gas transmission


HIGHLIGHTS

Net Earnings
Net earnings from Gas Transmission decreased $36 million to $586 million in 2004 compared to $622 million in 2003.

This decrease is primarily due to a $40 million decrease from the Alberta System and an $18 million decrease from the Canadian Mainline offset by a $14 million increase due to the acquisition of GTN.

Canadian Mainline The NEB, in its decision on Phase 1 of the 2004 Application, approved virtually all applied-for costs, as well as a new non-renewable firm transportation (FT-NR) service.

In December, the NEB approved TransCanada's application to establish the North Bay Junction as a new receipt and delivery point on the Canadian Mainline.

Alberta System In July 2004, TransCanada received a decision from the EUB on the GCOC proceeding which established an ROE of 9.60 per cent for all Alberta utilities for 2004 and an equity thickness for the Alberta System of 35 per cent.

The EUB disallowed approximately $24 million pre tax of operating costs associated with the operation of the Alberta System in its decision on Phase I of the 2004 GRA which dealt with revenue requirement and rate base. Simmons became part of the Alberta System on October 1, 2004.
 
GTN
On November 1, 2004, TransCanada acquired GTN which is a high-quality, reliable operation that exemplifies the company's growth strategy.

GTN contributed $14 million of earnings for the two months ended December 31, 2004.

Other Gas Transmission In 2004, TransCanada announced plans to develop two new LNG facilities, one in Cacouna, Québec, and one offshore in the New York State waters of Long Island Sound.

In June 2004, TransCanada filed an application under the Alaska Stranded Gas Development Act and proceeded to process its application with the State of Alaska for a right-of-way across State lands for the Alaska Highway Pipeline Project.

TransCanada continued to fund the Aboriginal Pipeline Group's (APG) participation in the Mackenzie Gas Pipeline Project.

TransCanada entered into arrangements that will increase TransCanada's natural gas storage capacity in Alberta commencing in 2005. In January 2005, it announced plans to develop a $200 million natural gas storage project near Edson, Alberta.



Canadian Mainline TransCanada's 100 per cent owned 14,898 km natural gas transmission system in Canada extends from the Alberta/Saskatchewan border east to the Québec/Vermont border and connects with other natural gas pipelines in Canada and the U.S.

Alberta System TransCanada's 100 per cent owned natural gas transmission system in Alberta gathers natural gas for use within the province and delivers it to provincial boundary points for connection with the Canadian Mainline, BC System, the Foothills System and other pipelines. The 23,186 km system is one of the largest carriers of natural gas in North America.

Gas Transmission Northwest System TransCanada's 100 per cent owned natural gas transmission system extends 2,174 km and links the BC System and the Foothills System with Pacific Gas and Electric Company's California Gas Transmission System and with Tuscarora, a partially-owned entity that runs from the Oregon/California border into Nevada.
  Foothills System TransCanada's 100 per cent owned 1,040 km natural gas 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.

BC System TransCanada's 100 per cent owned natural gas transmission system extends 201 km from Alberta's western border through B.C. to connect with the Gas Transmission Northwest System at the U.S. border, serving markets in B.C. as well as the Pacific Northwest, California and Nevada.

North Baja System The North Baja System is a 100 per cent owned, 128 km natural gas transmission system that extends from southwestern Arizona to a point near Ogilby, California on the California/Mexico border and connects with a pipeline system in Mexico.

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Ventures LP Ventures LP, which is 100 per cent owned by TransCanada, owns a 121 km pipeline and related facilities which supply natural gas to the oil sands region of northern Alberta, and a 27 km pipeline which supplies natural gas to a petrochemical complex at Joffre, Alberta.

Great Lakes Great Lakes connects with the Canadian Mainline at Emerson, Manitoba and serves markets in central Canada and the eastern and midwestern U.S. TransCanada has a 50 per cent ownership interest in this 3,387 km pipeline system.

TQM TQM is a 572 km natural gas pipeline system which connects with the Canadian Mainline and transports natural gas from Montréal to Québec City and to the Portland system. TransCanada holds a 50 per cent ownership interest in TQM.

Iroquois Iroquois connects with the Canadian Mainline near Waddington, New York and delivers natural gas to customers in the Northeastern U.S. TransCanada has a 41 per cent ownership interest in this 663 km pipeline system.

Portland Portland is a 471 km pipeline that connects with TQM near East Hereford, Québec and delivers natural gas to customers in the Northeastern U.S. TransCanada has a 61.7 per cent ownership interest in Portland.

Northern Border Northern Border is a 2,010 km natural gas pipeline system which serves the U.S. Midwest from a connection with the Foothills System. TransCanada indirectly owns approximately 10 per cent of Northern Border through its 33.4 per cent ownership interest in TC PipeLines, LP.
  Tuscarora Tuscarora operates a 386 km pipeline system transporting natural gas from the Gas Transmission Northwest System at Malin, Oregon to Wadsworth, Nevada with delivery points in northeastern California and northwestern Nevada. TransCanada owns an aggregate 17.4 per cent interest in Tuscarora, of which 16.4 per cent is held through TransCanada's interest in TC PipeLines, LP.

CrossAlta CrossAlta is an underground natural gas storage facility connected to the Alberta System and is located near Crossfield, Alberta. CrossAlta has a working natural gas capacity of 40 Bcf with a maximum deliverability capability of 410 million cubic feet per day (MMcf/d). TransCanada holds a 60 per cent ownership interest in CrossAlta.

Edson TransCanada is currently developing the Edson natural gas storage facility near Edson, Alberta. The Edson facility will have a capacity of approximately 50 Bcf and will connect to TransCanada's Alberta System. The facility is expected to be in-service in second quarter 2006.

TransGas TransGas is a 344 km natural gas pipeline system which runs from Mariquita in the central region of Colombia to Cali in the southwest of Colombia. TransCanada holds a 46.5 per cent ownership interest in this pipeline.

Gas Pacifico Gas Pacifico is a 540 km natural gas pipeline extending from Loma de la Lata, Argentina to Concepción, Chile. TransCanada holds a 30 per cent ownership interest in Gas Pacifico.

INNERGY INNERGY is an industrial natural gas marketing company based in Concepción, Chile that markets natural gas transported on Gas Pacifico. TransCanada holds a 30 per cent ownership interest in INNERGY.

Gas Transmission Net Earnings-at-a-Glance


Year ended December 31 (millions of dollars)

2004

2003

2002

Wholly-Owned Pipelines
     
    Canadian Mainline 272 290 307
    Alberta System 150 190 214
    GTN (1)
14    
    Foothills System (2) 22 20 17
    BC System 7 6 6

465 506 544

Other Gas Transmission
    Great Lakes 55 52 66
    Iroquois 17 18 18
    TC PipeLines, LP
16 15 17
    Portland (3) 10 11 2
    Ventures LP 15 10 7
    TQM 8 8 8
    CrossAlta 13 6 13
    TransGas 11 22 6
    Northern Development
(6)
(4)
(6)
    General, administrative, support costs and other
(18)
(22)
(22)
  121 116 109
Net earnings
586 622 653

(1) TransCanada acquired GTN on November 1, 2004. Amounts in this table reflect TransCanada's 100 per cent ownership interest in GTN's net earnings from the acquisition date.
(2) The remaining ownership interests in the Foothills System, previously not held by TransCanada, were acquired on August 15, 2003. Amounts in this table reflect TransCanada's proportionate interest in Foothills' net earnings prior to acquisition and 100 per cent interest thereafter.
(3) TransCanada increased its ownership interest in Portland to 43.4 per cent from 33.3 per cent in September 2003 and to 61.7 per cent from 43.4 per cent in December 2003. Amounts in this table reflect TransCanada's proportionate net earnings from Portland.

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In 2004, net earnings from the Gas Transmission business were $586 million compared to $622 million and $653 million in 2003 and 2002, respectively. The decrease in 2004 compared to 2003 was mainly due to lower net earnings from Wholly-Owned Pipelines, partially offset by higher net earnings from Other Gas Transmission. The 2004 decrease in Wholly-Owned Pipelines' net earnings was primarily due to a reduction in the Alberta System's net earnings of $40 million, reflecting the EUB's disallowance of certain operating costs in its decision on Phase I of the 2004 GRA and in its decision in the GCOC proceeding to allow an ROE in 2004 lower than the return implicit in the 2003 revenue requirement settlement with stakeholders.

In addition, net earnings on the Canadian Mainline were lower by $18 million in 2004 compared to 2003 due to a decline in both the average investment base and the allowed ROE. The addition of GTN had a positive effect on 2004 net earnings. Higher 2004 net earnings from Other Gas Transmission were primarily due to increased earnings from CrossAlta and Ventures LP and a $7 million gain on sale of Millennium, partially offset by the negative impact of a weaker U.S. dollar.

The overall decrease of $31 million in 2003 Gas Transmission net earnings compared to 2002 was mainly due to higher incremental earnings in 2002 due to the NEB's Fair Return decision in 2002 and lower investment bases in 2003.

GAS TRANSMISSION - EARNINGS ANALYSIS

Canadian Mainline The Canadian Mainline is regulated by the NEB. The NEB sets tolls which provide TransCanada the opportunity to recover projected costs of transporting natural gas and provide a return on the Canadian Mainline's average investment base. New facilities are approved by the NEB before construction begins. Changes in investment base, the ROE, the level of deemed common equity and the potential for incentive earnings affect the net earnings of the Canadian Mainline.

The Canadian Mainline generated net earnings of $272 million in 2004, a decrease of $18 million and $35 million, respectively, when compared to 2003 and 2002 earnings. The decrease in net earnings in 2004 from 2003 is primarily due to a decline in average investment base and allowed ROE. The NEB-approved ROE decreased to 9.56 per cent in 2004 from 9.79 per cent in 2003. The reduction in net earnings from $307 million in 2002 to $290 million in 2003 is due to the combined effect of a lower average investment base and recognition of incremental earnings in 2002 as a result of the NEB's June 2002 Fair Return decision in which it increased the deemed common equity ratio to 33 per cent from 30 per cent effective January 1, 2001. This decision resulted in additional net earnings of $16 million for the year ended December 31, 2001, which the company recognized in 2002.

Alberta System The Alberta System is regulated by the EUB primarily under the provisions of the Gas Utilities Act (Alberta) (GUA) and the Pipeline Act (Alberta). Under the GUA, its rates, tolls and other charges, and terms and conditions of service are subject to approval by the EUB.

Net earnings of $150 million in 2004 were $40 million lower than 2003 and $64 million lower than 2002. These decreases were primarily due to the impacts of the EUB decisions in respect of Phase I of the 2004 GRA in August 2004 and on the GCOC proceeding in July 2004. In the 2004 GRA Phase I decision, the EUB disallowed approximately $24 million of operating costs associated with the operation of the pipeline. In addition, the GCOC decision resulted in a lower return on deemed common equity in 2004 compared to the earnings implicit in the 2003 and 2002 negotiated settlements which included fixed revenue requirement components, before non-routine adjustments, of $1.277 billion and $1.347 billion, respectively. Net earnings in 2004 reflect a return of 9.60 per cent on deemed common equity of 35 per cent as approved in the GCOC decision. The negative impact of the two EUB decisions on 2004 net earnings was partially offset by lower operating costs.

GTN GTN is regulated by the U.S. Federal Energy Regulatory Commission (FERC), which has authority to regulate rates for natural gas transportation in interstate commerce. Both the Gas Transmission Northwest System and the North Baja System operate under fixed rate models, under which maximum and minimum rates for various service types have been ordered by the FERC and under which GTN is permitted to discount or negotiate rates on a non-discriminatory basis. The Gas Transmission Northwest System's last filed rate case was in 1994 and it was settled and approved by the FERC in 1996. The North Baja System's rates were established in the FERC's initial order in 2002 certifying construction and operation of the system. The net earnings of GTN are impacted by variations in volumes delivered under the various service types that are provided, as well as by variations in the costs of providing transportation service. Net earnings were $14 million for the two months ended December 31, 2004.

Other Gas Transmission TransCanada's direct and indirect investments in various natural gas pipelines and gas transmission related businesses are included in Other Gas Transmission. It also includes project development activities related to TransCanada's pursuit of new pipeline and natural gas transmission related opportunities throughout North America, including northern gas and LNG.

TransCanada's net earnings from Other Gas Transmission in 2004 were $121 million compared to $116 million and $109 million in 2003 and 2002, respectively. The increased net earnings of $5 million in 2004 compared to 2003 were due to higher earnings from CrossAlta, reflecting favourable natural gas storage market conditions in Alberta, higher earnings from Ventures LP as a result of an expansion that was completed in 2003 and higher earnings from Great Lakes as a result of successful marketing of short-term services. In addition, a $7 million gain was recorded on the sale of the company's equity interest in Millennium in 2004. These increases were partially offset by the impact of a weaker U.S. dollar and higher general, administrative and support costs. Earnings for 2003 also included a positive $11 million tax adjustment for TransGas.

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GAS TRANSMISSION - OPPORTUNITIES AND DEVELOPMENTS
GTN Acquisition TransCanada acquired GTN on November 1, 2004 for approximately US$1.2 billion, excluding assumed debt of approximately US$0.5 billion. The acquisition of GTN complements TransCanada's long-term commitment to serve the Pacific Northwest and California markets, which the company has advanced over the past few years with its 2002 West Path expansion and the purchase of the remaining interests in Foothills in 2003 that it previously did not own. GTN consists of two interstate pipeline systems: the Gas Transmission Northwest System, a 2,174 km pipeline extending from Kingsgate, B.C. on the B.C./Idaho border to Malin, Oregon on the Oregon/California border; and the North Baja System, a 128 km system that extends from Ehrenberg, Arizona to a point near Ogilby, California on the California/Mexico border. The North Baja System is well positioned to provide natural gas transportation services from LNG regasification terminals currently planned to be constructed on the coast of northern Baja California, Mexico.

Simmons Acquisition In October 2004, TransCanada acquired Simmons for approximately $22 million. The assets include 380 km of pipeline and metering facilities and four compressor units located in northern Alberta. The system has a capacity of approximately 185 MMcf/d. Simmons delivers natural gas to the Fort McMurray area from several connecting receipt points within the Alberta System, along with production connected directly to the pipeline. Continued development of oil sands resources is expected to increase the demand for natural gas in the Fort McMurray area, as oil sands production requires natural gas supply for hydrogen feedstock, power generation and fuel.

Iroquois In February 2004, the Iroquois pipeline began commercial operation of its Eastchester expansion. The expansion was the first major natural gas transmission pipeline to be built into New York City in approximately 40 years. In January 2004, Iroquois filed a rate application with the FERC to establish rates for the Eastchester expansion. Iroquois received approval from the FERC in October 2004 of its comprehensive settlement agreement, which implements an eight year rate moratorium for Eastchester. In addition to settling the Eastchester recourse rates, Iroquois also entered into negotiated rate agreements with all of the initial shippers on the Eastchester project.



Portland In August 2004, Portland initiated a restructuring plan whereby all of its operating and administrative functions would be performed by TransCanada pursuant to service agreements. The transition of duties was completed by December 2004.

Supply In 2004, primary supply growth within the WCSB came from northeastern B.C. and the west central foothills area of Alberta. TransCanada attracted incremental volumes from the Sierra discovery in B.C. through the new Ekwan receipt connection and incremental supply from the emerging Cutbank Ridge discovery in B.C. In Alberta, TransCanada saw increased incremental volumes from the central foothills area as well as unconventional production from coalbed methane (CBM), primarily from Horseshoe Canyon coal located in the central Alberta area between Edmonton and Calgary.

TransCanada continues to pursue the most cost effective and timely connection of these volumes, which allows TransCanada's customers to take advantage of continued premium gas price environments. TransCanada will continue to grow by seeking new opportunities to connect additional gas supplies.

Western Markets TransCanada continues to pursue growth opportunities within existing and new natural gas markets. In 2004, TransCanada further executed its strategy to provide cost effective incremental delivery service into the growing Fort McMurray, Alberta market. The acquisition of Simmons was approved by the EUB and the costs of acquiring these assets were added to the Alberta System rate base. The Alberta System's new arrangement for transportation service with Ventures LP was also approved and this service commenced on October 1, 2004.

TransCanada has also negotiated an arrangement with Husky Oil for transportation service on the Kearl Lake Pipeline that will provide the Alberta System an additional 110 MMcf/d delivery capacity. The fast growing production from oil-sands supply in Fort McMurray has also driven expansion in the refining sector of east Edmonton. As a result, TransCanada has negotiated an arrangement for transportation service with ATCO Pipelines (ATCO) that will allow TransCanada to provide incremental delivery service into the industrial market east of Edmonton. Both the Husky Kearl Lake and ATCO transportation service arrangements are included in the 2005 GRA.

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Eastern Markets Demand for natural gas continues to be strong in Eastern Canada and Northeast U.S. markets as reflected by the response to several open seasons held on TransCanada's Canadian Mainline. Power generation continues to be the primary driver for incremental natural gas demand in these markets. Ontario and Québec markets continue to develop power projects that require significant incremental natural gas volumes.

Customer behaviour continues to reinforce contract repositioning from long haul to short haul transportation and TransCanada seeks to address these market needs. To that end, TransCanada proposed a new contracting point near North Bay, Ontario to provide customers with additional flexibility. The NEB approval of the NBJ Application in 2004 means the market now has an additional short haul contracting option available.

Northern Development In 2004, TransCanada continued to pursue pipeline opportunities to move both Mackenzie Delta and Alaska North Slope natural gas to markets throughout North America.

TransCanada, the Mackenzie Delta gas producers and the APG reached funding and participation agreements in June 2003 that secured a role for TransCanada in the proposed Mackenzie Gas Pipeline Project and the APG to become an equity participant. This project would result in a natural gas pipeline being constructed from Inuvik, Northwest Territories to the northern border of Alberta, where it would connect with the Alberta System. TransCanada has agreed to finance the APG for its one-third share of project development costs. This share is currently expected to be approximately $90 million. The loan will be repaid from the APG's share of available future pipeline revenues. TransCanada funded $26 million of this loan in 2004, for a total of $60 million to December 31, 2004. The ability to recover this investment is dependent upon the outcome of the project. Under the terms of the agreement, TransCanada gains an immediate opportunity to acquire up to five per cent equity ownership of the pipeline at the time of construction. In addition, TransCanada also gains certain rights of first refusal to acquire 50 per cent of any divestitures of existing partners and an entitlement to obtain a one-third interest in all expansion opportunities once the APG reaches a one-third share, with the producers and the APG sharing the balance.

In October 2004, Imperial Oil Resources applied for the main regulatory approvals for the Mackenzie Gas Pipeline Project. These were submitted to the boards, panels and agencies responsible for assessing and regulating energy developments in the Northwest Territories. These filings mark a significant milestone in the project definition phase. TransCanada will continue to support the project through its position established under the various project agreements and to facilitate the interconnection of Mackenzie Delta natural gas into the Alberta System.

In 2004, TransCanada continued its discussions with Alaska North Slope producers and the State of Alaska relating to the Alaskan portion of the Alaska Highway Pipeline Project. In June 2004, TransCanada filed an application under the State of Alaska's Stranded Gas Development Act and requested the State resume processing of its long-pending application for a right-of-way lease across State lands. Once the right-of-way lease application is approved, TransCanada is prepared to convey the lease to another entity if that entity is willing to connect with TransCanada's pipeline system. The lease conveyance would require an interconnection agreement with TransCanada at the Yukon/Alaska border. TransCanada's application is one of three applications currently before the State.

Foothills holds the priority right to build, own and operate the first pipeline through Canada for the transportation of Alaskan gas. This right was granted under the NPA, following a lengthy competitive hearing before the NEB in the late 1970's, which resulted in 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 the facilities in Alberta which constitute a prebuild for the Alaska Highway Pipeline Project, and to expand those facilities five times, the latest of which was in 1998. Continued development under the NPA should ensure the earliest in-service date for the project.

LNG In September 2004, TransCanada and Petro-Canada signed a Memorandum of Understanding to develop an LNG facility, Cacouna Energy, in Cacouna, Québec. TransCanada and Petro-Canada will each own 50 per cent of the facility and TransCanada will operate the facility, while Petro-Canada will contract for all of the capacity and supply the LNG. The proposed facility would be capable of receiving, storing and regasifying imported LNG with an average annual send-out capacity of approximately 500 MMcf/d of natural gas. The estimated cost of construction is $660 million. Construction of the facility is subject to regulatory approval from federal, provincial and municipal governments which is expected to take approximately two years. If approval is received, the facility is expected to be in-service towards the end of this decade.

In November 2004, TransCanada and Shell US Gas & Power LLC (Shell) announced plans to jointly develop an offshore LNG regasification terminal, Broadwater Energy, in the New York State waters of Long Island Sound. The proposed floating storage and regasification unit would be located approximately 15 km off the Long Island coast and 18 km off the Connecticut coast. The proposed terminal would be capable of receiving, storing and regasifying imported LNG with an average send-out capacity of approximately one Bcf/d of natural gas. Broadwater Energy LLC, an entity which will be owned 50 per cent by TransCanada, will own and operate the facility, while Shell will contract for all of the capacity and supply the LNG. The estimated cost of construction is expected to be approximately US$700 million. Construction of the facility is subject to regulatory approval from U.S. federal and state governments. The regulatory approval process is expected to take approximately two to three years. TransCanada and Shell have filed a request with the FERC to initiate a six to nine month public review of the Broadwater proposal. Provided the necessary approvals are received, it is expected the facility will be in-service in late 2010.

In a referendum held in March 2004, the residents of Harpswell, Maine voted against leasing a town-owned site to build the Fairwinds LNG regasification facility. As a result, TransCanada and its partner, ConocoPhillips Company, have suspended further work on this LNG project.

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Natural Gas Storage In September 2004, TransCanada entered into long-term arrangements, commencing in second quarter 2005, for approximately 20 Bcf of additional natural gas storage capacity in Alberta. The capacity under contract increases to approximately 30 Bcf in 2006 and approximately 40 Bcf in 2007.

In January 2005, TransCanada announced that it is developing a $200 million natural gas storage project near Edson, Alberta. The Edson facility will have a capacity of approximately 50 Bcf and will connect to TransCanada's Alberta System. Storage capacity is expected to be available from the Edson facility commencing in second quarter 2006, on a phased-in basis.

These developments, combined with the company's investment in the CrossAlta natural gas storage facility, position TransCanada to become one of the largest natural gas storage providers in Western Canada. Upon completion of the Edson facility, TransCanada will own or control more than 110 Bcf, or approximately one-third, of the storage capacity in Alberta at that time. Current market fundamentals for natural gas storage are strong. The imbalance in North American natural gas supply and demand has created natural gas price volatility, resulting in demand for storage service. TransCanada believes Alberta-based storage will continue to serve market needs and could play an even more important role when northern gas is connected to North American markets.

Oil Pipeline In February 2005, TransCanada announced that it is proposing a US$1.7 billion oil pipeline project to transport approximately 400,000 barrels per day of heavy crude oil from Alberta to Illinois. The proposed Keystone project would be approximately 3,000 km in length. In addition to new pipeline construction, it would require the conversion of approximately 1,240 km of one of the lines in TransCanada's existing multi-line natural gas pipeline systems in Alberta, Saskatchewan and Manitoba.

TransCanada will continue to meet with oil producers, refiners and industry groups, including the Canadian Association of Petroleum Producers, to gauge additional interest and support for Keystone. Preliminary discussions have begun with stakeholders, including communities, government representatives and landowners along the proposed route. When sufficient support for this project from oil producers and shippers is obtained, TransCanada will proceed with the necessary regulatory applications. TransCanada will require various regulatory approvals from Canadian and U.S. agencies before construction can begin.

TransCanada is in the business of connecting energy supplies to markets and it views this opportunity as another way of providing a valuable service to its customers. Converting one of the company's natural gas pipeline assets for oil transportation is an innovative, cost-competitive way to meet the need for pipeline expansions to accommodate anticipated growth in Canadian crude oil production during the next decade.

GAS TRANSMISSION - REGULATORY DEVELOPMENTS
In 2004, TransCanada's principal regulatory activities included the appeal to the Federal Court of Appeal (FCA) of the NEB's February 2003 decision on TransCanada's September 2002 application to review and vary its decision on the fair return for the Canadian Mainline in 2001 and 2002 issued in June 2002; the EUB's GCOC proceeding; the 2004 Application; Phase I and II of the Alberta System's 2004 GRA; and the NBJ proceeding. TransCanada also filed the Alberta System's 2005 GRA-Phase I application. On February 24, 2005, TransCanada advised the EUB that it had reached an agreement in principle for the Alberta System with negotiating parties and requested a suspension of the established regulatory timetable for adjudication of the 2005 GRA pending its finalization of the contemplated settlement agreement. On February 25, 2005, the EUB granted this request. In February 2005, TransCanada reached a settlement with its Canadian Mainline shippers regarding 2005 tolls.

Canadian Mainline In February 2003, the NEB denied TransCanada's September 2002 request for a Review and Variance of the Fair Return decision. TransCanada maintained that the Fair Return decision issued in June 2002 did not recognize the long-term business risks of the Canadian Mainline, which led to an appeal of this decision with the FCA. In May 2003, the FCA granted TransCanada leave to appeal the NEB's February 2003 decision. In April 2004, the FCA dismissed TransCanada's appeal of the NEB's Fair Return Review and Variance decision, while endorsing TransCanada's view of the law relating to the determination of a fair return by the NEB.

In September 2003, TransCanada filed an application to define a new receipt and delivery point near NBJ to better satisfy market requirements. A December 2004 NEB decision approved NBJ as a new contracting point.

In January 2004, TransCanada filed its 2004 Application with the NEB, which included a request for approval of an 11 per cent ROE on deemed common equity of 40 per cent. Given the then pending appeal to the FCA on return issues, the NEB decided to hear the application in a two-phase proceeding, with all matters except cost of capital to be considered in the first phase. In its Phase I decision issued in September 2004, the NEB approved virtually all applied-for costs and the new FT-NR. Upon receipt of the FCA's decision dismissing TransCanada's appeal in April 2004, TransCanada amended its application to an ROE of 9.56 per cent, as determined under the NEB's generic ROE formula, on deemed common equity of 40 per cent. The NEB proceeded to consider cost of capital in the second phase of the proceeding which commenced in November 2004 and continued into 2005. A decision is expected in second quarter 2005.

In November 2004, the Canadian Association of Petroleum Producers (CAPP) filed an application with the NEB to review and vary its Phase I decision with respect to approving tolls for FT-NR to be determined on a biddable basis, allowing TransCanada to include all forecast long-term incentive compensation costs in its 2004 cost of service and allowing TransCanada to recover, through tolls, certain regulatory and legal costs relating to review and appeal proceedings.

On February 18, 2005, having considered whether there was a doubt as to the correctness of its decision on these matters, the NEB decided to review its decision on the toll to be charged for FT-NR service. It also decided not to review its decision on the inclusion of the disputed regulatory and legal costs in tolls. At CAPP's request, the NEB deferred its consideration of a review on its decision regarding long-term incentive compensation costs. As a next step, the NEB will consider the merits of confirming, amending or overturning its decision on the FT-NR toll.

On February 14, 2005, TransCanada announced it had reached a settlement with its Canadian Mainline shippers regarding 2005 tolls. This settlement establishes OM&A costs for 2005 at $169.5 million, which is comparable to the 2004 level. Any variance between actual OM&A costs in 2005 and those agreed to in the settlement will accrue to TransCanada. All other cost elements of the 2005 revenue requirement will be treated on a flow through basis. Further, the 2005 ROE for the Canadian Mainline will be 9.46 per cent as determined under the NEB's generic ROE formula, and the common equity component of the Canadian Mainline's capital structure in 2005 shall be based on the NEB's decision in the recently concluded hearing on the Canadian Mainline's cost of capital for 2004, subject to the outcome of any review applications or appeals.

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Alberta System In July 2003, TransCanada, along with other utilities, filed evidence in the EUB's GCOC Proceeding. In this application, TransCanada requested a return of 11 per cent on a deemed common equity of 40 per cent for the Alberta System in 2004. In July 2004, the EUB released its decision on the GCOC Proceeding. In its GCOC decision, the EUB set a generic ROE of 9.60 per cent for all Alberta utilities for 2004 and an equity thickness for the Alberta System of 35 per cent. The EUB decided that the generic ROE in future years will be adjusted by 75 per cent of the change in long-term Canada bonds, consistent with the approach used by the NEB. The EUB also indicated that a review of its ROE adjustment mechanism would not occur prior to 2009, unless the ROE resulting from the application of the ROE formula is less than 7.6 per cent or greater than 11.6 per cent. As for changes in capital structure, the EUB expects changes would only be pursued if there is a material change in investment risk.

In August 2004, TransCanada received the EUB's decision on Phase I of the 2004 GRA which consisted of evidence in support of the applied-for rate base and revenue requirement. The EUB approved depreciation rates which resulted in a composite rate of 4.05 per cent in 2004, the purchase of Simmons and the recovery of costs associated with existing transportation arrangements with the Foothills, Simmons and Ventures LP systems. However, the EUB decision disallowed certain operating and capital costs.

In September 2004, TransCanada filed with the Alberta Court of Appeal for leave to appeal the EUB's decision on Phase I of the 2004 GRA with respect to the disallowance of applied-for incentive compensation costs. In its decision, the EUB disallowed approximately $24 million (pre tax) of operating costs, which included $19 million of applied-for incentive compensation costs. TransCanada believes the EUB made errors of law in deciding to deny the inclusion of these compensation-related costs in the revenue requirement. The company believes these are necessary costs that it reasonably and prudently incurs for the safe, reliable and efficient operation of the Alberta System. At the request of TransCanada, the Court of Appeal adjourned the appeal for an indefinite period of time while TransCanada considers the merits of a review and variance application to the EUB in respect of 2004 costs, and works toward a negotiated settlement of future years' tolls with its customers.

In October 2004, the EUB approved Phase II of the 2004 GRA, which primarily dealt with rate design and services. The EUB also directed TransCanada to file a 2005 GRA-Phase II application on or before April 1, 2005 to address certain cost allocation issues related to rate design.

In December 2004, TransCanada filed its 2005 Phase I GRA with the EUB. On February 24, 2005, TransCanada advised the EUB that it had reached an agreement in principle for the Alberta System with negotiating parties and requested a suspension of the established regulatory timetable for adjudication of the 2005 GRA pending its finalization of the contemplated settlement agreement. On February 25, 2005, the EUB granted this request.

GAS TRANSMISSION - BUSINESS RISKS
Competition TransCanada faces competition at both the supply end and the market end of its systems. The competition is a result of other pipelines accessing an increasingly mature WCSB and markets served by TransCanada's pipelines. In addition, the continued expiration of transportation contracts has resulted in significant reductions in firm contracted capacity on both the Canadian Mainline and Alberta System.

As of December 2003, the WCSB had remaining discovered natural gas reserves of 55 trillion cubic feet and a reserves-to-production ratio of approximately nine years at current levels of production. Historically, additional reserves have continually been discovered to maintain the reserves-to-production ratio at close to nine years. Natural gas prices in the future are expected to be higher than long-term historical averages due to a tighter supply/demand balance which should stimulate exploration and production in the WCSB. However, WCSB supply is expected to remain essentially flat. With the expansion of capacity on TransCanada's wholly- and partially-owned pipelines over the past decade, and the competition provided by other pipelines, combined with significant growth in natural gas demand in Alberta, TransCanada anticipates there will be excess pipeline capacity out of the WCSB for the foreseeable future.

TransCanada's Alberta System provides the major natural gas gathering and export transportation capacity for the WCSB by connecting to most of the natural gas processing plants in Alberta and then transporting natural gas for domestic and export deliveries. The Alberta System faces competition primarily from the Alliance Pipeline, a natural gas pipeline from northeast B.C. to the Chicago area for ex-Alberta deliveries. In addition, the Alberta System has faced, and will continue to face, increasing competition from other pipelines.

The Canadian Mainline is TransCanada's cross-continent natural gas pipeline serving mid-western and eastern markets in Canada and the U.S. The demand for natural gas in TransCanada's key eastern markets is expected to continue to increase, particularly to meet the expected growth in 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 U.S. Northeast have access to an array of pipeline and supply options. Eastern Canadian markets that historically received Canadian supplies only from TransCanada are now capable of receiving supplies from new pipelines into the region that can source Western Canadian, Atlantic Canadian and U.S. supplies.

The Canadian Mainline has experienced reductions in long haul FT contracts. This has been partially offset by an increase in short haul contracts. While decreases in throughput do not directly impact Canadian Mainline earnings, such decreases will impact the competitiveness of its tolls. Looking forward, in the short to medium term, there is limited opportunity to reduce tolls by increasing long haul volumes on the Canadian Mainline.

The Gas Transmission Northwest System must compete with other pipelines for access to natural gas supplies and its markets. Transportation service capacity on the Gas Transmission Northwest System provides customers with access to supplies of natural gas primarily from the WCSB and serves markets in the Pacific Northwest, California and Nevada. These three markets may also access supplies from other competing basins in addition to supplies from the WCSB. Historically, natural gas supplies from the WCSB have been competitively priced on the Gas Transmission Northwest System in relation to natural gas supplies from the other supply regions serving these markets. Natural gas transported from the WCSB on the Gas Transmission Northwest System competes for the California and Nevada markets against supplies from the Rocky Mountain and southwest U.S. supply basins. In the Pacific Northwest market, natural gas transported on the Gas Transmission Northwest System competes against Rocky Mountain gas supply as well as additional western Canadian supply that is transported by Williams' Northwest Pipeline.

Transportation service on the North Baja System provides access to natural gas supplies primarily from both the Permian Basin, located in western Texas and southeastern New Mexico, and the San Juan Basin, primarily located in northwestern New Mexico and Colorado. The North Baja System delivers gas to Gasoducto Bajanorte Pipeline at the California/Mexico border, which transports the gas to markets in northern Baja California, Mexico. While there are currently no direct competitors to deliver natural gas to the North Baja System's downstream markets, the pipeline may compete with fuel oil which is an alternative to natural gas in the operation of some electric generation plants in the North Baja region. The North Baja System's market is near locations of interest for LNG development companies who may be interested in delivering foreign natural gas supplies to the area.

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Financial Risk Regulatory decisions continue to have a significant impact on the financial returns for existing and future investments in TransCanada's Canadian wholly-owned pipelines. TransCanada remains concerned the approved financial returns discourage additional investment in existing Canadian natural gas transmission systems. TransCanada had applied for a return of 11 per cent on 40 per cent deemed common equity, both to the NEB in the Canadian Mainline's 2004 Application and to the EUB in the Alberta System's application in the GCOC proceeding. In its GCOC decision, the EUB set a generic ROE of 9.60 per cent for all Alberta utilities for 2004 and a deemed equity thickness for the Alberta System of 35 per cent. Following the FCA's decision, TransCanada revised its 2004 Application to reflect a return of 9.56 per cent based on the NEB formula on 40 per cent common equity. The NEB's deliberations on the 2004 Application respecting these matters are currently under way with a decision expected in second quarter 2005.

The company is cognisant of the views and shares the concerns of credit rating agencies regarding the Canadian regulatory environment. Credit ratings and liquidity have risen to the forefront of investor attention. In light of the developments in the Canadian regulatory environment, there exists a view that current Canadian regulatory policy is eroding the credit worthiness of utilities which, over the long term, could make it increasingly difficult for utilities to access capital on reasonable terms.

Foreign Exchange TransCanada's earnings from GTN, as well as a significant amount of earnings in Other Gas Transmission are generated in U.S. dollars. The performance of the Canadian dollar relative to the U.S. dollar would either positively or negatively impact Gas Transmission's net earnings.

Throughput Risk As transportation contracts expire on Great Lakes, Northern Border and GTN, these pipelines will be more exposed to throughput risk and their revenues will more likely experience increased variability. Throughput risk is created by supply availability, economic activity, weather variability, pipeline competition and pricing of alternative fuels.

Regulation The Alberta System is regulated by the EUB. The remaining Canadian pipelines, other than Ventures LP, are regulated by the NEB. In the U.S., TransCanada's wholly- and partially-owned pipelines are regulated by the FERC. These regulators approve the pipelines' respective ROE, costs of service, capital structures, tolls and system expansions.

GAS TRANSMISSION - OTHER
Operational Excellence TransCanada continued its commitment to operational excellence in 2004 by further advancing initiatives that will improve the company's ability to provide low-cost, reliable and responsive service to customers. TransCanada continues to pursue this strategy in order to become the preferred company that customers choose to connect new natural gas supplies and markets.

In 2004, TransCanada reduced operating and maintenance costs through rationalizing maintenance and streamlining the delivery of services. The company met its ongoing goals in the management of greenhouse gases. TransCanada also achieved a high level of plant operating performance, as measured by the number of operational perfect days on both the Canadian Mainline and the Alberta System.

In 2004, TransCanada maintained high levels of customer satisfaction with the launch of a new website called "Customer Express". Customer Express is integrated into TransCanada's website and provides customers with more efficient access to commercial information needed to make transportation decisions. Customer feedback indicates this new website was very well received. Also, through a collaborative effort with customers, a new long-haul firm transportation service enhancement (FT-RAM) was offered on a one year pilot basis beginning November 1, 2004. The purpose of FT-RAM is to mitigate unutilized demand charges and provide greater flexibility in order to attract and retain contracts for FT service.

In 2005, TransCanada will continue to focus efforts on efficiencies, operational reliability, and environmental and safety performance. Greenhouse gas emissions management programs will continue to receive focused attention. Additional effort will be undertaken in 2005 with respect to improving contractor safety performance.

Safety TransCanada worked closely with regulators, customers and communities during 2004 to ensure the continued safety of employees and the public. Pipeline safety performance in 2004 was excellent with no line-breaks or other serious incidents. Under the approved regulatory models in Canada, expenditures on pipeline integrity have no negative impact on earnings. The company expects to spend approximately $70 million in 2005 for pipeline integrity on its Wholly-Owned Pipelines, which is comparable to amounts spent in 2004. TransCanada continues to use a rigorous risk management system that focuses spending on issues and areas that have the largest impact on maintaining or improving the reliability and safety of the pipeline system.

Environment In 2004, TransCanada continued to conduct activities to increase environmental protection through proactive sampling, remediation and monitoring programs. Compressor stations on the Alberta System have been assessed through the company's Site Assessment, Remediation & Monitoring program. In 2004, TransCanada invested in improved environmental protection measures. This program of actively assessing and addressing environmental issues will continue into the future. In addition, the decommissioning of six Canadian Mainline compressor plants and two Alberta compressor plants was undertaken in 2004, effectively reclaiming each project site.

For information on management of risks with respect to the Gas Transmission business, see the Risk Management section.

GAS TRANSMISSION - OUTLOOK
TransCanada's Gas Transmission business has a long history of providing pipeline capacity to markets and connecting natural gas supply for the company's customers. As the marketplace has evolved and competition has grown, Gas Transmission has focused on providing market-responsive products and services, competitive cost-effective structures and the highest levels of reliability to customers.

TransCanada continues to actively pursue pipeline and natural gas transmission-related development and acquisition opportunities in North America, where these opportunities are driven by strong customer demand and sound economics. The company will continue to evaluate options in a disciplined fashion to maintain a strong financial position.

World geo-political events will have an impact on the level of development of future and existing natural gas supplies worldwide. This could directly impact TransCanada, with the company expanding existing facilities across North America and being involved in the development of alternative natural gas transportation solutions as producers access northern and Atlantic Canada natural gas reserves.

TransCanada is committed to play a key role in northern gas development. While there are many issues to be resolved before this moves forward, TransCanada has advantages including expertise in the design, construction and operation of large diameter pipe in cold weather conditions. TransCanada is also the leading operator of large natural gas turbine compressor stations, owns and operates one of the largest, most sophisticated, remote-controlled pipeline networks in the world and has a solid reputation for safety and reliability. This positions the company well to play a key role in bringing northern gas to market.

In 2005, the company will continue to focus on achieving additional efficiency improvements in all aspects of the business by maintaining focus on operational excellence and leveraging technological advancements. TransCanada will also continue to work collaboratively with all stakeholders on negotiated settlements and the evolution of services that will increase the value of TransCanada's business to customers and shareholders.

Looking forward, as the supply/demand balance tightens, producers will continue to explore and develop new fields, particularly in northeastern B.C. and the central foothills regions of Alberta, as well as unconventional supply such as gas production from CBM reserves. In addition, TransCanada anticipates filing an application in 2005 with the EUB to construct Alberta System facilities required to connect additional natural gas supplies delivered to the Alberta System from the Mackenzie Delta.

TransCanada's earnings from its Canadian wholly-owned pipelines are primarily determined by the average investment base, ROE, deemed common equity and opportunity for incentive earnings. In the short to medium term, the company expects a modest level of investment in these mature assets and therefore anticipates, due to depreciation, a continued decline in the average investment base. Accordingly, without an increase in ROE, deemed common equity or incentive opportunities, future earnings are anticipated to decrease. However, these mature assets will continue to generate strong cash flows that can be redeployed to other projects offering higher returns. Under the current regulatory model, earnings from the Canadian wholly-owned pipelines are not affected by short-term fluctuations in the commodity price of natural gas, changes in throughput volumes or changes in contract levels.

Earnings On February 14, 2005 TransCanada announced it had reached a settlement with its Canadian Mainline shippers regarding 2005 tolls. This settlement essentially establishes an OM&A at-risk model for 2005 and has fixed OM&A at a level comparable to 2004. This OM&A at-risk settlement will provide some opportunity for incentive earnings as TransCanada continues to focus efforts on cost efficiencies in 2005. This settlement also establishes the 2005 ROE for the Canadian Mainline at 9.46 per cent as determined under the NEB formula, and its capital structure for 2005 to be subject to the outcome of the recently concluded hearing of the 2004 Application - Phase II.

In February 2005, TransCanada reached an agreement in principle with its Alberta System shippers on a revenue requirement settlement for the period January 1, 2005 to December 31, 2007. TransCanada is proceeding with finalizing the terms of the settlement with the negotiating parties and anticipates executing the settlement agreement in March 2005. TransCanada expects to file the settlement agreement with the EUB for approval shortly thereafter.

In 2005, there will be a full year's contribution from GTN, which was acquired on November 1, 2004.

Net earnings for Other Gas Transmission in 2005 will be affected by factors such as the level of project development costs and the performance of the Canadian dollar relative to the U.S. dollar.

Capital Expenditures Total capital spending for the Canadian wholly-owned pipelines during 2004 was $132 million. Overall capital spending on the Wholly-Owned Pipelines, including GTN, in 2005 is expected to be approximately $171 million. Capital expenditures on the Edson natural gas storage project are expected to be approximately $150 million in 2005.

Natural Gas Throughput Volumes

(Bcf) 2004 2003 2002
Canadian Mainline (1) 2,621 2,628 2,630
Alberta System (2) 3,909 3,883 4,146
Gas Transmission Northwest System (3) 181    
Foothills System 1,139 1,110 1,098
BC System 360 325 371
Great Lakes
801 856 863
Northern Border 845 850 839
Iroquois 356 341 340
TQM 159 164 175
Ventures LP 136 111 85
Portland 50 53 52
Tuscarora 25 22 20
TransGas 18 16 16

(1) Canadian Mainline deliveries originating at the Alberta border and in Saskatchewan for the year ended December 31, 2004 were 2,017 Bcf (2003 - 2,055 Bcf; 2002 - 2,221 Bcf).
(2) Field receipt volumes for the Alberta System for the year ended December 31, 2004 were 3,952 Bcf (2003 - 3,892 Bcf; 2002 - 4,101 Bcf).
(3) TransCanada acquired GTN on November 1, 2004. The North Baja System's total delivery volumes were 13 Bcf. The delivery volumes represent November and December 2004 throughput.

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