to manage a portion of its Canadian dollar gas purchases for VGS. These instruments mature in 2008 and 2009. The nominal value of forward contracts is $27,480,000 as at September 30, 2007 and $34,750,000 as at September 30, 2006. c) Maturity of instruments related to energy:

2012 and 2008 2009 2010 2011 following Total

Fair value $(37,195) $(19,450) $(9,472) $(2,583) $(7,965) $(76,665) d) The 9701 agreement between GMP and Hydro-Québec, which expires in 2016, grants Hydro-Québec an option to purchase a certain amount of electricity at a predetermined price. The fair value of this agreement is calculated using the Black- Scholes valuation method.

CREDIT RISK The Partnership is exposed to the credit risk of its derivative financial instrument counterparties that do not meet their obligations. To minimize this risk, the Partnership only concludes such transactions with major financial institutions that meet its credit evaluation standards.

As at September 30, 2007, the Partnership is not planning to resiliate any financial instruments before the maturity date.

Management considers that these derivative financial instruments do not present any unusual risk and does not expect any significant gain or loss as a result of these transactions.

22. COMMITMENTS AND GUARANTEES a) In the normal course of business, the Partnership signed natural gas and electricity supply, transportation and storage contracts for periods up to 2017. The costs relating to these contracts will be recovered from customers in the corresponding periods. b) Gaz Métro has issued letters of credit for $8,846,000 to guarantee a portion of the supplemental post-employment benefits. c) The Partnership and some subsidiaries have agreed to provide certain collateral, pursuant to certain derivative financial instruments contracts that define the natural gas or electricity price, the interest rates or the exchange rates if the fair value of the said instruments becomes negative for Gaz Métro and exceeds a certain pre-determined threshold. However, these commitments cannot have any direct impact on income. Attachment 2 CAPP 11 Page 80 of 92 78 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 2007 Annual Report GAZ MÉTRO LIVE BETTER WITH BLUE

23. CONTINGENCIES a) The Partnership is cited in claims and lawsuits in the normal course of its activities. In the opinion of management, these claims and lawsuits are, for the most part, covered by appropriate insurance coverage and the overall amount of the contingent liability relating to these claims and lawsuits is not material. b) VGS and GMP, subsidiaries of NNEEC, jointly with others, have been cited as being potentially responsible for polluting land on which a manufactured gas plant that ceased operations in 1966 was located. In 1999, a settlement protocol was signed by the Environmental Protection Agency (EPA) and the enterprises involved. It included an action plan to restore the site and a cost sharing method. The EPA has not completed its investigation and NNEEC is not presently able to predict the outcome of this matter. The VPSB has agreed that the costs incurred to date by VGS and GMP can be recovered in rates over a period of 10 to 20 years. If future outlays exceed the provisions already recorded in the books, new requests to recover such amounts in rates will be submitted to the VPSB. In the opinion of management, the costs that might arise in connection with this potential lawsuit would not be significant for the Partnership.

24. SUBSEQUENT EVENT Distributions totalling $37,336,000, or $0.31 per unit, were paid on October 1, 2007 to Partners of record as of September 17, 2007.

25. COMPARATIVE DATA Certain comparative figures for the preceding year have been reclassified to conform to the financial statement presentation adopted for the current year. Attachment 2 CAPP 11 Page 81 of 92 GAZ MÉTRO 2007 Annual Report 79 LIVE BETTER WITH BLUE

FIVE-YEAR REVIEW–CONSOLIDATED OPERATING DATA (1)

Years ended September 30, 2007 2006 2005 2004 2003 NORMALIZED NATURAL GAS VOLUME (106m3) (2) DISTRIBUTION Industrial Firm service 3,068 2,248 2,304 2,335 2,337 Interruptible service 814 868 683 785 734 Commercial 1,879 1,873 1,897 1,917 1,905 Residential 733 728 734 752 741 Total (106m3) 6,494 5,717 5,618 5,789 5,717 Total (Bcf) 229 202 198 204 202

NATURAL GAS DELIVERIES (106m3) DISTRIBUTION Total (106m3) 6,376 5,509 5,618 5,795 5,728 Total (Bcf) 225 194 198 205 202 TRANSPORTATION (3) (4) Total (106m3) 7,051 6,420 7,449 6,711 6,321 Total (Bcf) 249 227 263 237 223

CUSTOMERS (DISTRIBUTION) Industrial 2,518 2,394 2,394 2,341 2,280 Commercial 52,515 51,246 49,781 48,300 47,254 Residential 155,450 152,263 147,911 143,204 139,182 Total 210,483 205,903 200,086 193,845 188,716

SYSTEM DATA Length of pipelines (in km) NATURAL GAS DISTRIBUTION Canada 9,903 9,903 9,707 9,516 9,318 United States 1,051 1,051 1,051 988 935 Total 10,954 10,954 10,758 10,504 10,253 NATURAL GAS TRANSPORTATION (4) Canada 670 670 670 670 670 United States 478 489 489 489 489 Total 1,148 1,159 1,159 1,159 1,159 Lenght of lines (overhead and underground) (in km) ELECTRICITY DISTRIBUTION (5) United States 6,321 – – – – Gross property, plant and equipment (in millions of dollars) 3,386 3,035 2,929 2,632 2,718 Net property, plant and equipment (in millions of dollars) 2,148 1,924 1,881 1,657 1,786 Additions to property, plant, equipment and deferred charges (in millions of dollars) 234 191 239 190 235

NUMBER OF EMPLOYEES (4) DISTRIBUTION GAZ MÉTRO 1,287 1,346 1,344 1,310 1,256 VGS 111 118 116 111 112 GMP 194 – – – – 1,592 1,464 1,460 1,421 1,368 TRANSPORTATION PNGTS – – 7 11 32 TQM 4 4 4 4 5 4 4 11 15 37 STORAGE INTRAGAZ 26 28 33 – –

ENERGY SERVICES AND OTHER AQUA DATA 84 78 72 78 81 AQUA-REHAB 64 51 55 35 51 CDH (CCUM) 21 19 17 17 18 CONSULGAZ – – 1 1 2 GAZ MÉTRO PLUS 104 101 106 109 106 HYDROSOLUTION 26 16 1 – – MTO TÉLÉCOM 17 16 14 – – OPTION GAZ – – – 1 10 SERVITECH COMBUSTION 79 61 64 56 56 SOFAME (6) – – – 14 10 SOGENER – – 1 1 2 TELDIG 20 19 14 15 13 415 361 345 327 349 (1) Unaudited data. (2) Normalized volumes based on normal temperature for natural gas distribution in Quebec. (3) Includes volumes transported and delivered by TQM to the distribution sector (GAZ MÉTRO) and PNGTS. (4) Data not adjusted for Gaz Métro’s percentage interest in the subsidiaries, joint ventures and companies subject to significant influence. (5) Acquisition of GMP on April 12, 2007. (6) Sale of all the shares of Sofame on February 15,2007. Attachment 2 CAPP 11 Page 82 of 92 80 2007 Annual Report GAZ MÉTRO LIVE BETTER WITH BLUE

TEN-YEAR REVIEW–CONSOLIDATED FINANCIAL INFORMATION

Years ended September 30 (in thousands of dollars) 2007 2006 2005

SUMMARY OF RESULTS Revenues $1,957,469 $2,003,766 $1,808,201 Direct costs 1,333,851 1,427,455 1,245,049 Gross margin 623,618 576,311 563,152 Operations and maintenance (1) 220,664 206,855 187,896 Operating income before amortization 402,954 369,456 375,256 Amortization 155,375 137,729 133,058 Operating income 247,579 231,727 242,198 Financial expense 107,734 94,732 91,304 Income before share of income of companies subject to significant influence and income taxes 139,845 136,995 150,894 Share of income of companies subject to significant influence 15,474 22,106 12,362 Income before income taxes 155,319 159,101 163,256 Income taxes 32,478 11,894 8,811 NET INCOME $ 122,841 $ 147,207 $ 154,445

CASH FLOWS Operating activities (including working capital) $ 396,540 $ 309,426 $ 319,447 Investing activities (457,464) (176,319) (335,677) Financing activities: Distributions to Partners (148,430) (156,283) (157,749) Other financing activities 207,881 32,970 189,356 NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS $ (1,473) $ 9,794 $ 15,377

PER UNIT DATA Basic net income (in dollars) $ 1.02 $ 1.25 $ 1.33 Distribution paid (in dollars) $ 1.24 $ 1.33 $ 1.36 Partners’ equity (in dollars) $ 7.65 $ 7.87 $ 7.99 Basic weighted average number of outstanding units (in thousands) 120,433 117,507 116,496 Number of outstanding units as at September 30 (in thousands) 120,437 117,509 117,505

FINANCIAL STRUCTURE Bank borrowings $ 40,805 $ 37,134 $ 29,848 Long term debt maturing within one year 9,446 80,964 28,015 Long-term debt 1,644,154 1,314,855 1,353,733 Deferred financing costs (9,604) (9,577) (7,181) Total debt 1,684,801 1,423,376 1,404,415 Partners’ equity 921,892 924,588 938,442 TOTAL $2,606,693 $2,347,964 $2,342,857 TOTAL DEBT / TOTAL CAPITALIZATION 64.6% 60.6% 59.9%

INTEREST COVERAGE ON LONG-TERM DEBT OVER A PERIOD OF 12 MONTHS (times) 2.5 2.8 2.9 TOTAL ASSETS $3,142,460 $2,783,197 $2,880,094

FINANCIAL INFORMATION RELATED TO DETERMINATION OF RATE OF RETURN OF GAZ MÉTRO BY THE RÉGIE DE L’ÉNERGIE (2) (3) Rate base (4) $1,764,928 $1,733,902 $1,673,214 Deemed common equity (4) 38.50% 38.50% 38.50% Authorized rate of return on deemed common equity 9.57% 9.33% 11.64% Deemed prefered equity (4) 7.50% 7.50% 7.50% Authorized rate of return on deemed prefered equity 5.45% 5.30% 4.97% Deemed tax expense $ 48,002 $ 45,122 $ 49,030

(1) Includes development activities. (2) Unaudited data. (3) As noted under the accounting policies in the consolidated financial statements of Gaz Métro under Regulation. (4) Calculated on a monthly average based on capitalization that differs from the financial structure as recorded in the balance sheet of Gaz Métro due to the inclusion of short-term financing, securitization of trade receivables and other items. Attachment 2 CAPP 11 Page 83 of 92 GAZ MÉTRO 2007 Annual Report TEN-YEAR REVIEW – CONSOLIDATED FINANCIAL INFORMATION 81 LIVE BETTER WITH BLUE

2004 2003 2002 2001 2000 1999 1998

$1,782,934 $1,756,537 $1,607,700 $2,069,977 $1,633,736 $1,339,022 $1,216,923 1,227,975 1,187,712 1,051,828 1,532,916 1,100,310 841,367 736,063 554,959 568,825 555,872 537,061 533,426 497,655 480,860 183,380 184,087 176,669 167,500 176,109 164,556 159,246 371,579 384,738 379,203 369,561 357,317 333,099 321,614 128,583 131,899 135,211 127,111 120,797 106,834 100,788 242,996 252,839 243,992 242,450 236,520 226,265 220,826 89,737 89,997 89,412 101,286 92,798 90,493 80,080

153,259 162,842 154,580 141,164 143,722 135,772 140,746 14,744 – – – – – – 168,003 162,842 154,580 141,164 143,722 135,772 140,746 7,626 9,515 – – – – – $ 160,377 $ 153,327 $ 154,580 $ 141,164 $ 143,722 $ 135,772 $ 140,746

$ 340,901 $ 298,933 $ 298,836 $ 323,018 $ 190,003 $ 246,539 $ 231,691 (222,132) (260,974) (111,332) (257,893) (142,657) (242,372) (265,771)

(154,327) (148,036) (141,400) (140,295) (136,981) (134,748) (138,459) 32,587 109,199 (39,172) 74,797 84,513 111,620 198,432 $ (2,971) $ (878) $ 6,932 $ (373) $ (5,122) $ (18,961) $ 25,893

$ 1.40 $ 1.39 $ 1.40 $ 1.28 $ 1.30 $ 1.25 $ 1.32 $ 1.36 $ 1.34 $ 1.28 $ 1.27 $ 1.24 $ 1.25 $ 1.30 $ 7.73 $ 7.69 $ 7.45 $ 7.35 $ 7.30 $ 7.21 $ 6.93 114,477 110,475 110,469 110,469 110,469 108,671 106,918 114,482 113,927 110,469 110,469 110,469 110,469 106,918

$ 28,543 $ 30,805 $ 29,906 $ 38,441 $ 33,216 $ 45,779 $ 45,010 46,167 16,738 44,351 3,099 3,722 11,321 10,053 1,162,743 1,271,884 1,196,760 1,267,225 1,189,766 1,082,376 1,034,770 (6,952) (15,107) (7,604) (9,932) (7,815) (6,856) (5,687) 1,230,501 1,304,320 1,263,413 1,298,833 1,218,889 1,132,620 1,084,146 884,944 876,004 822,655 811,845 805,960 796,823 740,943 $2,115,445 $2,180,324 $2,086,068 $2,110,678 $2,024,849 $1,929,443 $1,825,089 58.2% 59.8% 60.6% 61.5% 60.2% 58.7% 59.4%

3.0 2.9 2.8 2.5 2.7 2.6 2.9 $2,360,987 $2,430,898 $2,337,157 $2,349,696 $2,262,939 $2,137,998 $2,017,255

$1,666,268 $1,566,707 $1,545,557 $1,545,839 $1,486,889 $1,413,245 $1,397,303 38.50% 38.50% 38.50% 38.50% 38.50% 38.50% 38.53% 10.96% 10.34% 9.69% 10.38% 9.72% 9.64% 10.75% 7.50% 7.50% 7.50% 7.17% 7.45% 7.50% 7.50% 4.79% 4.59% 4.54% 5.37% 5.61% 5.88% 5.63% $ 51,413 $ 58,482 $ 61,787 $ 60,350 $ 63,890 $ 55,716 $ 56,817 Attachment 2 CAPP 11 Page 84 of 92 82 2007 Annual Report GAZ MÉTRO LIVE BETTER WITH BLUE

BOARD OF DIRECTORS

Pierre Anctil Jean-Guy Desjardins EXECUTIVE VICE PRESIDENT, OFFICE OF THE PRESIDENT CHAIRMAN AND CHIEF EXECUTIVE OFFICER SNC-LAVALIN GROUP INC. CENTRIA INC. Mr. Anctil has more than 20 years of public and private sector Mr. Desjardins, Chairman and Chief Executive Officer of experience as a senior executive in strategic planning, business Centria Inc., was the cofounder and main shareholder of development and management. He joined SNC-Lavalin in 1997 TAL Global Asset Management Inc. until it was taken over by and became Senior Vice-President and General Manager a financial institution. In 2003, Mr. Desjardins acquired part of the Investment Division the same year. In 2001, he was of the assets under management and the personnel of Elantis appointed Executive Vice-President and Member of the to create Fiera Capital, one of the largest independent invest- Office of the President. Mr. Anctil is a member of the Ordre ment management companies in Canada. He is a member of des ingénieurs du Québec and a director of, among others, 407 a number of associations and boards of directors, including International Inc., AltaLink Management Ltd., Astoria Energy the Bank of Canada, HEC Montréal, Mega Brands Inc. and LLC and the Montreal Heart Institute. Neurochem Inc.

Director since: August 4, 2004 Director since: August 22, 2002 Number of units held (1): 6,593 Number of units held: 3,500 Attendance at meetings (2): Board: 9/9 Committees: 8/8 Attendance at meetings (2): Board: 8/9 Committees: 10/14

Sophie Brochu Nicolle Forget PRESIDENT AND CHIEF EXECUTIVE OFFICER CORPORATE DIRECTOR GAZ MÉTRO INC. A graduate of the Université du Québec à Montréal, the École des Sophie Brochu was appointed President and Chief Executive hautes études commerciales and the Université de Montréal, Officer in February 2007. Since joining Gaz Métro in 1997, she Madame Forget is a member of the Quebec Bar. She has been has successively occupied the positions of Vice President, a member of a number of administrative tribunals and boards Business Development, Vice President, Customer and Gas of directors, including the boards of Hydro-Québec and the Supply, and Executive Vice President, Quebec Distribution. Economic Council of Canada. She is a member of the board of Madame Brochu began her career in 1987 as a Financial directors of The Jean Coutu Group (PJC) Inc. Analyst at SOQUIP, where she later served as Assistant to the President from 1990 to 1992, then as Vice President, Director since: January 30, 1997 Development from 1992 to 1997. She is a director of the Number of units held: 6,000 Montreal Museum of Archaeology and History (Pointe-à- Attendance at meetings (2): Board: 9/9 Committees: 10/10 Callière) and the Rehabilitation Institute of Montreal. She also contributes to Muscular Dystrophy Canada and to École Ghislain Gauthier Hochelaga, a primary school in the Hochelaga-Maisonneuve SENIOR VICE PRESIDENT, INVESTMENTS, district of Montreal that Gaz Métro sponsors. INFRASTRUCTURE AND ENERGY CAISSE DE DÉPÔT ET PLACEMENT DU QUÉBEC Director since: February 7, 2007 A graduate in administration from the Université du Québec à Number of units held: 10,060 Chicoutimi, Mr.Gauthier is also a Chartered Financial Analyst Attendance at meetings (2): Board: 6/6 (CFA). Following a few years with the Business Development Bank of Canada and Export Development Canada, Mr. Gauthier joined the Caisse de dépôt et placement du Québec in 1982 where he worked primarily in private placements and stock markets. He is currently responsible for the management and growth of a substantial North American and European portfolio of corporate securities in the energy and infrastructure sectors. Mr. Gauthier is a director of BAA plc in England and a member of the Private Placements Investment Committee of the Caisse de dépôt et placement du Québec.

Director since: August 4, 2004 Number of units held (1): – Attendance at meetings (2): Board: 8/9 Committees: 6/6 Attachment 2 CAPP 11 Page 85 of 92 GAZ MÉTRO 2007 Annual Report BOARD OF DIRECTORS 83 LIVE BETTER WITH BLUE

Louis P. Gignac Stephen J.J. Letwin PRESIDENT EXECUTIVE VICE PRESIDENT, G MINING SERVICES INC.AND CORPORATE DIRECTOR GAS TRANSPORTATION AND INTERNATIONAL Mr. Gignac is President of G Mining Services Inc., a mining ENBRIDGE INC. management and engineering firm. Mr. Gignac was the Before joining Enbridge, Mr. Letwin was, among others, Senior President and Chief Executive Officer of Cambior Inc. from 1986 Vice President and Chief Financial Officer with TransCanada to 2006. Until it was acquired by IAMGOLD in November 2006, PipeLines and, prior to that, President and Chief Financial Cambior produced gold, niobium and bauxite in Quebec and Officer of Numac Energy Inc. In 1999, he was appointed South America. Mr. Gignac, who holds a doctorate in mining President and Chief Operating Officer of Enbridge Energy engineering, is also a director of Domtar Corp., Franco Nevada Services until 2001 when he was appointed Group Vice Corp., Revett Minerals Inc., and St-Andrew Goldfields Ltd. President, Distribution and Services of Enbridge Inc. In 2003, Mr. Letwin was appointed Group Vice President, Gas Strategy Director since: September 25, 1990 & Corporate Development, Enbridge Inc. Number of units held: 5,000 Attendance at meetings (2): Board: 7/9 Committees: 12/12 On May 1, 2006, Mr. Letwin was promoted to the position of Executive Vice President, Gas Transportation and International. Emmanuel Hedde He has overall responsibility for Enbridge Energy Partners, L.P. COMPANY SECRETARY and is responsible for all of Enbridge’s natural gas operations, GAZ DE FRANCE GROUP including the Alliance and Vector natural gas pipelines. In Mr. Hedde was appointed Company Secretary of the Gaz de addition, he has oversight of Enbridge Gas Distribution and France Group in 2007. After starting in industrial engineering, Enbridge Gas New Brunswick and is responsible for the he held management positions in a company in the mechanical International business unit, including Enbridge Technology Inc. industry and then, for 13 years, in a bank. He joined the Finance Division of Gaz de France in 1993, first as Manager, Subsidiaries Director since: February 7, 2001 and Investment Interests followed from 2000 to 2003 as Number of units held (1): – Executive Vice President, from 2003 to 2005 as Vice President, Attendance at meetings (2): Board: 7/9 Committees: 4/6 Projects and Business Development Division, and from 2005 to 2007 as Vice President, Equity Acquisitions Division. He is Pierre Michaud a director of other industrial or service companies. CHAIRMAN OF THE BOARD PROVIGO INC. Director since: May 23, 2002 Since 2003, following more than 30 years at the helm of retail Number of units held (1): – businesses (Groupe Val Royal and Réno-Dépôt), Mr. Michaud Attendance at meetings (2): Board: 6/9 has focused on his other professional activities. Mr. Michaud is a corporate director. He has been Chairman of the Board of Provigo since June 1993. He is also Deputy Chairman of the board of the Laurentian Bank of Canada and a director of Bombardier Recreational Products and The Loblaw Companies Limited.

Director since: August 4, 2004 Number of units held: 13,000 Attendance at meetings (2): Board: 7/9 Committees: 5/8 Attachment 2 CAPP 11 Page 86 of 92 84 BOARD OF DIRECTORS 2007 Annual Report GAZ MÉTRO LIVE BETTER WITH BLUE

David T. Robottom Robert Tessier GROUP VICE PRESIDENT, CORPORATE LAW CHAIRMAN OF THE BOARD ENBRIDGE INC. GAZ MÉTRO INC. Before joining Enbridge in 2006 as its executive officer in charge Robert Tessier was appointed Chairman of the Board of Gaz of legal affairs, Mr. Robottom was a senior partner with the Métro in February 2007. Mr. Tessier started his career in the Stikeman Elliott LLP law firm. Prior to that, he was a senior public sector where he held, among others, the positions of partner and the Chief Executive Officer of Fraser Milner Casgrain Vice-Rector, Université du Québec à Montréal; Secretary of the LLP. Mr. Robottom practised primarily in the corporate law Conseil du trésor du Québec; Deputy Minister in the Ministère area, and has been recognized as a leading practitioner in the de l’Énergie et des Ressources of the government of Quebec, corporate, commercial, securities and mergers and acquisitions and Executive Vice President of the Société genérale de areas by various Canadian, U.S. and other international financement du Québec. He was President and Chief Executive legal ranking publications. Mr. Robottom holds B.Com (With Officer of MIL Group from 1991 to 1992, and of Alstom Canada Distinction), M.B.A. and LL.B. degrees and is a director of a from 1992 to 1997. He was President and Chief Executive Officer number of Enbridge affiliates, both public and private. of Gaz Métro from February 1997 to February 2007. Mr. Tessier is a member of the boards of directors of AXA Canada, CGI Director since: June 21, 2006 Group, CDH Solutions & Operations, Green Mountain Power Number of units held (1): – Corporation and Northern New England Energy Corporation. Attendance at meetings (2): Board: 9/9 He chairs the Independent Review Committee of Investors funds. He is also a director of the United Way and the Conseil Réal Sureau du patronat du Québec and chairman of the board of the Cercle PRESIDENT des Présidents du Québec. SUREAU MANAGEMENT LIMITED AND CORPORATE DIRECTOR Mr. Sureau, an accountant by profession, is President of Sureau Director since: January 30, 1997 Management Limited, a financial consulting and wealth mana- Number of units held: 27,708 gement firm. Over the course of his career, positions held by Attendance at meetings (2): Board: 9/9 Committees: 7/7 Mr. Sureau include Vice President, Finance with Forex and the Canam Manac Group. He was also President of the Ordre des comptables agréés du Québec in 1995-1996 and Vice President CHANGES TO THE BOARD OF DIRECTORS of the Patented Medicine Prices Review Board from 1995 to On February 7, 2007, Robert Tessier became Chairman of 2005. He is a director of Desjardins Financial Security Life the Board in place of Robert Parizeau who retired. Also, Assurance Company and the Société de services financiers because of changes within Gaz de France, Didier Holleaux Fonds FMOQ inc. and its subsidiaries. Since November 2004, and Joël Nicolas left the Board of Directors on February he has been a member of the Employment Insurance Board 28 and November 21, 2007 respectively. The Board thanks of Referees. He is also a member of the Discipline Committee Messrs. Parizeau, Holleaux and Nicolas for their valuable of the Ordre des comptables agréés du Québec and the Pension collaboration in the affairs of Gaz Métro. Fund Committee of the Canadian Red Cross.

Director since: January 26, 1995 (was also a Director from 1987 to 1991) Number of units held: 8,000 Attendance at meetings (2): Board: 7/9 Committees: 11/11

(1) Directors who do not personally receive compensation for their service as directors are not required to own units of the Partnership. (2) Meetings during fiscal 2007. Attachment 2 CAPP 11 Page 87 of 92 GAZ MÉTRO 2007 Annual Report 85 LIVE BETTER WITH BLUE

GOVERNANCE INFORMATION SUMMARY

THE COMPANY experience, the size of the Board appears appropriate. Gaz Métro inc. (the “Company”), as the General Partner, Directors are appointed by Noverco Inc., or by the Board, oversees the affairs of Gaz Métro Limited Partnership (the with the consent of Noverco Inc., if there is a vacancy “Partnership”). (As the Company basically only manages between two annual meetings. The Corporate Governance the affairs of the Partnership, the terms “Company” and Committee, which is composed of a majority of independent “Partnership” are hereinafter used interchangeably). Directors, reviews the composition of the Board and Comprehensive information about the governance practices provides the sole shareholder with its opinion as to the required by the Canadian Securities Administrators will size of the Board, proposed candidates or individuals who be included in the Company’s Annual Information Form should be considered as candidates by Noverco Inc. that will be published, as required when there is no infor- mation circular, no later than December 29, 2007. The A large majority of the Directors are independent within the following summary is intended for the immediate benefit definition provided by the Canadian Securities Administrators. of the reader. Only the Chairman of the Board, the President and Chief Executive Officer and another Director, Ghislain Gauthier, The Company is a wholly-owned subsidiary of Noverco Inc., are not independent based on this definition. Until a private company whose shareholders are Trencap L.P. February 7, 2007, the Chairman of the Board was President (50.38%), Enbridge Inc. (32.06%) and Gaz de France (17.56%). and Chief Executive Officer. The Chairman of the Board is not related to Noverco Inc., its shareholders or management BOARD OF DIRECTORS of the Company. Because the Chairman of the Board is not The Partnership’s affairs are managed by the Directors an independent director in accordance with Policy Statement assembled in a Board. The Board’s objective is to ensure 58-201 to Corporate Governance Guidelines of the Canadian that the Company’s resources and its potential are used Securities Administrators, the Board has appointed an and developed in such a way as to create value for the independent Director to act as Lead Director. That individual Partnership’s Limited Partners while abiding by applicable also chairs the Human Resources Committee, the Corporate laws and the Company’s values and social responsibility. Governance Committee and the Special Corporate This growth objective includes the protection of the value Governance Committee. of the Company against the main risks it faces. At the end of each meeting, the Board holds in camera The Board has a written mandate that specifies the respon- sessions, first without management, and then without the sibilities reserved to it as well as those delegated to the Chairman of the Board. At the end of each of its meetings, President and Chief Executive Officer. It has also prepared the Audit Committee also holds in camera sessions, without a position description for the Chairman of the Board and management, with the external auditors and the internal the President and Chief Executive Officer. audit manager. The external auditors and the internal audit manager attend all Audit Committee meetings. The Board is composed of 12 Directors, 5 of whom are officers of companies that are direct or indirect shareholders During the 2007 fiscal year, the Board of Directors met nine of Noverco Inc. Considering the importance of having a times, including twice by telephone conference. Director significant number of Directors who are independent of attendance was 85.83%, i.e. 103 attendances out of a Noverco Inc. and who have diverse competencies and maximum of 120. Attachment 2 CAPP 11 Page 88 of 92 86 GOVERNANCE INFORMATION SUMMARY 2007 Annual Report GAZ MÉTRO LIVE BETTER WITH BLUE

BOARD COMMITTEES DIRECTORS To assist it in discharging its responsibilities, the Board has As soon as a new Director is appointed, he/she receives created a number of Committees that each function in a copy of the Gaz Métro Director’s and Officer’s Manual, accordance with a written mandate established by the which includes a description of the Company and the Board. The Board has also prepared position descriptions Partnership, a summary of the duties, obligations and for each Committee chair. The Committees are–Executive responsibilities of a Director and of the Board, a description Committee, Audit Committee, Corporate Governance of the mandates of the Board and its Committees, a copy Committee, Special Corporate Governance Committee, of the Corporate Policies and a copy of certain Regulations Human Resources Committee and Pension Fund Committee. adopted by the Canadian Securities Administrators. The During the 2007 fiscal year, the Audit Committee met six Manual is updated regularly. times, the Corporate Governance Committee five times, the Human Resources Committee seven times and the Pension At the beginning of his/her mandate, each new Director Fund Committee five times. The Executive Committee and is also invited to meet individually with senior executives the Special Corporate Governance Committee did not meet in order to get to know them and familiarize themselves during the fiscal year. The Executive Committee, which may with each sector of the Company’s activities. exercise all of the powers of the Board of Directors, only meets when, among other things, ad hoc matters having In addition, the Board ensures Directors are familiar with no strategic importance arise between two Board meetings. the activities of the Company and the industry through The Special Corporate Governance Committee was created information provided by management and external sources. in February 2007 when Robert Tessier was appointed Management is also always available for information Chairman of the Board and Sophie Brochu was appointed sessions for Directors. President and Chief Executive Officer. Its mandate is to assess the effectiveness of the Chairman of the Board, recommend An assessment of the effectiveness of the Board, and its his reappointment each year and ensure relations between Chairman and Committees is performed approximately every him and the President and Chief Executive Officer are good. two years. The Corporate Governance Committee oversees It meets when necessary, but at least once a year. this initiative. The Chairman of the Board, the Chairman of the Corporate Governance Committee and the President The majority of the members of the Corporate Governance and Chief Executive Officer also periodically discuss the Committee, the Special Corporate Governance Committee, individual contribution of Directors to the work of the Board the Human Resources Committee, the Pension Fund and its Committees and assess their effectiveness. Committee and the Audit Committee are independent. Ghislain Gauthier, one of the four Audit Committee members, If a Director wants to retain the services of an outside is not considered independent based on the criteria consultant at the expense of the Company, he/she can do applicable to the members. However, in this case, because so with the prior approval of the Board or the Executive of his professional qualifications and experience, the Board Committee, or in an emergency, the Chairman of the Board. used the exemption in Regulation 52-110 Respecting Audit Committees of the Canadian Securities Administrators. In the view of the Board, Mr. Gauthier possesses the necessary impartial judgement to discharge his responsibilities as a member of the Audit Committee and his participation is in the interest of the Company, the Partnership and the Partners. Of the Executive Committee members the Chairman (who is also the Chairman of the Board), the President and Chief Executive Officer and Mr. Gauthier are not independent. Attachment 2 CAPP 11 Page 89 of 92 GAZ MÉTRO 2007 Annual Report 87 LIVE BETTER WITH BLUE

DIRECTORS AND OFFICERS

BOARD OF DIRECTORS MANAGEMENT

PIERRE ANCTIL 2, 3 EMMANUEL HEDDE MANAGEMENT COMMITTEE GUYLAINE LEHOUX Executive Vice President, Company Secretary Vice President, Marketing Office of the President Gaz de France Group SOPHIE BROCHU and Rate Design SNC-Lavalin Group Inc. President and STEPHEN J.J. LETWIN 2 Chief Executive Officer MARC LEMIEUX SOPHIE BROHU 1 Executive Vice President, Vice President, Legal Affairs President and Gas Transportation PIERRE DESPARS and Corporate Secretary Chief Executive Officer and International Executive Vice President Gaz Métro inc. Enbridge Inc. and Chief Financial Officer SERGE RÉGNIER Vice President, Employees JEAN-GUY DESJARDINS 3, 4 PIERRE MICHAUD 4, 5, 6 PATRICK CABANA and Culture Chairman and Chairman of the Board Vice President, Corporate Control Chief Executive Officer Provigo Inc. JEAN SIMARD Centria inc. MARTIN IMBLEAU Vice President, Sustainable DAVID T. ROBOTTOM 1 Vice President, Business Development, Public NICOLLE FORGET 3, 5, 6 Group Vice President, Development, Gas Supply & Governmental Affairs Corporate Director Corporate Law and Transportation Enbridge Inc. GHISLAIN GAUTHIER 1, 2, 6 Senior Vice President, Investments, RÉAL SUREAU 2, 3 Infrastructure and Energy President Caisse de dépôt et placement Sureau Management Limited du Québec and Corporate Director

LOUIS P. GIGNAC 1, 4, 5, 6 ROBERT TESSIER 1, 3, 4, 5 President Chairman of the Board G Mining Services Inc. and Gaz Métro inc. Corporate Director

1 Member of the Executive Committee 2 Member of the Audit Committee 3 Member of the Pension Fund Committee 4 Member of the Human Resources Committee 5 Member of the Corporate Governance Committee 6 Member of the Special Corporate Governance Committee Attachment 2 CAPP 11 Page 90 of 92 88 2007 Annual Report GAZ MÉTRO LIVE BETTER WITH BLUE

OFFICES

GAZ MÉTRO MAURICIE CLIMATISATION ET CHAUFFAGE PORTLAND NATURAL GAS 929 Père-Daniel URBAINS DE MONTRÉAL, S.E.C. TRANSMISSION SYSTEM HEAD OFFICE Trois-Rivières, Quebec G9A 2W9 1350 Nobel One Harbour Place 1717 du Havre Tel.: 819 372-1242 Boucherville, Quebec J4B 5H3 Suite 375 Montreal, Quebec H2K 2X3 Tel.: 450 641-6300 Portsmouth, New Hampshire 03801 USA Tel.: 514 598-3444 SAGUENAY-LAC ST-JEAN Xavier Pietri Tel.: 603 559-5501 1100 Bersimis President and Chief Robert W. Pirt BUSINESS OFFICES Chicoutimi, Quebec G7K 1A5 Executive Officer, Climatisation President Tel.: 418 696-2231 et Chauffage Urbains de WESTERN MONTREAL, Montréal,Inc. SERVITECH COMBUSTION LAURENTIANS AND ABITIBI- SUBSIDIARIES 12020 Albert-Hudon TÉMISCAMINGUE REGION AND AFFILIATES CONSULGAZ Montréal-Nord, Quebec H1G 3K7 1350 Nobel Tel.: 514 353-6732 WESTERN MONTREAL GAZ MÉTRO PLUS Boucherville, Quebec J4B 5H3 Luc Génier 2200 de Cannes-Brûlées 1350 Nobel Tel.: 450 641-6300 President and Chief Lasalle, Quebec H8N 2Z2 Boucherville, Quebec J4B 5H3 Luc Génier Executive Officer Tel.: 514 367-2525 Tel.: 450 641-6300 President and Chief Luc Génier Executive Officer SOGENER LAURENTIANS President and Chief 1350 Nobel 1230 Michèle-Bohec Executive Officer GREEN MOUNTAIN POWER Boucherville, Quebec J4B 5H3 Blainville, Quebec J7C 5S4 163 Acorn Lane Tel.: 450 641-6300 Tel.: 450 434-4091 AQUA DATA Colchester, Vermont 05466 USA Luc Génier 95 – 5th Avenue Toll free: 1 888 835-4672 President and Chief ABITIBI-TÉMISCAMINGUE Pincourt, Quebec J7V 5K8 Christopher L. Dutton Executive Officer 145 Québec Tel.: 514 425-1010 President and Chief Executive Rouyn-Noranda, Quebec J9X 6M8 Gordon Halliday Officer TELDIG SYSTEMS Tel.: 819 797-2111 President 575 Saint-Joseph East HYDROSOLUTION Québec, Quebec G1K 3B7 EASTERN MONTREAL AQUA-REHAB 12020 Albert-Hudon Tel.: 418 948-1314 AND MONTÉRÉGIE 2145 Michelin Montréal-Nord, Quebec H1G 3K7 Toll free: 1 800 501-5554 Laval, Quebec H7L 5B8 Tel.: 514 353-0077 Jacques Therrien EASTERN MONTREAL Tel.: 450 687-3472 Claude Lambert President 11401 L.-J. Forget Georges Dorval General Manager Anjou, Quebec H1J 2Z8 President TRANS QUEBEC & Tel.: 514 356-8777 INTRAGAZ MARITIMES PIPELINE CDH 6565 Jean-XXIII 6300 Auteuil MONTÉRÉGIE 555 René-Lévesque West Trois-Rivières, Quebec G9A 5C9 Suite 525 4305 Lapinière Suite 1230 Tel.: 819 377-8080 Brossard, Quebec J4Z 3P2 Brossard, Quebec J4Z 3H8 Montréal, Quebec H2Z 1B1 Emile Guilbert Tel.: 450 462-5300 Tel.: 450 443-7000 Tel.: 514 954-1983 Interim General Manager Bernard Otis Xavier Pietri Acting General Manager EASTERN QUEBEC REGION President M.S.C. RÉHABILITATION 2145 Michelin VERMONT GAS SYSTEMS EASTERN TOWNSHIPS CHAMPION PIPE LINE Laval, Quebec H7L 5B8 85 Swift Street 240 Léger 1717 du Havre Tel.: 450 661-1672 South Burlington, Vermont 05403 USA Sherbrooke, Quebec J1L 1M1 Montréal, Quebec H2K 2X3 Sylvain Comeau Tel.: 802 863-4511 Tel.: 819 564-1311 Tel.: 514 598-3444 General Manager A. Donald Gilbert, Jr. Martin Imbleau President and Chief QUEBEC CITY President MTO TELECOM Executive Officer 2388 Einstein 2600 Ontario Street East Sainte-Foy, Quebec G1P 3S2 Suite 225 Tel.: 418 577-5500 Montréal, Quebec H2K 4K4 Tel.: 514 524-2224 Myrtle Gale President Attachment 2 CAPP 11 Page 91 of 92 GAZ MÉTRO 2007 Annual Report 89 LIVE BETTER WITH BLUE

INFORMATION FOR PARTNERS

PARTNERSHIP’S UNITS INCOME DISTRIBUTIONS Listed on the Toronto Stock Exchange under the symbol GZM.UN. Policy is to distribute virtually all of the income in each fiscal year. Unit prices for the last two fiscal years ended September 30: Quarterly distributions are paid on Gaz Métro’s first working day following the end of a calendar quarter, i.e. the first working day of 2007 2006 January, April, July and October, to Partners of record at the close of business on December 15, March 15, June 15 and September 15 High $18.50 $22.50 or, if the Toronto Stock Exchange is not open that day, the first day Low $15.30 $15.56 on which it is open. The Partnership approved a quarterly distribution of $0.31 per unit payable on January 3, 2008. 120.4 million units outstanding with a market value of $1.9 billion Partners may request that their income distributions be deposited as at September 30, 2007. At the same date, the market value of directly into a Canadian bank account. This rapid, reliable and the 34.9 million units held by the public was $559.4 million. convenient service is offered by most banks and other financial institutions. To take advantage of this direct deposit service, contact UNIT TAX FEATURES CIBC Mellon at 1-800-387-0825. The Income Tax Act (Canada) requires the Partnership to allocate Partners their share of its taxable income. Under the terms of PROCEDURE FOR COMPLAINTS ABOUT ACCOUNTING, Gaz Métro’s Partnership Agreement, this allocation is made on a pro INTERNAL ACCOUNTING CONTROLS OR THE AUDIT rata basis in accordance with distributions received by each Partner. Any person wanting to lodge a complaint about accounting, internal The taxable income allocated to each Partner is primarily considered accounting controls or the audit of Gaz Métro Limited Partnership as business income. However, other types of income may be earned should contact the Chief Internal Auditor, Internal Audit, in one of the and allocated to Partners. Additional information is available following manners: under the “Income Distributions and Tax Treatment” heading of the By mail: Gaz Métro inc., 1717 du Havre “Investors” section of Gaz Métro’s corporate website. Montreal, Quebec H2K 2X3 A Partner who was allocated a share of the Partnership’s taxable By telephone: 1-866-598-3220 income has to file both Quebec and federal income tax returns By e-mail: [email protected] regardless of his/her province or country of residence because the taxable income allocated is business income earned in Quebec. The The Chairman of the Audit Committee will be promptly informed of taxable income allocated to each Partner will be shown on the T5013 each complaint. (federal) and Relevé 15 (Quebec) slips. A Partner who owns the Partnership’s units in a non-taxable vehicle, TRANSFER AGENT such as an RRSP, will not receive the T5013 and Relevé 15 slips CIBC Mellon since the income earned in these vehicles is taxable only when it is withdrawn from the plan. ANNUAL MEETING The Partnership’s taxable income differs from accounting income The Annual Partners’ Meeting will be held at 2:00 p.m., Wednesday, due to differences between the federal and Quebec tax legislation February 6, 2008, at the Palais des Congrès de Montréal, 1001 Place and generally accepted accounting principles. Since 1993, taxable Jean-Paul-Riopelle, Salle 511 B, Montreal, Quebec. income has, on average, exceeded distributions by 4.8% for federal purposes and 4.5% for Quebec purposes. Historically, the spreads PUBLICATION OF RESULTS have been as high as +31.5% (unfavourable spread for a taxable Following approval by the Board of Directors, the quarterly results Partner) and as low as -17.7% (favourable spread for a taxable will be published around the following dates: Partner). For the fiscal year ended September 30, 2007, taxable 1st quarter: February 6, 2008 2nd quarter: May 9, 2008 income is 9.9% and 9.6% less than distributions for federal and 3rd quarter: August 6, 2008 4th quarter: November 19, 2008 Quebec purposes respectively. When a Partner sells his/her units, the net amount by which the INVESTOR RELATIONS taxable income exceeds the distributions received will increase 1717 du Havre, Montreal, Quebec, H2K 2X3 the adjusted cost base (“ACB”), thereby decreasing the capital gain Telephone: 514-598-3324 or 514-598-3039 or increasing the capital loss, depending on the selling price. To Fax: 514-521-8168 calculate the ACB, a Partner will have to add to his/her purchase E-mail: [email protected] cost the taxable income allocated to him/her every year and deduct the total distributions received. Quarterly reports, annual reports and press releases are accessible Under the terms of Gaz Métro’s Partnership Agreement, a Partner through the “Investors” section of our website: who is a “non-resident” of Canada can be required by the Partnership www.corporatif.gazmetro.com to sell his/her units to a person who is not a “non-resident” for purposes of the Income Tax Act (Canada). Ce document est également disponible en français. The income of a limited Partner who does not participate actively in the Partnership’s business is not self-employment income subject to Quebec Pension Plan contributions. This section does not take account of the legislative measures on “specified investment flow-through entities” that would have an impact on Gaz Métro and its unitholders as of October 1, 2010, provided Gaz Métro respects at any time before that date the “normal growth guidelines” for such entities published by Canada’s Minister of Finance on December 15, 2006.

DESIGN: WWW.NOLIN.CA Printed in Canada Cert no. SGS-COC-1727 Photo: Manon Boyer – APG–1050 12/2007-19 Attachment 2 CAPP 11 Page 92 of 92

www.gazmetro.com RH-1-2008 Response to CAPP Item 12 March 28, 2008 Page 1 of 7

CAPP 12

Reference: Appendix 1, TQM Evidence, p.18-19.

Preamble: TQM refers to the prevalence of ROE formula mechanisms in Canada and speaks of the influence of the NEB.

Request:

(a) Please identify every Canadian jurisdiction that has an ROE formula mechanism, the date the mechanism was first adopted, the dates of any subsequent reviews or changes to the mechanism, the utilities in each jurisdiction to which the mechanism applies, the assets of each such utility, and the nature of each such mechanism.

(b) Please provide the proportion that the Canadian utility assets subject to an ROE formula mechanism are to the total of Canadian utility assets.

(c) Since 1994, what has been the total capital investment in Canada by rate of return regulated utilities?

Response:

(a) Currently, there are four Canadian jurisdictions that have an ROE formula mechanism: Jurisdiction Year Formula Year Formula Implementation Review National Energy Board 1995 1997, 2002 Alberta Energy and 2004 Preliminary Question Utilities Board Proceeding 2008 British Columbia 1994 2006 Utilities Commission Ontario Energy Board 1997 2004 Québec Régie de 1999 2007 l'Énergie Manitoba Public 1995 (Formula abandoned Utilities Board in 1999)

Following is a description of the mechanisms used in each jurisdiction.

Page 2 of 7

CAPP 12

National Energy Board (“NEB”)

• The NEB established its ROE formula mechanism in Decision RH-2-94 released in March 1995. Under this approach, the ROE in each year consists of:

i. the difference between the forecast yield on long-term Canada bonds for the coming year and the forecast yield in the previous year;

ii. an adjustment factor of 75%;

iii. the ROE determined the previous year

= + []× ()− ROEt ROEt −1 0.75 YLDt YLDt −1 Where:

„ ROEt: Allowed ROE in the current year

„ ROEt-1: Allowed ROE in the previous year

„ YLDt: Long-Canada bond forecast yield in the current year

„ YLDt-1: Long-Canada bond forecast yield in the previous year

• The NEB formula determines the ROE for the following transmission utilities:

Approved or Applied- Pipeline for Average Rate Base 2007 ($000) Foothills Pipe Line $795,629 TQM $459,893 TransCanada Mainline $7,297,466 Westcoast Transmission $1,147,749

Page 3 of 7

CAPP 12

Additionally, recent settlements for oil pipeline projects include the NEB formula ROE plus a premium:

„ Alberta Clipper (NEB formula ROE plus 225 basis points)

„ Line 4 Extension (NEB formula ROE plus 225 basis points)

• The formula established in 1995 included a rounding of the ROE to the nearest 25 basis points. In 1997 the Board reviewed its mechanism and decided to delete the rounding, which effectively took place in 1998.

• The Board reviewed the formula a second time in the context of the RH-4- 2001 proceeding, in which TransCanada requested total return based on the ATWACC approach. The Board granted the TransCanada Mainline an increase in its equity ratio, but did not change its formula mechanism.

• In its RH-2-94 Decision, the Board stated that it was not “setting a limit on the life of the mechanism and it does not expect to reassess the rate of return on common equity in a formal hearing for at least three years”.1

Alberta Energy Utilities Board (“EUB”) / Alberta Utilities Commission (“AUC”)

• The EUB conducted a Generic Cost of Capital (GCOC) hearing, releasing its decision in 2004 whereby a formula ROE as approved. The EUB/AUC formula follows that of the NEB, except it uses base year data as opposed to previous year data:

= + []× ()− ROEt ROEBaseYear 0.75 YLDt YLDBaseYear

• In its GCOC Decision, the EUB made reference to the generic formulas used by other Canadian regulators, especially to the one adopted by the NEB. Particularly, the EUB stated that it did not consider the implementation of a formula approach until the NEB rendered its RH-4-2001 Decision.2 Also, elements of the EUB’s formula, such as the calculation of the forecast long-term Canada bond yield, were said to be “consistent with the approach used by the NEB”.3

1National Energy Board. Reasons for Decision RH-2-94, p.34. 2 Alberta Energy Utilities Board. Decision 2004-052, p. 1. 3 Alberta Energy Utilities Board. Decision 2004-052, p. 32.

Page 4 of 7

CAPP 12

• The EUB/AUC formula determines the ROE for the following utilities:

Rate Base Utility Type of Utility 2007 ($000) ATCO Electric N/A Transmission Electric Transmission EPCOR Transmission N/A AltaLink N/A NGTL $4,143,940 Gas Transmission ATCO Pipelines $706,249 Fortis Alberta N/A ATCO Electric N/A Distribution Electric Distribution ENMAX Distribution N/A EPCOR Distribution N/A ATCO Gas $1,108,900 Gas Distribution AltaGas $104,583 *TQM does not maintain information on electric utilities.

• In March 2008, the AUC initiated a Preliminary Question Proceeding to address whether the Generic Cost of Capital adjustment formula continues to yield a fair ROE. In its original GCOC decision the EUB had established that a review would be considered after five years.

British Columbia Utilities Commission (“BCUC”)

• In 1994, the BCUC established a formula mechanism similar to the one implemented by the NEB, except for the adjustment factor. Specifically, the 1994 BCUC formula contained a 50-basis-point adjustment as opposed to the 75-basis-point adjustment used by the NEB. In 2006, the BCUC held a generic hearing to review the formula, which resulted in a change in the adjustment factor from 50 to 75 basis points, and the inclusion of a premium on the ROE to account for utility-specific risk.

• In the 2006 generic review, the Joint Industry Electrical Steering Committee expressed concerns about the circularity that would result from the BCUC relying on what has been done by other regulators. However, the BCUC stated that there was “little danger of circularity” when considering returns awarded by other regulators’ formulas.4

4 British Columbia Utilities Commission. Order G-14-06, p.49.

Page 5 of 7

CAPP 12

• The BCUC formula applies to the following utilities:

Utility Type of Utility Premium Rate Base (Basis Points) 2007 ($000) Terasen Gas Inc. 0 $2,484,000 Terasen Gas Vancouver Island Inc. 70 $483,887 Pacific Northern Gas - Gas Distribution 65 $1,318,000 W Pacific Northern Gas - 40 $33,500 NE FortisBC Electric Distribution 40 N/A BC Hydro Electric Transmission 0 & Distribution N/A * TQM does not maintain information on electric utilities.

• The BCUC established a review period of five years, while noting that any party can at any time apply to the Commission to consider a review of the formula.

Ontario Energy Board (“OEB”)

• The OEB implemented its ROE formula in 1997, which follows the same approach used by the NEB in Decision RH-2-94. The OEB formula applies only to Union Gas and Enbridge Gas Distribution. In its 1997 Decision, the OEB included a 15-basis point risk premium into the base year ROE for Union Gas considering it riskier than its peer Enbridge Gas Distribution.

• The 1997 Decision issued by the OEB states that one of the reasons for adopting a formula approach was the fact that other Canadian regulators had done so previously. In particular, the Decision summarizes the approaches of the NEB, the BCUC and the Manitoba Public Utilities Board.

• Both Union and Enbridge Gas requested a review of the formula mechanism in 2002. The OEB rendered its decision in 2004 by which the formula mechanism was reaffirmed.

• Ontario gas distribution utilities have entered into a multi-year incentive rate mechanism for the period 2008 – 2012. During this five year period, the ROE for both utilities will be the 2007 OEB formula ROE. However, at the end of the settlement period, the 2012 OEB formula ROE may be used for purpose of application of earnings sharing mechanisms.

Page 6 of 7

CAPP 12

• For the year 2007, Enbridge Gas’ approved rate base was $3,743.7 million. The 2007 approved rate base for Union Gas was $3,377.2 million.

Québec Régie de l'Énergie («Régie »)

• The Régie introduced a formula approach in 1999. This formula, which sets the ROE for Gaz Métropolitain only, follows the same mechanism used by the NEB. In addition, the Régie includes in its formula an adjustment factor of 0.30% which accounts for “issue costs and other factors”.5

• Gaz Métro proposed a new formula approach in 2007, which included the application of the Fama-French model. In its decision, the Régie did not give weight to the proposed method but did recognize that Gaz Métro’s risk had increased since 1999 when the formula was first established. As a result, the Régie granted Gaz Métro an ROE of 9.05% for 2008, as opposed to 8.91%, which would be the ROE resulting from the application of the formula.

• The Régie reaffirmed the automatic ROE adjustment formula, to be in application as of 2009, according to the terms and conditions established in Decision D-99-11.

• In the year 2007, Gaz Métro had an average rate base of $1,814.462 million.

Manitoba Public Utilities Board (MPUB)

• In 1995 the MPUB implemented an ROE formula for Centra Gas Manitoba –a natural gas distribution company. In setting the parameters for the adjustment mechanism, the MPUB referred to the RH-2-94 NEB proceeding. The MPUB adopted a similar formula to the one approved in RH-2-94, with the exception of the adjustment factor which was set at 80% as opposed to the 75% used by the NEB.

• The MPUB formula ceased to determine the ROE for Centra Gas Manitoba in 1999 when the company became a Crown corporation. Currently, the MPUB does not utilize a formula mechanism for setting return on equity.

(b) & (c)

5 Régie de l’Énergie, Décision D-99-11, p. 46.

Page 7 of 7

CAPP 12

(b) & (c)

TQM declines to respond to these requests on the grounds that the time, effort and expense preparing the responses are not warranted by the relevance, if any, or the probative value of the result. TQM expects that the requested information maybe possible for CAPP to complete itself from publicly available information.

RH-1-2008 Response to CAPP Item 13 March 28, 2008 Page 1 of 2

CAPP 13

Reference: Appendix 1, TQM Evidence, page 7, lines 13-20

Preamble: TQM states that it:

“… approaches the analysis of the fair return issue from two points of view. One is the utilization of the ATWACC approach to cost of capital estimation, which is used by corporations in the analysis of investment opportunities. The other is the traditional methodology that reflects business risk in the equity component of the capital structure and makes a separate estimate of the rate of return on equity. Traditionally, regulators including the NEB have relied on various methodologies to determine ROEs, with the equity risk premium method holding favour in recent times. Properly applied, ATWACC and the traditional methodology yield similar results in terms of overall return on capital.”

Request:

(a) Has the NEB ever used the ATWACC approach in deriving a cost of capital estimate?

(b) Is TQM suggesting that the NEB use the ATWACC approach in deriving a cost of capital estimate in this proceeding?

(c) If no, why is TQM presenting evidence regarding the ATWACC approach?

Response:

(a) In the RH-4-2001 proceeding, TCPL proposed that the NEB replace its traditional deemed equity/rate of return methodology with the ATWACC methodology. The NEB considered the approach in depth and was not persuaded to adopt it (RH-4-2001 Decision, Chapter 4, pages 37-45). In the RH-2-2004 Phase II proceeding, TCPL sponsored evidence of Drs. Kolbe and Vilbert who used an ATWACC-based approach to estimate the cost of capital and deemed equity ratio for the TCPL Mainline. The NEB considered and weighed the evidence of Drs. Kolbe and Vilbert in reaching its decision on the appropriate equity ratio for the TCPL Mainline (RH-2-2004 Phase II Decision, Chapter 5, pages 49 through 57).

Page 2 of 2

CAPP 13

(b) & (c):

TQM is sponsoring the ATWACC-based evidence of Drs. Kolbe and Vilbert to support its request for approval of a rate of return of 11 percent on deemed equity of 40 percent.

RH-1-2008 Response to CAPP Item 14 March 28, 2008 Page 1 of 1

CAPP 14

Reference: Appendix 1, TQM Evidence, p. 19, lines 3-9

Preamble: TQM discusses the use of negotiated or settlement returns in establishing a fair return. In particular, TQM states:

“Negotiated and settled returns are indicative of the returns required by the market and are therefore relevant to the comparable investment standard, at least on an aggregate if not individual basis. TQM would observe, however, that returns from settlements may be lower than market levels since they are negotiated against the NEB ROE formula which itself does not reflect market levels of return.”

“TQM notes that recent settlements for NEB-regulated pipelines have consistently yielded returns that exceed returns derived solely through application of the NEB ROE Formula.”

Request:

Would TQM confirm that it believes that if returns in negotiated or settlement agreements are below what the pipeline would have wished because of being negotiated against the NEB formula, it means that they do not reflect market returns, yet if they are above the NEB formula, they indicate that the NEB formula does not reflect market rates?

Response:

Not confirmed. TQM believes that negotiated returns for new pipeline projects at levels higher than the ROE Formula indicate that the market requires higher than formula returns for pipelines. TQM also believes that the rates of return in settlements for incumbent pipelines are lower than market levels because of the existence of the NEB ROE Formula which is lower than market return. The observation by TQM that recent settlements have yielded returns that exceed the ROE Formula level relates to the actual, achieved returns of pipelines that have operated pursuant to settlements. It appears that, through negotiated incentives and operational efficiencies, such pipelines have managed to achieve actual returns that exceed Formula returns.

RH-1-2008 Response to CAPP Item 15 March 28, 2008 Page 1 of 3

CAPP 15

Reference: Appendix 1, TQM Evidence, p. 19, lines 22-25

Preamble: TQM states that “no significant new pipeline project has been proposed in the last ten years that would utilize the 1994 ROE Formula.” TQM goes on to argue that the “fact that pipeline proponents, whether pipeline companies or energy producers, find the Formula return to be insufficient is an indication that it does not meet the fair return standard.”

Request:

(a) What is TQM’s definition of “significant” and please indicate whether TQM includes expansions of existing pipelines in this category?

(b) Is TQM aware of a “non-significant” pipeline that has been proposed in the last 10 years that has relied upon the 1994 ROE formula? Provide the details of such pipelines.

(c) What does TQM mean when it says that no projects have been proposed that “utilize” the 1994 ROE formula? Is TQM referring to the actual returns on equity and the deemed equity percentage that were established in 1994? Or is TQM referring to the idea that no projects have been proposed that specifically ask for a return on equity and a deemed equity percentage? Is TQM criticizing the NEB’s use of a formula, the structure of the formula or both?

(d) Is it not possible the pipeline companies simply have a biased view of what a fair return might be?

(e) Could TQM please provide a list of pipeline projects proposed in Canada in the past ten years, along with the return that was requested and the return that was approved?

(f) Were any pipeline projects completed in the past ten years? If so, what were the returns that were requested, and what were the returns that were approved?

(g) Please identify the pipeline projects that TQM says were or have been proposed or completed in the past ten years at returns that did not utilize the 1994 formula return but that TQM would view as having a cost of service toll model similar to TQM.

Page 2 of 3

CAPP 15

(h) Why has TQM limited its comments to the last ten years given that 2007 was the 13th year since the RH-2-94 decision came into effect on January 1, 1995?

(i) Is it TQM’s position that the NEB formula return has not been fair for the ten years prior to the filing of the present application? Is that since 1997 or 1998?

Response:

(a) TQM defines significant as any large diameter long distance rate regulated pipeline project and has included all projects of which it is aware in this category. TQM includes the Alberta Clipper and Line 4 Extension projects which are expansions of the Enbridge Mainline. However these expansions are treated as discrete incremental projects.

(b) TQM is not aware of any new pipeline projects in the last 10 years that has utilized, without modification, the NEB ROE formula.

(c) TQM simply observes that no projects have been proposed that use the NEB ROE formula result of the year in question to determine the project’s cost of capital. It is TQM’s position that this is one indication that the formula result does not meet the fair return standard.

(d) TQM’s evidence is based on the observed facts, analysis and advice from its experts.

(e) Please refer to Table 1, pages 51 and 52 of Appendix 5 to the Application.

(f) Alliance was completed with an ROE of 11.26% and equity ratio of 30% and expanded at the same ROE and equity ratio in 2007. M&NP was completed with an initial ROE of 13.0% on 30% equity ratio, and most recently set by settlement for 2008 with an ROE of 11.66% and equity ratio of 31.18%. Both were negotiated.

(g) These pipelines would include Alliance, M&NP, Alberta Clipper, Trans Mountain expansions, Southern Lights and the Line 4 Extension. Please refer to the response to CAPP 7. For a list of projects please refer to Table 1, pages 51 and 52 of Appendix 5 to the Application.

(h) The choice of a ten year time period was a judgment, informed by the fact that no significant pipelines were proposed after the RH-2-94 Decision until M&NP.

Page 3 of 3

CAPP 15

(i) Please refer to the response to CAPP 7.

RH-1-2008 Response to CAPP Item 16 March 28, 2008 Page 1 of 1

CAPP 16

Reference: Appendix 1, TQM Evidence, p. 20, lines 12-27

Preamble: TQM attempts to rectify the apparent contradiction between its claim that the NEB ROE formula is unfair and the fact that it will go ahead and make investments at rates lower that what it considers to be fair. TQM seems to indicate that the motivation for investment is that it fears the loss of business to other competitors who would receive “a higher return on investment that the incumbent.”

Request:

(a) Is TQM suggesting that the NEB has been unfair or biased in its decisions against incumbents?

(b) Is TQM suggesting that there is something about the NEB approach to return that has allowed say TransMountain to negotiate an incentive return for its existing pipeline business and also to negotiate incentives to expand its existing pipeline but prevents TQM from negotiating incentive agreements for its existing pipeline or for expansions of its existing pipeline?

Response:

(a) TQM has not made and does not make any suggestion of bias. The primary reason for this Application is the belief of TQM, based on its analysis and the views of the experts that it has retained, that the NEB-approved returns for TQM for 2007 and 2008 are unfair. As stated in the cited passage, experience shows that new pipelines would require and likely obtain a higher return on investment than incumbent pipelines.

(b) No.

RH-1-2008 Response to CAPP Item 17 March 28, 2008 Page 1 of 2

CAPP 17

Reference: Appendix 1, TQM Evidence, at page 3, Appendix 1, lines 16-19

Preamble: TQM cites as support for a change in deemed equity a Board adjudicated rate case in which TCPL capital thickness was increased from 30% to 36%. TQM goes on to discuss settlements and other negotiated agreements.

TQM also suggests that settlement returns are applicable to the Board’s rate setting process at page 19 of 22.

Request:

(a) Does TQM believe that individual rate components– such as equity thickness – arrived at through settlement are precedents on which the Board should rely. If so, please provide the rationale for this assertion.

(b) What weight does TQM give to the language in settlemnts and agreements that they are without prejudice and are not to be precedents?

(c) Does TQM believe that settlement results should be given equal weight in Board deliberations to results derived from NEB-adjudicated rate cases? If so, please provide the rationale for this assertion.

(d) Is TQM aware of any tradeoffs made as part of the settlement packages and agreements it cites for equity thickness or ROE not determined in accordance with the 94 Board return Decision? If so, please enumerate such elements. Did TQM in fact take these factors into account in its assessment? If so, how and where in the evidence is this seen? If not, why not?

Response:

(a) No. TQM does not believe that the Board should treat individual rate components arrived at through settlements as precedents. Nor is the Board bound by its past decisions as precedents. Settlement results are one indication that the formula ROE on 30% equity is not a fair return for TQM. Please refer to the response to CAPP 52(b).

Page 2 of 2

CAPP 17

(b) This wording goes hand in hand with trade-offs that may be involved in settlements, the significance of which is addressed by TQM in Appendix 2 to the Application, page 4, lines 6 to 23. Please refer to the response to CAPP 52(b).

(c) TQM believes that risk/return comparison made to pipelines whose returns were settled should be given more weight than risk/return comparisons to pipelines whose returns were set in NEB-adjudicated rate cases where ROE was an issue to avoid circularity in the approval of returns.

(d) Please refer to the response to CAPP 38.

RH-1-2008 Response to CAPP Item 18 March 28, 2008 Page 1 of 1

CAPP 18

Reference: Appendix 1, TQM Evidence, at page 11, Appendix 1, at lines 15-16

Preamble: TQM states that it believes a fair return is a market competitive return that is sufficient to maintain and increase investment.

Request:

(a) Does TQM believe that both the above conditions are necessary ones for a fair return?

(b) Can a fair return be a return that is sufficient to maintain and increase investment without being a market competitive return? Explain.

Response:

(a) The preamble is not entirely accurate. The actual phrase in the TQM evidence is:

From the perspective of TQM, a fair return is a market- competitive return that is sufficient to maintain and induce investment in TQM by its owners, Gaz Métro Limited Partnership (“Gaz Métro”) and TransCanada, and in those owners by their owners.

The phrase was intended to capture the three requirements of the fair return standard - the comparable investment standard (market competitive return), and the capital attraction and financial integrity standards (maintain and induce investment).

(b) No. TQM believes that all three elements of the fair return standard need to be met for the return to be fair.

RH-1-2008 Response to CAPP Item 19 March 28, 2008 Page 1 of 2

CAPP 19

Reference: Appendix 1, TQM Evidence, at pages 12-16, Appendix 1

Preamble: TQM discusses at great length what it feels are the legal and economic elements which must be considered by the Board in arriving at a fair return.

Request:

(a) Please confirm that the NUL, Hope and Bluefield decisions were rendered prior to 1994.

(b) Please confirm that the British Columbia Electric Railway Company v. PUC of British Columbia decision of the Canadian Supreme Court was rendered prior to 1994.

(c) Is TQM suggesting by this long discussion that the Board Guidelines adopted in 1994 failed to consider these opinions?

(d) Is TQM aware of any successful court challenge to the NEB guidelines adopted in RH-2-1994? If so, please provide cites to these successful challenges.

(e) Which witness(es) will respond to questions about the legal cases cited?

Response:

(a) to (c):

The citations included in the TQM evidence indicate that NUL was reported in 1929, Bluefield in 1923, Hope in 1944, and BC Electric in 1960 (Appendix 1, footnotes 3 and 28). TQM re-iterates that all referenced decisions were prior to 1994.

However, TQM also notes that the RH-2-94 Decision contains no discussion of the legal framework for determining fair return, nor does it mention any of the judicial decisions referred to in the TQM evidence. The RH-1-70 Decision and the RH-2-2004 Phase II Decision both discuss the legal framework and accept the total return concept that comes out of the cited judicial decisions.

Page 2 of 2

CAPP 19

(d) TQM does not know what is meant by the reference in the question to “NEB guidelines adopted in RH-2-1994”. There were no appeals of the RH-2-94 Decision following its issuance in March 1995. In RH-4-2001, the NEB was asked to review and vary the RH-2-94 Decision. It changed its RH-2-94 decision on the appropriate deemed equity for the TCPL Mainline - increasing it from 30 percent to 33 percent - but declined to accept the ATWACC methodology and confirmed the RH-2-94 Formula for the determination of rate of return. In TCPL v. NEB, which was an appeal of the NEB RH-R-1-2002 Decision refusing to review and vary the RH-4-2001 Decision, the Federal Court of Appeal confirmed the NEB decision to maintain the RH-2-94 Formula, but held that the impact on customers was an irrelevant consideration in determining a fair return. In the RH- 2-2004 Phase II Decision, the NEB explicitly acknowledged the finding of the Federal Court of Appeal and removed “the appropriate balance of customer and investor interests” from the attributes of a fair return that it had stipulated in the RH-4-2001 and RH-R-1-2002 decisions.

(e) The application of the legal cases cited is a matter of argument rather than evidence. As in the RH-4-2001 and RH-2-2004 Phase II proceedings, non-legal witnesses will respond to questions relating to their understanding of how the legal principles inform the business positions of the utility.

RH-1-2008 Response to CAPP Item 20 March 28, 2008 Page 1 of 1

CAPP 20

Reference: Appendix 1, TQM Evidence, at page 18 , Appendix 1 at lines 1-10

Preamble: TQM states that applicability of the comparable investment standard requires consideration of both indirect and direct investors in TQM. However, TQM goes on to indicate at lines 11-18 that the NEB should not focus on the financial standing of the parent, but should evaluate TQM on a stand alone basis.

Request:

If TQM desires to be evaluated on a stand-alone basis for its return, what relevance is the discussions about the competition of TQM owners in globalise capital markets?

Response:

TQM takes the position that application of the fair return standard to a stand alone TQM should include consideration of alternative investments that are available to investors in TQM. Since equity investors in the owners of TQM (TransCanada Corporation and Gaz Metro) are, through their investments, investors in TQM, the alternative returns that are available to those equity investors in globalise capital markets are relevant to the determination of the fair return for TQM.

RH-1-2008 Response to CAPP Item 21 March 28, 2008 Page 1 of 2

CAPP 21

Reference: Appendix 1, TQM Evidence, at page 20, Appendix 1, lines 12-27

Preamble: TQM indicates that the return it should be receiving is one which will prevent another pipeline from stepping in to meet consumer demand.

Request:

(a) Does TQM believe that if another pipeline feels the rate of return is sufficient to step in to meet consumer demand at a lower rate that that being demanded by TQM they should be prevented from doing so?

(b) If negotiated agreements for new pipelines are all at higher costs of capital without offsets, namely higher costs than TQM’s current costs, as TQM suggests then what is it about TQM or the TQM pipeline or the way TQM does business that would cause anyone to pay higher costs either to bypass TQM or step in and take an opportunity away from TQM for an extension or expansion such as for the proposed Rabasca or Gros Cacouna LNG terminals? Explain.

(c) What actual threats does TQM believe it is exposed to of bypass or of someone stepping in and taking an opportunity away from TQM such as the expansions for the proposed Rabasca or Gros Cacouna LNG terminals? Explain.

Response:

The preamble mischaracterizes the TQM evidence cited. TQM’s evidence does not indicate that the return it should be receiving is one that will prevent another pipeline from stepping in to meet consumer demand. TQM’s evidence is that any new pipeline constructed to meet the need for incremental capacity would require, and likely would obtain, a higher return on investment than an incumbent pipeline that is subject to the NEB’s currently approved cost of capital.

(a) Not necessarily. However, any new pipeline would likely not only take any incremental load, but also some of the load formerly transported by the incumbent pipeline leading to duplication of facilities and less efficient and orderly development of natural resources.

Page 2 of 2

CAPP 21

(b) It is likely that customers would play a higher cost of capital than TQM’s current cost of capital when incremental capacity in excess of TQM’s capacity is required and TQM is unable or is unwilling to invest additional capital at a return that is not a fair return.

(c) TQM is not aware of any potential proposals that may by-pass the TQM system.

RH-1-2008 Response to CAPP Item 22 March 28, 2008 Page 1 of 2

CAPP 22

Reference: Appendix 1, TQM Evidence, at page 21, Appendix 1, lines 4-8

Preamble: TQM indicates that it can attract and retain capital at “8.46 on 30".

Request:

Given this admission by the company – that TQM doesn’t need a higher return, it just wants a higher return – why should the NEB look any further than this statement in affirming the use of the 1994 ROE formula for a determination of TQM’s rate of return?

Response:

The CAPP request is a complete distortion of the TQM evidence. The response to the CAPP request is evident from the complete question and answer of TQM:

Q25. Is the overall return determined by the NEB ROE Formula on 30 percent deemed equity such that Gaz Métro and TransCanada will not invest in TQM?

A25. The obligation of management to shareholders is to invest only at a return that is at least comparable to returns available on alternative investments of equivalent risk. The present level of allowed return creates a serious economic disincentive to invest even maintenance capital. If maintenance capital for the TQM were considered as a stand alone incremental investment, it would not be undertaken by the owners in the present cost of capital environment.

This does not mean, however, that the owners will not invest in TQM at all at the level of approved return. They will invest the necessary capital to maintain standards of safety and security on TQM to at least their present level. They will also invest incremental capital to maintain the going-concern value of the regulated investment. If TQM were not to expand to meet customer demand, another pipeline would step in to do so.

Experience (Alliance, M&NP, Mackenzie) shows that any new pipeline would require and likely obtain a higher return on

Page 2 of 2

CAPP 22

investment than the incumbent. A result could be duplication of facilities (since competing pipelines often construct to take more than just incremental load, but also some of the load formerly transported by the incumbent, viz. Alliance) and less efficient and orderly development of the natural resources.

The fact that a regulated enterprise is able to attract capital for these purposes does not necessarily mean that it can do so on terms and conditions that are reasonable. This concept links the capital attraction standard and the comparable investment standard. The fact that TQM can attract “going-concern value” capital at “8.46 on 30” or “8.71 on 30” does not mean that it is fair that it be required do so. When alternative investments of similar risk are available at significantly higher returns, it is unfair for the regulator to require the regulated enterprise to seek to attract any capital at 8.46 or 8.71 on 30. The issue is the difference between a “necessary” or “minimum” return and a “fair” return. The capital attraction standard requires the regulator to determine the latter, not the former.

TQM believes that its evidence should persuade the Board that “11 on 40” is a fair return. A fair return will facilitate future capital investments including expansion or extension of the pipeline to accommodate liquefied natural gas.”

RH-1-2008 Response to CAPP Item 23 March 28, 2008 Page 1 of 1

CAPP 23

Reference: Appendix 1, TQM Evidence, at page 20, Appendix 1, lines 19-21; page 20, Appendix 2, lines 21-23; page 21, of Appendix 1, lines 4-8

Preamble: TQM indicates that it will “invest the necessary capital to maintain standards of safety and security on TQM to at least their present level. [TQM] will also invest incremental capital to maintain the going concern value of the regulated investment”.

TQM also indicates that “a new pipeline should not and does not require a greater return than an existing pipeline. Each has capital deployed for the same purpose and each has a long term horizon.”

Later, TQM indicates that it can attract and retain capital at “8.46 on 30".

Request:

On the basis of the above statements, why does TQM believe the NEB should award it a ROE of more than “8.46 on 30".

Response:

Please refer to the response to CAPP 22.

RH-1-2008 Response to CAPP Item 24 March 28, 2008 Page 1 of 3

CAPP 24

Reference: Appendices 1 and 2, TQM Evidence

Preamble: The evidence discusses capital attraction on reasonable terms and conditions, financial integrity, and comparative risk as well as changed circumstances. Evidence on investor perspectives and expectations has also been filed by TQM.

Request:

(a) Please provide copies of all analyst reports, presentations to external parties, and credit reports that discuss TQM’s business and/or financial risk made either by TQM or either or both of its parents TransCanada or Gaz Metro since 1994.

(b) Please provide monthly yields on TQM’s long term bonds and equivalent maturity Government of Canada bonds for each month since 1998. Please provide the equivalent data for EGDI/Consumers Gas, Terasen Gas/BC Gas, Fortis, Emera, GMI and TransCanada Pipelines.

(c) Please provide a copy of all prospectuses by which TQM or its financing affiliates have raised long term financing since 1994.

(d) Please provide copies of all press releases and filings with the Ontario or Quebec Securities Commissions dealing with material changes in TQM’s business risk since 1994.

(e) Please indicate whether there are any “stand alone” pure regulated natural gas pipelines other than TQM which issue debt in the public markets in Canada. If so provide their equity capital (in $million), debt ratio and DBRS bond rating.

(f) In the company’s judgment, does being a standalone pipeline issuing debt on its own credit enhance or weaken its debt rating and financial costs relative to other equivalent pipelines that raise debt through their parent such as the TransCanada Mainline, Foothills and the BC System?

(g) Please provide a comparison of yield spreads since 1994 for TQM and TransCanada. Please provide a similar comparison of TQM yield spreads with Enbridge.

Page 2 of 3

CAPP 24

Response:

(a) The requested materials are voluminous. A reading room is being established at the offices of TransCanada’s counsel, Stikeman Elliott LLP (Calgary), where the materials may be accessed by interested parties and the Board. Arrangements for viewing may be made by email to [email protected].

For TransCanada, equity analyst reports from 2006 onward have been searched and the relevant documents will be provided in the reading room. TransCanada has paper copies of equity analyst reports from April 2000 to December 2005. TransCanada has not undertaken a review of these hard copies on the ground that such an effort would be unduly onerous.

TransCanada has not undertaken a review of investor presentations on the ground that such an effort would be unduly onerous. The reading room material for this response includes one presentation and one transcript from November 2007 which was provided to the investment community.

Credit rating reports are provided in the response to CAPP 10(c).

(b) Please refer to Attachment CAPP 24(b) for available data provided by Bank of Montreal.

(c) Please refer to Attachment CAPP 24(c).

(d) The Company was first required to introduce a Risk Factor section in its Annual Information Form and a Business Risk section in its Annual Report for fiscal year ended 2005 and 2003 respectively. However, no press release or filing with Securities Commissions have dealt with material changes in TQM's business risk since 1994.

(e) TQM believes that Alliance Pipeline Limited Partnership (“Alliance”) and Maritimes & Northeast Pipeline Limited Partnership (“M&NP”) would both be considered stand alone pure regulated natural gas pipelines. Requested statistics, according to the most recent DBRS data, are as follows:

Equity Debt Ratio Return DBRS As at capital on Equity Rating Alliance $716.9 m 67.9% 12.5% A(low) Dec 31/06 M& NP $238.5 m 68.5% 13.0% A Sep 30/07

Page 3 of 3

CAPP 24

Note that, like TQM, these entities credit ratings are positively influenced by strong ownership. As such, the ratings are not strictly based on the pipeline business.

(f) No generalizations can be made in this regard. TQM expects that there are credit advantages and disadvantages to being a stand alone pipeline when compared to a more diversified issuer. It is also important to note that TQM’s credit ratings are enhanced by its strong owners – as such, TQM’s credit ratings are not strictly based on its pipeline business.

(g) Please refer to Attachment CAPP 24(b).

Attachment CAPP 24(b) Page 1 of 10

30-Year Government of Canada Indicative Yield Spreads (Basis Points)

Month TransQuebec Maritime TransCanada Pipeline Differential (TQM-TRP) Sep 2002 180 185 -5 Oct 2002 184 183 1 Nov 2002 171 198 -28 Dec 2002 186 178 8 Jan 2003 184 179 5 Feb 2003 179 185 -6 Mar 2003 186 198 -13 Apr 2003 177 197 -20 May 2003 179 169 10 Jun 2003 175 164 11 Jul 2003 169 151 18 Aug 2003 168 142 26 Sep 2003 160 140 20 Oct 2003 148 135 13 Nov 2003 139 132 7 Dec 2003 125 120 5 Jan 2004 113 98 15 Feb 2004 116 99 17 Mar 2004 119 105 14 Apr 2004 122 107 14 May 2004 126 110 17 Jun 2004 132 115 18 Jul 2004 134 121 13 Aug 2004 132 118 14 Sep 2004 125 117 9 Oct 2004 125 118 7 Nov 2004 124 116 8 Dec 2004 120 112 9 Jan 2005 120 110 10 Feb 2005 117 110 8 Mar 2005 115 111 4 Apr 2005 124 120 4 May 2005 128 126 2 Jun 2005 120 124 -3 Jul 2005 112 118 -6 Aug 2005 109 114 -5 Sep 2005 113 116 -3 Oct 2005 115 115 1 Nov 2005 118 121 -3 Dec 2005 120 120 0 Jan 2006 120 121 -1 Feb 2006 121 126 -5 Mar 2006 122 130 -8 Apr 2006 120 124 -3 May 2006 120 122 -2 Jun 2006 128 125 3 Jul 2006 130 128 2 Aug 2006 129 127 2 Sep 2006 128 124 4 Oct 2006 124 122 2 Nov 2006 121 121 1 Attachment CAPP 24(b) Month TransQuebec Maritime TransCanada Pipeline Differential (TQM-TRP) Page 2 of 10 Dec 2006 121 120 1 Jan 2007 121 119 2 Feb 2007 121 116 5 Mar 2007 121 118 3 Apr 2007 124 127 -3 May 2007 127 132 -5 Jun 2007 123 132 -10 Jul 2007 130 134 -4 Aug 2007 133 136 -3 Sep 2007 142 141 1 Oct 2007 138 141 -4 Nov 2007 151 149 2 Dec 2007 149 151 -3 Jan 2008 166 166 1 Feb 2008 164 170 -6 Mar 2008 187 192 -5

Note: Monthly spreads based on average of end of week spreads ocurring during month. Attachment CAPP 24(b) Page 3 of 10

30-Year Government of Canada Indicative Yield Spreads (Basis Points)

Month TransQuebec Maritime Enbridge Inc. Differential (TQM-ENB) Sep 2002 180 179 1 Oct 2002 184 187 -4 Nov 2002 171 170 0 Dec 2002 186 163 23 Jan 2003 184 161 23 Feb 2003 179 167 12 Mar 2003 186 185 1 Apr 2003 177 186 -9 May 2003 179 174 5 Jun 2003 175 170 5 Jul 2003 169 160 9 Aug 2003 168 156 12 Sep 2003 160 151 10 Oct 2003 148 139 9 Nov 2003 139 133 6 Dec 2003 125 117 8 Jan 2004 113 103 10 Feb 2004 116 108 8 Mar 2004 119 110 9 Apr 2004 122 112 9 May 2004 126 118 8 Jun 2004 132 123 9 Jul 2004 134 127 8 Aug 2004 132 127 5 Sep 2004 125 126 -1 Oct 2004 125 131 -6 Nov 2004 124 130 -6 Dec 2004 120 124 -4 Jan 2005 120 124 -4 Feb 2005 117 121 -4 Mar 2005 115 117 -2 Apr 2005 124 124 0 May 2005 128 128 0 Jun 2005 120 124 -4 Jul 2005 112 117 -5 Aug 2005 109 114 -5 Sep 2005 113 119 -6 Oct 2005 115 121 -5 Nov 2005 118 123 -5 Dec 2005 120 126 -6 Jan 2006 120 127 -7 Feb 2006 121 128 -7 Mar 2006 122 129 -7 Apr 2006 120 127 -7 May 2006 120 127 -7 Jun 2006 128 141 -13 Jul 2006 130 147 -17 Aug 2006 129 144 -15 Sep 2006 128 143 -15 Oct 2006 124 141 -17 Nov 2006 121 140 -19 Attachment CAPP 24(b) Page 4 of 10

Month TransQuebec Maritime Enbridge Inc. Differential (TQM-ENB) Dec 2006 121 143 -21 Jan 2007 121 146 -25 Feb 2007 121 147 -26 Mar 2007 121 148 -28 Apr 2007 124 159 -36 May 2007 127 172 -45 Jun 2007 123 172 -50 Jul 2007 130 181 -51 Aug 2007 133 184 -51 Sep 2007 142 193 -51 Oct 2007 138 188 -50 Nov 2007 151 200 -49 Dec 2007 149 200 -51 Jan 2008 166 216 -50 Feb 2008 164 210 -45 Mar 2008 187 230 -43

Note: Monthly spreads based on average of end of week spreads ocurring during month. Attachment CAPP 24(b) Page 5 of 10 TransCanada LT Yield vs GCAN LT Yield

TRP 6.30 May Month / 2030 G.Can 30-year Jun 2000 7.7% 5.6% Jul 2000 7.6% 5.5% Aug 2000 7.4% 5.5% Sep 2000 7.2% 5.5% Oct 2000 7.2% 5.7% Nov 2000 7.4% 5.7% Dec 2000 7.3% 5.6% Jan 2001 7.4% 5.6% Feb 2001 7.2% 5.7% Mar 2001 7.2% 5.7% Apr 2001 7.2% 5.8% May 2001 7.3% 6.0% Jun 2001 7.2% 5.9% Jul 2001 7.4% 6.0% Aug 2001 7.3% 5.9% Sep 2001 7.2% 5.8% Oct 2001 7.2% 5.7% Nov 2001 7.0% 5.4% Dec 2001 7.0% 5.5% Jan 2002 7.1% 5.7% Feb 2002 6.9% 5.6% Mar 2002 7.1% 5.8% Apr 2002 7.2% 5.9% May 2002 7.1% 5.9% Jun 2002 7.0% 5.8% Jul 2002 7.1% 5.7% Aug 2002 7.3% 5.7% Sep 2002 7.1% 5.4% Oct 2002 7.1% 5.5% Nov 2002 7.2% 5.6% Dec 2002 7.2% 5.5% Jan 2003 7.1% 5.5% Feb 2003 7.2% 5.5% Mar 2003 7.1% 5.4% Apr 2003 7.3% 5.6% May 2003 7.1% 5.4% Jun 2003 6.7% 5.0% Jul 2003 6.6% 5.1% Aug 2003 6.8% 5.4% Sep 2003 6.9% 5.4% Oct 2003 6.6% 5.2% Nov 2003 6.7% 5.4% Dec 2003 6.5% 5.3% Jan 2004 6.3% 5.3% Feb 2004 6.2% 5.2% Mar 2004 6.0% 5.0% Apr 2004 6.3% 5.2% May 2004 6.3% 5.3% Jun 2004 6.5% 5.4% Attachment CAPP 24(b) TRP 6.30 May Page 6 of 10 Month / 2030 G.Can 30-year Jul 2004 6.5% 5.3% Aug 2004 6.4% 5.2% Sep 2004 6.3% 5.1% Oct 2004 6.3% 5.1% Nov 2004 6.1% 5.0% Dec 2004 6.1% 5.0% Jan 2005 6.0% 4.9% Feb 2005 5.9% 4.7% Mar 2005 5.9% 4.8% Apr 2005 5.9% 4.7% May 2005 5.8% 4.6% Jun 2005 5.6% 4.3% Jul 2005 5.5% 4.3% Aug 2005 5.5% 4.3% Sep 2005 5.3% 4.1% Oct 2005 5.4% 4.2% Nov 2005 5.6% 4.4% Dec 2005 5.5% 4.2% Jan 2006 5.3% 4.1% Feb 2006 5.5% 4.2% Mar 2006 5.6% 4.2% Apr 2006 5.6% 4.3% May 2006 5.8% 4.5% Jun 2006 5.6% 4.4% Jul 2006 6.0% 4.6% Aug 2006 5.7% 4.4% Sep 2006 5.5% 4.2% Oct 2006 5.3% 4.1% Nov 2006 5.4% 4.1% Dec 2006 5.2% 4.0% Jan 2007 5.4% 4.1% Feb 2007 5.5% 4.2% Mar 2007 5.3% 4.1% Apr 2007 5.5% 4.2% May 2007 5.5% 4.2% Jun 2007 5.6% 4.4% Jul 2007 5.8% 4.5% Aug 2007 5.8% 4.4% Sep 2007 5.8% 4.4% Oct 2007 5.8% 4.4% Nov 2007 5.9% 4.4% Dec 2007 5.7% 4.1% Jan 2008 5.6% 4.1% Feb 2008 5.7% 4.2% Mar 2008 5.8% 4.1% Attachment CAPP 24(b) Page 7 of 10

Fortis Alberta LT Yield vs GCAN LT Yield

Fortis Alberta Month 6.22% Oct / 2034 G.Can 30-year Oct 2004 6.1% 5.0% Nov 2004 6.1% 5.0% Dec 2004 6.1% 5.0% Jan 2005 5.9% 4.9% Feb 2005 5.8% 4.7% Mar 2005 5.8% 4.8% Apr 2005 5.8% 4.7% May 2005 5.7% 4.6% Jun 2005 5.4% 4.3% Jul 2005 5.4% 4.3% Aug 2005 5.4% 4.3% Sep 2005 5.2% 4.1% Oct 2005 5.3% 4.2% Nov 2005 5.5% 4.4% Dec 2005 5.3% 4.2% Jan 2006 5.2% 4.1% Feb 2006 5.4% 4.2% Mar 2006 5.3% 4.2% Apr 2006 5.5% 4.3% May 2006 5.6% 4.5% Jun 2006 5.4% 4.4% Jul 2006 5.7% 4.6% Aug 2006 5.5% 4.4% Sep 2006 5.2% 4.2% Oct 2006 5.1% 4.1% Nov 2006 5.1% 4.1% Dec 2006 5.0% 4.0% Jan 2007 5.1% 4.1% Feb 2007 5.2% 4.2% Mar 2007 5.1% 4.1% Apr 2007 5.2% 4.2% May 2007 5.2% 4.2% Jun 2007 5.3% 4.4% Jul 2007 5.5% 4.5% Aug 2007 5.6% 4.4% Sep 2007 5.6% 4.4% Oct 2007 5.6% 4.4% Nov 2007 5.6% 4.4% Dec 2007 5.4% 4.1% Jan 2008 5.3% 4.1% Feb 2008 6.0% 4.2% Mar 2008 5.5% 4.1% Attachment CAPP 24(b) Page 8 of 10

EGDI LT Yield vs GCAN LT Yield

EGDI 6.16% Month Dec 2033 G.Can 30-year Dec 2003 6.1% 5.2% Jan 2004 6.4% 5.3% Feb 2004 6.0% 5.2% Mar 2004 5.9% 5.0% Apr 2004 6.1% 5.2% May 2004 6.2% 5.3% Jun 2004 6.4% 5.4% Jul 2004 6.3% 5.3% Aug 2004 6.3% 5.2% Sep 2004 6.2% 5.1% Oct 2004 6.1% 5.1% Nov 2004 6.0% 5.0% Dec 2004 6.0% 5.0% Jan 2005 5.8% 4.9% Feb 2005 5.8% 4.7% Mar 2005 5.7% 4.8% Apr 2005 5.7% 4.7% May 2005 5.6% 4.6% Jun 2005 5.4% 4.3% Jul 2005 5.3% 4.3% Aug 2005 5.3% 4.3% Sep 2005 5.0% 4.1% Oct 2005 5.2% 4.2% Nov 2005 5.3% 4.4% Dec 2005 5.2% 4.2% Jan 2006 5.1% 4.1% Feb 2006 5.3% 4.2% Mar 2006 5.3% 4.2% Apr 2006 5.4% 4.3% May 2006 5.6% 4.5% Jun 2006 5.4% 4.4% Jul 2006 5.8% 4.6% Aug 2006 5.5% 4.4% Sep 2006 5.2% 4.2% Oct 2006 5.1% 4.1% Nov 2006 5.1% 4.1% Dec 2006 4.9% 4.0% Jan 2007 5.1% 4.1% Feb 2007 5.2% 4.2% Mar 2007 5.1% 4.1% Apr 2007 5.2% 4.2% May 2007 5.3% 4.2% Jun 2007 5.4% 4.4% Jul 2007 5.6% 4.5% Aug 2007 5.6% 4.4% Sep 2007 5.6% 4.4% Oct 2007 5.7% 4.4% Nov 2007 5.6% 4.4% Attachment CAPP 24(b) Page 9 of 10 EGDI 6.16% Month Dec 2033 G.Can 30-year Dec 2007 5.4% 4.1% Jan 2008 5.4% 4.1% Feb 2008 5.6% 4.2% Mar 2008 5.6% 4.1% Attachment CAPP 24(b) Page 10 of 10

Gazmet LT Yield vs GCAN LT Yield

GZM 6.30% Month Oct / 2033 G.Can 30-year Jul 2006 5.5% 4.5% Aug 2006 5.4% 4.4% Sep 2006 5.2% 4.2% Oct 2006 5.1% 4.1% Nov 2006 5.1% 4.1% Dec 2006 4.9% 4.0% Jan 2007 5.0% 4.1% Feb 2007 5.2% 4.2% Mar 2007 5.0% 4.1% Apr 2007 5.1% 4.2% May 2007 5.2% 4.2% Jun 2007 5.3% 4.4% Jul 2007 5.5% 4.5% Aug 2007 5.5% 4.4% Sep 2007 5.5% 4.4% Oct 2007 5.6% 4.4% Nov 2007 5.6% 4.4% Dec 2007 5.4% 4.1% Jan 2008 5.3% 4.1% Feb 2008 5.5% 4.2% Mar 2008 5.5% 4.1% Attachment CAPP 24(c) Page 1 of 80 Attachment CAPP 24(c) Page 2 of 80 Attachment CAPP 24(c) Page 3 of 80 Attachment CAPP 24(c) Page 4 of 80 Attachment CAPP 24(c) Page 5 of 80 Attachment CAPP 24(c) Page 6 of 80 Attachment CAPP 24(c) Page 7 of 80 Attachment CAPP 24(c) Page 8 of 80 Attachment CAPP 24(c) Page 9 of 80 Attachment CAPP 24(c) Page 10 of 80 Attachment CAPP 24(c) Page 11 of 80 Attachment CAPP 24(c) Page 12 of 80 Attachment CAPP 24(c) Page 13 of 80 Attachment CAPP 24(c) Page 14 of 80 Attachment CAPP 24(c) Page 15 of 80 Attachment CAPP 24(c) Page 16 of 80 Attachment CAPP 24(c) Page 17 of 80 Attachment CAPP 24(c) Page 18 of 80 Attachment CAPP 24(c) Page 19 of 80 Attachment CAPP 24(c) Page 20 of 80 Attachment CAPP 24(c) Page 21 of 80 Attachment CAPP 24(c) Page 22 of 80 Attachment CAPP 24(c) Page 23 of 80 Attachment CAPP 24(c) Page 24 of 80 Attachment CAPP 24(c) PROSPECTUS SUPPLEMENT Page 25 of 80 To a Short Form Shelf Prospectus dated July 27, 1999 TRANS QUÉBEC & MARITIMES PIPELINE INC. [LOGO] $100,000,000 SERIES H BONDS

guaranteed by

TQM PIPELINE AND COMPANY, LIMITED PARTNERSHIP

The $100,000,000 aggregate principal amount of Series H Bonds (the “Series H Bonds”) of Trans Québec & Maritimes Pipeline Inc. (the “Company”) offered hereby will be dated August 16, 1999, will mature August 24, 2009, will bear interest at the rate of 6.50% per annum from August 16, 1999 payable semi-annually on February 24 and August 24 in each year, commencing February 24, 2000. The Series H Bonds will be redeemable, at the Company’s option, in whole at any time or in part from time to time, at the greater of: (i) par value, and (ii) the Canada Yield Price (as defined) plus, in either case, accrued and unpaid interest, if any, to the date fixed for redemption. (See “Details of the Offering - Redemption”). In the opinion of counsel, the Series H Bonds will be eligible for investment under certain statutes as set out under “Eligibility for Investment”. Price to Underwriter’s Net Public Fee (1) Proceeds (2)(3) Per $100 principal amount of Series H Bonds...... Non-fixed price 0.75% 99.25% Total...... Non-fixed price $750,000 $99,250,000

(1) The Underwriters’ overall compensation will increase or decrease by the amount by which the aggregate price paid for the Series H Bonds by purchasers exceeds or is less than the gross proceeds paid by the Underwriters to TQM Pipeline and Company, Limited Partnership. (2) Plus accrued interest, if any, from August 16, 1999 to the date of closing. (3) Before deducting expenses of issue estimated at $300,000 which, together with the Underwriters’ fee, will be paid out of the general funds of TQM Pipeline and Company, Limited Partnership. The Underwriters have agreed to purchase the Series H Bonds from TQM Pipeline and Company, Limited Partnership (the “Partnership”) at 100% of their principal amount subject to the terms and conditions set forth in the underwriting agreement referred to under “Plan of Distribution”. The Series H Bonds will be offered to the public at prices to be negotiated by the Underwriters with purchasers. Accordingly, the price at which the Series H Bonds will be offered and sold to the public may vary as between purchasers and during the period of distribution of the Series H Bonds. Each of Nesbitt Burns Inc., TD Securities Inc. and Lévesque Beaubien Geoffrion Inc. is controlled by a Canadian chartered bank which is a lender to the Company and to which the Company is indebted. The net proceeds of this offering will be used to reduce the Company’s indebtedness to certain of such banks. (See “Use of Proceeds”). We, as principals, conditionally offer the Series H Bonds, subject to prior sale, if, as and when issued by the Company, acquired and guaranteed by the Partnership and delivered to and accepted by us, in accordance with the conditions contained in the underwriting agreement referred to under “Plan of Distribution” and subject to the approval of certain legal matters on behalf of the Company and the Partnership by Byers Casgrain, a general partnership, and on our behalf by McCarthy Tétrault. Subscriptions will be received subject to rejection or allotment in whole or in part and the right is reserved to close the subscription books at any time without prior notice. It is intended that the closing of this offering will take place on August 16, 1999, or on such other date as may be agreed upon, but not later than August 23, 1999. A certificate for the aggregate principal amount of the Series H Bonds will be issued in registered form to The Canadian Depository for Securities Limited (“CDS”) and will be deposited with CDS on the date of closing. No certificate evidencing the Series H Bonds will be issued to purchasers, except in certain limited circumstances, and registration will be made in the depository service of CDS. Purchasers of the Series H Bonds will receive only a customer confirmation from the Underwriter or other registered dealer who is a CDS participant and from or through whom beneficial interest in the Series H Bonds is purchased. (See “Details of the Offering”).

July 30, 1999 Attachment CAPP 24(c) Page 26 of 80

S-2

TABLE OF CONTENTS

Page

DOCUMENTS INCORPORATED BY REFERENCE ...... S-2 PLAN OF DISTRIBUTION ...... S-2 USE OF PROCEEDS ...... S-3 DETAILS OF THE OFFERING ...... S-4 Interest and Maturity...... S-4 Redemption...... S-4 Purchase of Series H Bonds ...... S-4 Negative Covenants ...... S-4 Form, Denomination and Book-Entry...... S-4 INTEREST AND ASSET COVERAGE ...... S-5 ELIGIBILITY FOR INVESTMENT...... S-6 CERTIFICATE OF TRANS QUÉBEC & MARITIMES PIPELINE INC...... SC-1 CERTIFICATE OF THE UNDERWRITERS ...... SC-2

DOCUMENTS INCORPORATED BY REFERENCE

This prospectus supplement is deemed to be incorporated by reference into the accompanying short form shelf prospectus of the Company dated July 27, 1999 (the “Short Form Prospectus”) only for the purpose of the offering of the securities covered by this prospectus supplement. Other documents are also incorporated or deemed to be incorporated by reference into the Short Form Prospectus and reference should be made to the Short Form Prospectus for full particulars.

PLAN OF DISTRIBUTION

Under an agreement to be dated August 16, 1999 (the “Issuance Agreement”) between the Company, the Partnership, TQM Finance Inc. and The Royal Trust Company or any successor thereto (as trustee of the Series H Bonds of the Company), the Company will agree to issue to TQM Finance Inc. the $100,000,000 principal amount of Series H Bonds in consideration for bonds of TQM Finance Inc. in like principal amount. TQM Finance Inc. will agree to transfer such Series H Bonds to the Partnership in consideration for notes of the Partnership in like principal amount and the Partnership will agree to endorse its guarantee on each such Series H Bond and to sell the same to the Underwriters.

Under an agreement dated July 30, 1999 (the “Underwriting Agreement”), between the Partnership and ScotiaMcLeod Inc., Nesbitt Burns Inc., TD Securities Inc., CIBC World Markets Inc., Lévesque Beaubien Geoffrion Inc., Merrill Lynch Canada Inc., RBC Dominion Securities Inc. and Casgrain & Company Limited (the “Underwriters”), the Underwriters agreed to purchase from the Partnership on or about August 16, 1999, the $100,000,000 aggregate principal amount of Series H Bonds endorsed with the guarantee of the Partnership at an aggregate purchase price of $100,000,000, payable in cash to the Partnership against delivery of the Series H Bonds, plus accrued interest, if any, from August 16, 1999 to the date of delivery, subject to the provisions contained in such agreement. The obligation of the Underwriters may be terminated at their discretion on the basis of their assessment of the state of the financial markets and may also be terminated on the occurrence of certain stated events. The Underwriters are, however, obligated to take up and pay for all the Series H Bonds if any of them are purchased under the Underwriting Agreement. Attachment CAPP 24(c) Page 27 of 80

S-3

The Partnership has agreed to pay to the Underwriters a total fee of $750,000 for their services performed in connection with this distribution.

The Series H Bonds will be offered to the public at prices to be negotiated by the Underwriters with purchasers. Accordingly, the price at which the Series H Bonds will be offered and sold to the public may vary as between purchasers and during the period of distribution of the Series H Bonds. The Underwriters’ overall compensation will increase or decrease by the amount by which the aggregate price paid for the Series H Bonds by the purchasers exceeds or is less than the gross proceeds paid by the Underwriters to the Partnership.

The Company may be considered to be a connected issuer to certain Underwriters within the meaning of applicable securities legislation. (See “Use of Proceeds”).

The Series H Bonds offered hereby have not been and will not be registered under the United States Securities Act of 1933, as amended (the “Securities Act”) or any United States state securities laws and, subject to certain exceptions, may not be offered or sold, directly or indirectly, in the United States. Offers and sales of Series H Bonds in the United States would constitute a violation of the Securities Act unless made in compliance with the registration requirements of the Securities Act or pursuant to an exemption therefrom. The Underwriters have represented and agreed, and will cause each member of any selling group formed in connection with the distribution of the Series H Bonds to represent and agree, that they will not offer or sell, directly or indirectly, any Series H Bonds acquired by them in the United States unless made pursuant to an exemption from the registration requirements of the Securities Act.

The Underwriting Agreement, however, permits the Underwriters to re-offer and resell Series H Bonds purchased by them to certain qualified institutional buyers in the United States provided that such re-offers and resales are made only in accordance with Rule 144A under the Securities Act (which Rule provides an exemption from registration under such Act in connection with such re-offers and resales). The Underwriting Agreement provides further that the Underwriters will not take any action that would make the safe harbour provided under Regulation S of the Securities Act unavailable in connection with the offering and sale of the Series H Bonds. Such Regulation provides an exemption from registration under such laws in connection with the initial offer and sale of such Series H Bonds.

In addition, until 40 days after the commencement of the offering, any offer or sale of the Series H Bonds offered hereby within the United States by any dealer, whether or not participating in the offering, may violate the registration requirements of the Securities Act if such offer or sale is made otherwise than in accordance with Rule 144A under the Securities Act.

In connection with this distribution, the Underwriters may over-allot or effect transactions intended to stabilize or maintain the market price of the Series H Bonds at a level above that which might otherwise prevail in the open market. These transactions can be commenced or interrupted at any time during the distribution.

USE OF PROCEEDS

The net proceeds of this offering, after deducting the costs of issue and the Underwriters’ commission or other remuneration, will be used, to the extent of at least $74,000,000, to reduce outstanding indebtedness to a syndicate of lenders which provided financing relating to the development and construction of the New Section (the “Facility”). Any remaining net proceeds will be used to reduce the indebtedness under a term loan agreement with a Canadian chartered bank (the “Term Loan”). Each of Nesbitt Burns Inc. and TD Securities Inc. is controlled by a Canadian chartered bank. Both banks are part of a syndicate of financial institutions which have granted the Facility to the Partnership and each such bank has committed to loan 37.5% of the Facility. In addition, one of such banks is the lender under the Term Loan and has granted a $20,000,000 line of credit to the Partnership. Lévesque Beaubien Geoffrion Inc. is controlled by a Canadian chartered bank which has granted a $20,000,000 line of credit to the Partnership. The Partnership and the Company are not and have never been in default under the Facility, the Term Loan or either of such lines of credit. Nesbitt Burns Inc., TD Securities Inc. and Lévesque Beaubien Geoffrion Inc. will derive no benefit from this offering other than their share of the remuneration described above payable by the Partnership. None of such banks has participated in or attempted to influence the Attachment CAPP 24(c) Page 28 of 80

S-4 negotiations relating to this offering, the use of proceeds of this offering or the determination of the terms and conditions of this offering in any manner whatsoever.

DETAILS OF THE OFFERING

The following is a summary of the material attributes and characteristics of the Series H Bonds offered hereby. This summary does not purport to be complete and for full particulars reference should be made to the Trust Deeds.

Interest and Maturity

The $100,000,000 principal amount of Series H Bonds will be issued under the Trust Deed.

The Series H Bonds will be dated August 16, 1999 and will mature on August 24, 2009. Interest on the Series H Bonds will accrue from August 16, 1999 and will be payable semi-annually on February 24 and August 24 at the rate of 6.50% per annum. The first interest payment will be made on February 24, 2000 and will be in the amount of $34.20 per $1,000 principal amount of Series H Bonds, assuming the Series H Bonds are issued on August 16, 1999. The following interest payments will be in the amount of $32.50 per 1,000 principal amount of Series H Bonds.

Redemption

The Series H Bonds will be redeemable, at the Company’s option, in whole at any time or in part from time to time, on not more than 60 and not less than 20 days’ prior notice, at the greater of: (i) par value, and (ii) the Canada Yield Price (as defined below), plus, in either case, accrued and unpaid interest, if any, to the date fixed for redemption.

For the purposes of this subsection, “Canada Yield Price” means, in respect of any redemption of Series H Bonds, a price equal to the price of the Series H Bonds calculated to provide a yield to maturity equal to the sum of the Government of Canada Yield on the third business day preceding the redemption date, plus 0.21% and “Government of Canada Yield” means, on any day the arithmetic average of the yield to maturity on such day, compounded semi-annually, which a non-callable Government of Canada Bond would carry if issued, in Canadian dollars in Canada, at 100% of its principal amount on such date with a term to maturity which most closely approximates the remaining term of maturity of the Series H Bonds from such day quoted at 10:00 a.m. (ET) by, as the case may be, any two of the Underwriters or their respective successors, as selected by the Company.

Purchase of Series H Bonds

The Company will have the right, when not in default under any provision of the Trust Deed, to purchase Series H Bonds in the open market or by tender or private contract at any time at prices not exceeding 106.50% of their principal plus interest accrued and unpaid to the date of purchase and costs of purchase.

Negative Covenants

The covenants of the Company and the Partnership referred to under “Certain Covenants of the Company and the Partnership” in the Short Form Prospectus will apply to the Series H Bonds, so long as any such Series H Bonds remain outstanding. The other material attributes and characteristics of the Series H Bonds are summarized in the Short Form Prospectus.

Form, Denomination and Book-Entry

Except as described below, the Series H Bonds will be issued in “book-entry only” form and must be purchased or transferred through a participant (a “Participant”) in the depository service of CDS, which is a book-based system. On the date of closing, the Trustee will cause the Series H Bonds to be delivered to CDS and registered in the name of its nominee. The Series H Bonds will be evidenced by a book-entry only certificate. Attachment CAPP 24(c) Page 29 of 80

S-5

Registration of interests in and transfers of the Series H Bonds will be made only through the depository service of CDS.

Except as described below, a purchaser acquiring a beneficial interest in the Series H Bonds (a “Beneficial Owner”) will not be entitled to a certificate or other instrument from the Trustee or CDS evidencing that purchaser’s interest therein, and such purchaser will not be shown on the records maintained by CDS, except through a Participant. Such purchaser will receive a confirmation of purchase from the Underwriter or other registered dealer from whom Series H Bonds are purchased.

Neither the Company nor the Underwriters will assume any liability for: (a) any aspect of the records relating to the beneficial ownership of the Series H Bonds held by CDS or the payments relating thereto; (b) maintaining, supervising or reviewing any records relating to the Series H Bonds; or (c) any advice or representation made by or with respect to CDS and those contained in the Short Form Prospectus and relating to the rules governing or any action to be taken by CDS or at the direction of its Participants. The rules governing CDS provide that it acts as the agent and depositary for the Participants. As a result, Participants must look solely to CDS and Beneficial Owners must look solely to Participants for the payment of the principal and interest on the Series H Bonds paid by or on behalf of the Company to CDS.

The Series H Bonds will be issued to Beneficial Owners in fully registered and certificated form only in denominations of $1,000 and integral multiples thereof and only if: (i) required by applicable law; (ii) the book-based system ceases to exist; (iii) the Company or CDS advises the Trustee that CDS is no longer willing or able to properly discharge its responsibilities as depositary with respect to the Series H Bonds and the Company is unable to locate a qualified successor; (iv) the Company, at its option, decides to terminate the use of the book-based system through CDS in respect of the Series H Bonds, or (v) after the occurrence of an event of default, Participants acting on behalf of Beneficial Owners representing, in the aggregate, more than 50% of the aggregate principal amount of the Series H Bonds then outstanding, advise CDS in writing that the continuation of a book-based system through CDS is no longer in their best interest.

Upon the occurrence of any of the events described in (i) to (v) of the immediately preceding paragraph, the Trustee must notify CDS, for and on behalf of Participants and Beneficial Owners, of the availability through the Trustee of the Series H Bonds. Upon surrender by CDS of the certificates representing the Series H Bonds and receipt of instructions from CDS for the new registrations, the Trustee will deliver the Series H Bonds in the form of Series H Bond certificates (the "Series H Bond Certificates") and thereafter the Company will recognize the holders of such Series H Bonds as Bondholders under the Trust Deed.

Interest on the Series H Bonds will be paid to CDS while the book-based system is in effect. If Series H Bond Certificates are issued, interest will be paid by cheque drawn by the Company and sent by prepaid mail to the registered holder or by such other means as may become customary for the payment of interest. Principal of the Series H Bonds and the interest due at maturity will be paid to CDS while the book-based system is in effect. If Series H Bonds Certificates are issued, principal of the Series H Bonds and interest due at maturity will be paid upon surrender thereof at any branch in Canada of a bank to be specified in the Trust Deed.

INTEREST AND ASSET COVERAGE

The following financial ratios for the Partnership are calculated as at December 31, 1998 and as at March 31, 1999 and for the periods of twelve months then ended, giving effect to the issue of the Series H Bonds and payment of bank indebtedness. (See “Plan of Distribution” and “Use of Proceeds”). Attachment CAPP 24(c) Page 30 of 80

S-6

December 31, 1998 March 31, 1999

Interest coverage on long-term debt of the 1.86 times 2.07 times Partnership(1) (including allowance for funds used during construction)......

Net tangible asset coverage on the long-term debt of 1.45 times 1.45 times the Partnership (including current portion)......

______(1) Interest coverage on long-term debt of the Partnership excluding allowance for funds used during construction would be 1.49 as at December 31, 1998 and 1.58 as at March 31, 1999.

ELIGIBILITY FOR INVESTMENT

In the opinion of Byers Casgrain, a general partnership, counsel to the Corporation and McCarthy Tétrault, counsel to the Underwriters, based on legislation in effect at the date hereof and subject to compliance with the general investment provisions and restrictions and, where applicable, subject to compliance with prudent investment standards and the satisfaction of requirements relating to investment and lending policies and goals and, where applicable, without resort to the so called “basket” provisions, the Series “H” Bonds will not, at the time of closing of the offering, be precluded as investments under or by the following statutes:

Insurance Companies Act (Canada) Pension Benefits Act (Ontario) Pension Benefits Standards Act, 1985 (Canada) An Act respecting insurance (Québec), for an insurer (as defined therein) incorporated under the laws Trust and Loan Companies Act (Canada) of the Province of Quebec, other than a mutual Employment Pension Plans Act (Alberta) insurance association, insurance fund, a guarantee fund and a professional order, as such Insurance Act (Alberta) terms are defined therein Loan and Trust Corporations Act (Alberta) An Act respecting Trust Companies and Savings Financial Institutions Act (British Columbia) Companies (Québec), for a trust company investing its own funds and deposits it receives Pension Benefits Standards Act (British Columbia) and a savings company (as defined therein) The Insurance Act (Manitoba) investing its funds Loan and Trust Corporations Act (Ontario) Supplemental Pension Plans Act (Québec) Attachment CAPP 24(c) Page 31 of 80

SC-1

CERTIFICATE OF TRANS QUÉBEC & MARITIMES PIPELINE INC.

July 30, 1999

The Short Form Prospectus dated July 27, 1999, together with the documents incorporated therein by reference, as supplemented by the foregoing, constitutes full, true and plain disclosure of all material facts relating to the securities offered by such prospectus and this supplement as required by the securities laws of all provinces of Canada and does not contain any misrepresentation likely to affect the value or the market price of the securities to be distributed.

TRANS QUÉBEC & MARITIMES PIPELINE INC. (for itself and as mandatary of TQM Pipeline and Company, Limited Partnership)

Signed "Robert Turgeon" Signed "Réjean Laforge" Robert Turgeon Réjean Laforge President Controller and Treasurer (acting as Chief Executive Officer) (acting as Chief Financial Officer)

On behalf of the Board of Directors

Signed "Robert Tessier" Signed "John W. Carruthers" Robert Tessier John W. Carruthers Director Director Attachment CAPP 24(c) Page 32 of 80 SC-2

CERTIFICATE OF THE UNDERWRITERS

July 30, 1999

To the best of our knowledge, information and belief, the Short Form Prospectus dated July 27, 1999, together with the documents incorporated therein by reference, as supplemented by the foregoing, constitutes full, true and plain disclosure of all material facts relating to the securities offered by such prospectus and by this supplement as required by the securities laws of all provinces of Canada and does not contain any misrepresentation likely to affect the value or the market price of the securities to be distributed.

SCOTIAMcLEOD INC. NESBITT BURNS INC.

Signed "Claude Michaud" Signed "Richard Dufresne" Per: Claude Michaud Per: Richard Dufresne TD SECURITIES INC.

Signed "Tim Pepper" Per: Tim Pepper

CIBC WORLD MARKETS LÉVESQUE BEAUBIEN MERRILL LYNCH RBC DOMINION INC. GEOFFRION INC. CANADA INC. SECURITIES INC.

Signed "Charles St-Germain" Signed "Paul Béland" Signed "Catherine Sansoucy" Signed "Jean-Pierre Demontigny" Per: Charles St-Germain Per: Paul Béland Per: Catherine Sansoucy Per: Jean-Pierre Demontigny

CASGRAIN & COMPANY LIMITED

Signed "Roger Casgrain" Per: Roger Casgrain

The following includes the names of every person having an interest directly or indirectly to the extent of not less than 5% in the capital of: SCOTIAMcLEOD INC.: wholly-owned subsidiary of a Canadian chartered bank; NESBITT BURNS INC.: wholly-owned subsidiary of The Nesbitt Burns Corporation Limited, a majority-owned subsidiary of a Canadian chartered bank; TD SECURITIES INC. : a wholly owned subsidiary of a Canadian chartered bank; CIBC WORLD MARKETS INC.: a wholly-owned subsidiary of a Canadian chartered bank; LÉVESQUE BEAUBIEN GEOFFRION INC.: wholly-owned subsidiary of Lévesque Beaubien and Company Inc., a majority- owned subsidiary of a Canadian chartered bank; MERRILL LYNCH CANADA INC.: indirectly, a wholly-owned subsidiary of Merrill Lynch & Co. Inc.; RBC DOMINION SECURITIES INC.: RBC Dominion Securities Limited, a majority-owned subsidiary of a Canadian chartered bank; CASGRAIN & COMPANY LIMITED.: a majority-owned subsidiary of a private holding company. #661657.4. Attachment CAPP 24(c) Page 33 of 80

This pricing supplement, together with the short form shelf prospectus dated July 27, 1999 (the “Shelf Prospectus”) and the prospectus supplement dated July 6, 2000 (the “Prospectus Supplement”) to which it relates, as amended or supplemented, and each document deemed to be incorporated by reference into the Shelf Prospectus and the Prospectus Supplement, as amended or supplemented, constitutes a public offering of these securities only in those jurisdictions where they may be lawfully offered for sale and therein only by persons permitted to sell such securities. No securities commission or similar authority in Canada has in any way passed upon the merits of the securities offered hereunder and any representation to the contrary is an offence. These securities have not been and will not be registered under the United States Securities Act of 1933, as amended, and subject to certain exceptions, may not be offered, sold or delivered, directly or indirectly, in the United States of America, its territories or possessions.

Pricing Supplement to Short Form Shelf Prospectus dated July 27, 1999 and Prospectus Supplement dated July 6, 2000 TRANS QUÉBEC & MARITIMES PIPELINE INC. (the “Company”) [LOGO] 7.053% MTN Series Bonds due September 22, 2010 guaranteed by TQM PIPELINE AND COMPANY, LIMITED PARTNERSHIP (the “Partnership”)

Pricing Supplement No: 1 Date: July 13, 2000

Type of Note: Fixed Rate CUSIP No.: 893 32Z AA2 Principal Amount: $100,000,000 Agency Fee ($): $0.40 Offering Price: $100.00 Proceeds to Company after Agency Fee: $99,600,000 Currency: Canadian Dollars Pricing Date: July 6, 2000 Settlement Date: July 17, 2000 Maturity Date: September 22, 2010 Interest Rate: 7.053% Interest Payment Dates: March 22 and September 22 Initial Interest Payment Date: September 22, 2000 Redemption: The Company may redeem the MTN Series Bonds referred to herein on the terms and conditions and in the manner described below under the heading “Redemption Provisions”. The Government of Canada Yield Additional Percentage is 0.30%. Form of MTN Series Bonds: Book-entry MTN Series Bonds registered in the name of CDS & Co. Denomination: $5,000 and multiples of $1,000 over and above $5,000 Agents: BMO Nesbitt Burns Inc. Scotia Capital Inc. TD Securities Inc. National Bank Financial Inc. Distribution: Agency Attachment CAPP 24(c) Page 34 of 80

Redemption Provisions:

The Company shall be entitled to redeem the MTN Series Bonds referred to herein, in whole or in part from time to time, upon not less than twenty but not more than sixty days’ notice, at the higher of the Canada Yield Price (as defined below) and par, together with accrued and unpaid interest to the date fixed for redemption.

“Canada Yield Price” shall mean, in effect, a price equal to the price of each MTN Series Bond being redeemed calculated to provide a yield to maturity equal to the Government of Canada Yield (as defined below) on the business day preceding the date of the resolution of the Company authorizing the redemption, plus 0.30%. “Government of Canada Yield” means, on any day the arithmetic average of the yield to maturity on such day, compounded semi-annually, which a non-callable Government of Canada Bond would carry if issued, in Canadian dollars in Canada, at 100% of its principal amount on such date with a term to maturity which most closely approximates the remaining term of maturity of the MTN Series Bonds being redeemed from such day quoted at 10:00 a.m. (ET) by, as the case may be, any two of the Agents or their respective successors, as selected by the Company.

Other Provisions:

Each of BMO Nesbitt Burns Inc., TD Securities Inc. and National Bank Financial Inc. is controlled by a Canadian chartered bank which is a lender to the Company and to which the Company is indebted. A portion of the proceeds of the offering of MTN Series Bonds may be used to reduce the Company’s indebtedness to certain such banks for the repayment of short-term and long-term indebtedness for which the Company has granted some security interests, which consist mainly of movable and immovable hypothecs. Consequently, the Company may be considered to be a connected issuer of such Agents within the meaning of applicable securities legislation.

Each Canadian chartered bank which controls BMO Nesbitt Burns Inc. and TD Securities Inc. is part of a syndicate of institutions which have granted a term loan to the Partnership due March 31, 2003 (the “Term Loan”). In addition, one of such banks has granted a $30,000,000 line of credit to the Partnership. The Canadian chartered bank which controls National Bank Financial Inc. has granted a $30,000,000 line of credit to the Partnership. The Partnership and the Company are not and have never been in default under the Term Loan or either of such lines of credit. None of the banks participated in the decision to make the offering not did they participate in the determination of its terms. BMO Nesbitt Burns Inc., TD Securities Inc. and National Bank Financial Inc. will derive no benefit from this offering other than their share of the remuneration described above payable by the Partnership.

Scotia Capital Inc. has acted as an independent agent in connection with the offering of the MTN Series Bonds and, in that capacity, has participated with the other Agents in due diligence meetings relating to the Prospectus Supplement with the Company and its representatives, has reviewed the Prospectus Supplement and has had an opportunity to propose such changes to the Prospectus Supplement as it considered appropriate and has participated, together with the other Agents, in establishing the terms of the MTN Series Bonds and the price at which they will be sold by the Company.

This pricing supplement is deemed to be incorporated by reference into the Shelf Prospectus and the Prospectus Supplement as of the date of this Pricing Supplement and only for purposes of the MTN Series Bonds issued hereunder.

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