SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C.  20549

 

FORM 6-K

 

REPORT OF FOREIGN PRIVATE ISSUER

PURSUANT TO RULE 13a-16 OR 15d-16 OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the month of January 2006

 

COMMISSION FILE No. 1-31690

 

TransCanada Corporation

(Translation of Registrant’s Name into English)

 

450 – 1 Street S.W., Calgary, Alberta, T2P 5H1, Canada

(Address of Principal Executive Offices)

 

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F.

 

Form 20-F                                           o                                    Form 40-F                                      0;     ý

 

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): o

 

Indicated by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7): o

 

Indicate by check mark whether the registrant by furnishing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.

 

Yes                            o                                    No                                ý

 

Attached as Exhibit 99.1 to this Form 6-K is a copy of the Registrant’s news release of January 31, 2006.  This news release is being furnished, not filed, and will not be incorporated by reference into any registration statement filed by TransCanada Corporation under the Securities Act of 1933, as amended.

 

 



 

SIGNATURES

 

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

 

TRANSCANADA CORPORATION

 

 

 

 

 

 

 

By:

/s/ Russell K. Girling

 

 

 

Russell K. Girling

 

 

Executive Vice-President, Corporate

 

 

Development and Chief Financial Officer

 

 

 

 

 

 

 

By:

/s/ Lee G. Hobbs

 

 

 

Lee G. Hobbs

 

 

Vice-President and Controller

 

 

 

January 31, 2006

 

 

 

2



 

EXHIBIT INDEX

 

99.1

 

A copy of the Registrant’s news release of January 31, 2006.

 

3


Exhibit 99.1

 

News Release dated January 31, 2006

 

 
TransCanada Corporation
 

Media Inquiries:

 

Jennifer Varey

(403) 920-7859

 

 

 

(800) 608-7859

Analyst Inquiries:

 

David Moneta/Myles Dougan

(403) 920-7911

 

News Release

 

TransCanada Reports 2005 Net Income of $1.2 Billion

Board of Directors Increases Quarterly Dividend

 

CALGARY, Alberta –January 31, 2006 – (TSX: TRP) (NYSE: TRP)

 

Fourth Quarter and Year-End 2005 Financial Highlights

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

 

                  Quarterly dividend of $0.32 per common share declared by the Board of Directors, an increase of five per cent

                  Net income, excluding gains, for fourth quarter 2005 of $235 million or $0.48 per share, an increase of 27 per cent

                  Net income, excluding gains, for the year ended December 31, 2005 of $852 million or $1.75 per share, an increase of eight per cent

                  Funds generated from operations for fourth quarter 2005 of $530 million, an increase of 12 per cent; for the year ended December 31, 2005, $1,951 million, an increase of 15 per cent

 

The Board of Directors of TransCanada Corporation (TransCanada or the company) today declared a quarterly dividend of $0.32 per common share for the quarter ending March 31, 2006, a five per cent increase over the $0.305 paid in each of the previous four quarters. The dividend is payable on April 28, 2006 to shareholders of record at the close of business on March 31, 2006. This is the sixth consecutive annual increase in the common share dividend.

 

TransCanada today announced net income and net income from continuing operations (net earnings) for fourth quarter 2005 of $350 million or $0.72 per share.  Excluding an after-tax gain of $115 million or $0.24 per share from the sale of the company’s interest in PT Paiton Energy Company (Paiton Energy), net earnings were $235 million or $0.48 per share, an increase of $50 million or $0.10 per share compared to $185 million or $0.38 per share for fourth quarter 2004.

 

For the year ended December 31, 2005, TransCanada’s net income was $1,209 million or $2.49 per share compared to $1,032 million or $2.13 per share for 2004.  Net earnings for 2005 included gains

 



 

related to the sales of TransCanada Power, L.P. (Power LP), Paiton Energy and units of TC PipeLines, LP (PipeLines, LP), while net earnings for 2004 included gains on sales of the ManChief and Curtis Palmer assets to Power LP and the company’s equity interest in Millenium.  Excluding total gains of $357 million recorded in 2005 and total gains of $194 million recorded in 2004, net earnings for 2005 of $852 million or $1.75 per share increased $66 million or $0.13 per share compared to 2004.

 

Funds generated from operations for fourth quarter 2005 were $530 million, an increase of $55 million compared to fourth quarter 2004.  Funds generated from operations for the year ended December 31, 2005 were $1,951 million, an increase of $248 million compared to 2004. 

 

“TransCanada’s strong 2005 results are the direct result of significant capital investments over the past six years,” said Hal Kvisle, TransCanada’s chief executive officer.  “We have invested approximately $8.5 billion over that period to grow our North American gas transmission and power businesses.  In doing so, we have sustained our gas transmission earnings and built a substantial and profitable power generation business.

 

“Events over the past year have reinforced the critical need for new gas and power infrastructure in many parts of North America.  TransCanada continues to play a vital role in the continental energy market through our extensive natural gas transmission network and our growing fleet of power generation facilities,” said Mr. Kvisle.

 

“In 2005, TransCanada invested approximately $2.1 billion in our core businesses.  Notable acquisitions included the Sheerness Power Purchase Arrangement and the Northeast US Hydro assets. Key development projects include Bruce Power, the Bécancour cogeneration plant, the Cartier Wind power project and the Keystone oil pipeline. Longer-term initiatives relate to the transmission of northern natural gas and the development of liquefied natural gas facilities. Acquisitions, active projects and longer-term initiatives will all contribute to further strengthening our position as a leading North American energy infrastructure company.

 

“Our success is the direct result of our expertise in our core businesses, our experience in the responsible and reliable operation of large-scale energy infrastructure, and our financial strength. For our shareholders, that has meant another year of solid growth in earnings and cash flow, and a total annual return on their investment of approximately 28 per cent. For the sixth year in a row, confidence in our growth prospects has enabled TransCanada’s Board of Directors to increase the dividend paid to shareholders to $1.28 on an annual basis,” said Mr. Kvisle.

 

During the fourth quarter of 2005 and the first month of 2006, TransCanada:

 



 

FOURTH QUARTER NEWS RELEASE 2005

 

                  Announced in October that Bruce Power (being the collective investments in Bruce Power A L.P. (Bruce A) and Bruce Power L.P. (Bruce B)) and the Ontario Power Authority (OPA), a Crown Corporation of the Province of Ontario, entered into a long-term agreement on the restart and refurbishment of the Bruce A units.  The capital program for the restart and refurbishment work is expected to total approximately $4.25 billion.  As owner of a 47.9 per cent interest in the newly formed Bruce A (along with BPC Generation Infrastructure Trust (BPC) – 47.9 per cent, and the Power Workers’ Union Trust No. 1 and The Society of Energy Professionals Trust – together, 4.2 per cent) TransCanada’s approximate share of the capital program is $2.125 billion and will be financed through capital contributions to 2011.  With the restart of Units 1 and 2, Bruce Power’s output capacity is expected to rise by approximately 1,500 megawatts (MW) to more than 6,200 MW.

 

                  In November, signed a Memorandum of Understanding with ConocoPhillips Company and ConocoPhillips Pipe Line Company (CPPL) (a wholly owned subsidiary of ConocoPhillips Company) which commits ConocoPhillips Company to ship crude oil on the proposed Keystone oil pipeline (Keystone), and gives CPPL the right to acquire up to a fifty per cent participating interest in the pipeline.  On January 31, 2006, TransCanada announced it has secured firm, long-term contracts totalling 340,000 barrels per day through the binding Open Season held during the fourth quarter. The Keystone pipeline, expected to cost approximately US$2.1 billion, will be capable of transporting approximately 435,000 barrels per day of crude oil from Hardisty, Alberta to Patoka, Illinois through a 2,950 kilometre pipeline system.

 

                  Acquired the remaining rights and obligations of the 756 megawatt Sheerness Power Purchase Arrangement (PPA) from the Alberta Balancing Pool for $585 million. The remaining term of the PPA is approximately 15 years.  The acquisition closed on December 30, 2005. 

 

                  Closed the sale of its 11 per cent interest in Paiton Energy to subsidiaries of The Tokyo Electric Power Company for gross proceeds of US$103 million ($122 million). Paiton Energy owns two 615 MW coal-fired power plants in East Java, Indonesia.

 

                  Received support from the Canadian Association of Petroleum Producers (CAPP) and other stakeholders for an increase in the deemed common equity ratio from 30 per cent to 36 per cent on TransCanada’s Foothills and BC Systems, effective January 1, 2006.  On December 21, 2005, The National Energy Board (NEB) approved the Foothills System 2006 tolls, reflecting a deemed common equity of 36 per cent, as final tolls.  BC System tolls have been authorized on an interim basis, with no issues raised with respect to the capital structure.

 

                  Continued to advance the Bécancour and Cartier Wind power projects.  Construction of the 550 MW Bécancour cogeneration

 

3



 

plant near Trois Rivières, Québec remains on schedule to begin operations in September 2006.  The 740 MW Cartier Wind project, 62 per cent owned by TransCanada, continued to award construction contracts in November and December and construction is scheduled to begin in March 2006.  Located in the Gaspésie region of Québec, the first of the six projects that make up Cartier Wind is anticipated to be operational beginning in December 2006 with the remaining projects continuing through 2012. 

 

                  Issued, in January 2006, through its wholly owned subsidiary TransCanada PipeLines Limited (TCPL), $300 million of five-year medium-term notes bearing interest of 4.3 per cent under its Canadian base shelf program.  Proceeds from the offering were used to reduce commercial paper outstanding.

 

                  On behalf of the Broadwater Energy project, filed a formal application on January 30, 2006 with the U.S. Federal Energy Regulatory Commission (FERC) for federal approval to construct and operate the Broadwater project.  The proposed facility, which would be located in the New York State waters of Long Island Sound, would be capable of receiving, storing, and re-gasifying imported liquefied natural gas with an average annual send-out capacity of approximately one billion cubic feet (bcf) a day of natural gas. The estimated cost of construction is US$700 million to US$1 billion.  Broadwater is being developed jointly by TransCanada and Shell US Gas and Power.

 

                  The Mackenzie Gas Pipeline Project has continued to progress.  The public hearings phase of the regulatory process commenced in late January 2006 and is expected to continue throughout the year.

 

4



 

Results of Operations

 

Operating Results

 

Three months ended December 31

 

Year ended December 31

 

(millions of dollars)

 

2005

 

2004

 

2005

 

2004

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

1,771

 

1,480

 

6,124

 

5,497

 

Net Income

 

 

 

 

 

 

 

 

 

Continuing operations

 

350

 

185

 

1,209

 

980

 

Discontinued operations

 

 

 

 

52

 

 

 

350

 

185

 

1,209

 

1,032

 

Cash Flows

 

 

 

 

 

 

 

 

 

Funds generated from operations

 

530

 

475

 

1,951

 

1,703

 

Increase/(decrease) in working capital

 

124

 

(23

)

(49

)

29

 

Net cash provided by operations

 

654

 

452

 

1,902

 

1,732

 

 

 

 

 

 

 

 

 

 

 

Capital expenditures

 

(345

)

(203

)

(754

)

(530

)

Acquisitions, net of cash acquired

 

(685

)

(1,453

)

(1,317

)

(1,516

)

Dispositions, net of current tax

 

125

 

2

 

671

 

410

 

 

 

 

Three months ended December 31

 

Year ended December 31

 

Common Share Statistics

 

2005

 

2004

 

2005

 

2004

 

 

 

 

 

 

 

 

 

 

 

Net Income Per Share – Basic

 

 

 

 

 

 

 

 

 

Continuing operations

 

$

0.72

 

$

0.38

 

$

2.49

 

$

2.02

 

Discontinued operations

 

 

 

 

0.11

 

 

 

$

0.72

 

$

0.38

 

$

2.49

 

$

2.13

 

 

 

 

 

 

 

 

 

 

 

Dividends Declared Per Share

 

$

0.305

 

$

0.29

 

$

1.22

 

$

1.16

 

 

 

 

 

 

 

 

 

 

 

Common Shares Outstanding (millions)

 

 

 

 

 

 

 

 

 

Average for the period – Basic

 

487.1

 

484.7

 

486.2

 

484.1

 

End of period

 

487.2

 

484.9

 

487.2

 

484.9

 

 

5



 

Consolidated

 

Segment Results-at-a–Glance

 

Three months ended December 31

 

Year ended December 31

 

(millions of dollars except per share amounts)

 

2005

 

2004

 

2005

 

2004

 

Gas Transmission Net Earnings

 

 

 

 

 

 

 

 

 

Excluding gains

 

160

 

157

 

635

 

579

 

Gain on sale of PipeLines LPunits

 

 

 

49

 

 

Gain on sale of Millennium

 

 

 

 

7

 

 

 

160

 

157

 

684

 

586

 

Power Net Earnings

 

 

 

 

 

 

 

 

 

Excluding gains

 

82

 

31

 

253

 

209

 

Gain on sale of Paiton Energy

 

115

 

 

115

 

 

Gains related to Power L P

 

 

 

193

 

187

 

 

 

197

 

31

 

561

 

396

 

Corporate

 

(7

)

(3

)

(36

)

(2

)

 

 

 

 

 

 

 

 

 

 

Net Income

 

 

 

 

 

 

 

 

 

Continuing Operations (1)

 

350

 

185

 

1,209

 

980

 

Discontinued Operations

 

 

 

 

52

 

 

 

350

 

185

 

1,209

 

1,032

 

Net Income Per Share

 

 

 

 

 

 

 

 

 

Continuing Operations (2)

 

$

0.72

 

$

0.38

 

$

2.49

 

$

2.02

 

Discontinued Operations

 

 

 

 

0.11

 

Basic

 

$

0.72

 

$

0.38

 

$

2.49

 

$

2.13

 

Diluted

 

$

0.71

 

$

0.38

 

$

2.47

 

$

2.12

 

(1) Net Income from Continuing Operations:

 

 

 

 

 

 

 

 

 

Excluding gains

 

235

 

185

 

852

 

786

 

Gains related to Paiton Energy, PipeLines LP, Power LP and Millennium

 

115

 

 

357

 

194

 

 

 

350

 

185

 

1,209

 

980

 

(2) Net Income Per Share from Continuing Operations :

 

 

 

 

 

 

 

 

 

Excluding gains

 

$

0.48

 

$

0.38

 

$

1.75

 

$

1.62

 

Gains related to Paiton Energy, PipeLines LP, Power LP and Millennium

 

0.24

 

 

0.74

 

0.40

 

 

 

$

0.72

 

$

0.38

 

$

2.49

 

$

2.02

 

 

Net income and net earnings for fourth quarter 2005 of $350 million or $0.72 per share increased by $165 million or $0.34 per share compared to $185 million or $0.38 per share for fourth quarter 2004. This increase was due to significantly higher net earnings from the Power business, including an after-tax gain of $115 million or $0.24 per share from the sale of Paiton Energy.

 

Excluding the $115 million gain on sale of Paiton Energy, net income and net earnings for fourth quarter 2005 increased $50 million or $0.10 per share compared to fourth quarter 2004, to $235 million or $0.48 per share.  This was due to increases of $51 million and $3 million in net earnings from the Power and Gas Transmission businesses, respectively, partially offset by an increase of $4 million in net expenses in the Corporate segment.

 

6



 

The increase in Power’s net earnings was primarily due to higher operating and other income from Bruce Power and Eastern Operations.  The increase in net earnings from the Gas Transmission business was primarily due to higher earnings from the Gas Transmission Northwest System and the North Baja System (collectively GTN), acquired on November 1, 2004.  Corporate’s net expenses increased in fourth quarter 2005 compared to fourth quarter 2004 primarily due to increased net interest costs, partially offset by an income tax refund in fourth quarter 2005.

 

TransCanada’s net income for the year ended December 31, 2005 was $1,209 million or $2.49 per share compared to $1,032 million or $2.13 per share for 2004. Net income for 2004 included net income from discontinued operations of $52 million or $0.11 per share.

 

TransCanada’s net earnings for the year ended December 31, 2005 were $1,209 million or $2.49 per share compared to $980 million or $2.02 per share for 2004.  Net earnings for 2005 included after-tax gains of $193 million on the sale of the company’s interest in Power LP, $115 million on the sale of Paiton Energy and $49 million on the sale of PipeLines LP units, while net earnings for 2004 included after-tax gains of $187 million on the sale of the ManChief and Curtis Palmer assets to Power LP and the recognition of dilution gains resulting from a reduction in TransCanada’s ownership interest in Power LP and other previously deferred gains, as well as a $7 million after-tax gain on sale of the company’s equity interest in Millennium.

 

Excluding the total gains of $357 million recorded in 2005 and total gains of $194 million recorded in 2004, net earnings for 2005 of $852 million or $1.75 per share increased $66 million or $0.13 per share compared to 2004.  This was mainly due to an increase in net earnings from the Gas Transmission and Power businesses, partially offset by an increase in net expenses in the Corporate segment.

 

Excluding the gains on sales of PipeLines LP units in 2005 and the Millennium interest in 2004, the $56 million increase in net earnings from the Gas Transmission business for 2005 compared to 2004 was primarily attributable to a $57 million increase as a result of a full year of net earnings from GTN.  In addition, Gas Transmission’s net earnings for 2005 included approximately $35 million ($13 million related to 2004 and $22 million related to the year ended December 31, 2005) as a result of the April 2005 NEB decision on the Canadian Mainline’s 2004 Tolls and Tariff Application (Phase II).  This decision dealt with capital structure and included an increase in the deemed common equity ratio to 36 per cent from 33 per cent for 2004, which was also effective for 2005 under the 2005 tolls settlement.  The increase in Canadian Mainline’s earnings for 2005 as a result of this NEB decision was partially offset by a combination of a lower average investment base, lower earnings related to operating cost savings and a decrease in the approved rate of return on common equity (ROE) in 2005 compared to 2004.  These increases in net earnings

 

7



 

were partially offset by lower earnings from TransCanada’s Other Gas Transmission businesses.

 

Excluding the above-mentioned gains related to the company’s investments in Power LP in 2004 and 2005 and Paiton Energy in 2005, Power’s net earnings for 2005 increased $44 million as a result of higher operating and other income from Bruce Power and Eastern Operations, partially offset by lower contributions from Western Operations and higher general, administrative, support costs and other.

 

The increase in net expenses of $34 million in the Corporate segment in 2005 compared to 2004 was primarily due to increased interest expense on higher average long-term debt and commercial paper balances in 2005 as well as the release in third quarter 2004 of previously established restructuring provisions.

 

Funds generated from operations of $530 million for fourth quarter 2005 increased $55 million compared to fourth quarter 2004.  Funds generated from operations of $1,951 million for the year ended December 31, 2005 increased $248 million when compared to 2004.

 

Gas Transmission

 

The Gas Transmission business generated net earnings of $160 million and $684 million for the three months and year ended December 31, 2005, respectively, compared to $157 million and $586 million for the comparable periods in 2004.

 

8



 

Gas Transmission Results-at-a–Glance

 

Three months ended December 31

 

Year ended December 31

 

(millions of dollars)

 

2005

 

2004

 

2005

 

2004

 

Wholly-Owned Pipelines

 

 

 

 

 

 

 

 

 

Canadian Mainline

 

67

 

71

 

283

 

272

 

Alberta System

 

38

 

40

 

150

 

150

 

GTN (1)

 

18

 

14

 

71

 

14

 

Foothills System

 

5

 

5

 

21

 

22

 

BC System

 

1

 

2

 

6

 

7

 

 

 

129

 

132

 

531

 

465

 

Other Gas Transmission

 

 

 

 

 

 

 

 

 

Great Lakes

 

10

 

12

 

46

 

55

 

Iroquois

 

3

 

3

 

17

 

17

 

PipeLines LP

 

2

 

3

 

9

 

16

 

Portland

 

4

 

4

 

11

 

10

 

Ventures LP

 

3

 

5

 

12

 

15

 

TQM

 

2

 

2

 

7

 

8

 

CrossAlta

 

7

 

7

 

19

 

13

 

TransGas

 

3

 

2

 

11

 

11

 

Northern Development

 

(1

)

(3

)

(4

)

(6

)

General, administrative, support costs and other

 

(2

)

(10

)

(24

)

(25

)

 

 

31

 

25

 

104

 

114

 

Gain on sale of PipeLines LP units

 

 

 

49

 

 

Gain on sale of Millennium

 

 

 

 

7

 

 

 

31

 

25

 

153

 

121

 

Net Earnings

 

160

 

157

 

684

 

586

 

 


(1) TransCanada acquired GTN on November 1, 2004.

 

Wholly-Owned Pipelines

 

The Canadian Mainline’s fourth quarter 2005 net earnings decreased $4 million compared to fourth quarter 2004. The decrease in net earnings was due to a combination of a lower average investment base in 2005, a lower approved rate of return on common equity of 9.46 per cent in 2005 compared to 9.56 per cent in 2004 and lower operating cost savings in 2005 compared to 2004, partially offset by an increase in the deemed common equity ratio. The NEB’s decision on the Canadian Mainline’s 2004 Tolls and Tariff Application (Phase II) in April 2005 included an increase in the deemed common equity ratio from 33 to 36 per cent for 2004 which was also effective for 2005 under the 2005 tolls settlement. Net earnings for the year ended December 31, 2005 increased $11 million compared to 2004. As a result of the NEB decision that increased the deemed common equity to 36 per cent from 33 per cent, Canadian Mainline’s 2005 net earnings increased $35 million ($13 million related to 2004 and $22 million related to 2005) compared to 2004 net earnings.  This earnings increase was partially offset by the combination of a lower average investment base, lower operating cost savings in 2005 compared to 2004 and the lower approved ROE in 2005.

 

9



 

The Alberta System’s net earnings of $38 million in fourth quarter 2005 decreased $2 million compared to $40 million in fourth quarter 2004.  Net earnings of $150 million for the year ended December 31, 2005 were consistent with net earnings for 2004.  The decrease in fourth quarter net earnings was primarily due to a lower investment base and a lower approved ROE in 2005.  Net earnings for the year remained unchanged as the impacts of a lower investment base and a lower approved ROE in 2005 were offset by the impact on 2004 net earnings of disallowed costs in the Alberta Energy and Utilities Board (EUB) decision on Phase 1 of the 2004 General Rate Application (GRA).  Net earnings in 2004 and 2005 reflect an ROE of 9.60 and 9.50 per cent,  respectively, as prescribed by the EUB, on deemed common equity of 35 per cent.

 

GTN was acquired by TransCanada on November 1, 2004 and generated net earnings of $18 million and $71 million for the three months and year ended December 31, 2005, respectively, compared to $14 million for the two months ended December 31, 2004.

 

Operating Statistics

 

 

 

Canadian

 

 

 

 

 

Gas Transmission

 

 

 

 

 

 

 

 

 

 

Year ended

 

Mainline (1)

 

Alberta System (2)

 

Northwest System (3)

 

Foothills System

 

BC System

 

 

December 31

 

2005

 

2004

 

2005

 

2004

 

2005

 

2004

 

2005

 

2004

 

2005

 

2004

 

Average investment base ($ millions)

 

7,807

 

8,196

 

4,446

 

4,619

 

n/a

 

n/a

 

680

 

714

 

216

 

228

 

Delivery volumes (Bcf)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

2,997

 

2,621

 

3,999

 

3,909

 

777

 

181

 

1,051

 

1,139

 

321

 

360

 

Average per day

 

8.2

 

7.2

 

11.0

 

10.7

 

2.1

 

3.0

 

2.9

 

3.1

 

0.9

 

1.0

 

 


(1)   Canadian Mainline deliveries originating at the Alberta border and in Saskatchewan in 2005 were 2,215 Bcf (2004 – 2,017 Bcf); average per day was 6.1 Bcf (2004 – 5.5 Bcf).

(2)   Field receipt volumes for the Alberta System in 2005 were 4,034 Bcf (2004 – 3,952 Bcf); average per day was 11.1 Bcf (2004 – 10.8 Bcf).

(3)   TransCanada acquired the Gas Transmission Northwest System on November 1, 2004.  The delivery volumes for 2004 represent November and December 2004 throughput. The system is currently operating under a fixed rate model approved by FERC and, as a result, the system’s current results are not dependent on average investment base.

 

Other Gas Transmission

 

TransCanada’s proportionate share of net earnings from Other Gas Transmission was $31 million for the three months ended December 31, 2005 compared to $25 million for the same period in 2004.  The $6 million increase compared to the prior period was primarily due to lower project development costs expensed in fourth quarter 2005 resulting from capitalization of costs of the Broadwater and Keystone projects in 2005 and higher earnings from Gas Pacifico.  These increases were partially offset by lower earnings from Great Lakes and Ventures LP.

 

Net earnings from Other Gas Transmission for the year ended December 31, 2005 were $153 million compared to $121 million for 2004.  Excluding the gain on sale of PipeLines LP units in 2005 and Millennium in 2004, net earnings for 2005 were $10 million

 

10



 

lower compared to 2004.  The decrease was due to lower net earnings from Great Lakes as a result of lower short-term revenues and higher operating and maintenance costs, and lower net earnings from PipeLines LP as a result of the reduced ownership interest.  Results were also negatively impacted by a weaker U.S. dollar in 2005.  These decreases were partially offset by higher earnings from CrossAlta as a result of increased capacity and favourable natural gas storage market conditions in 2005.

 

As at December 31, 2005, TransCanada had $87 million of advances to the Aboriginal Pipeline Group (APG) with respect to the Mackenzie Gas Pipeline Project, and had capitalized $19 million of costs related to the Broadwater project and $6 million related to the Keystone project.

 

Power

 

Power Results-at-a–Glance

 

Three months ended December 31

 

Year ended December 31

 

(millions of dollars)

 

2005

 

2004

 

2005

 

2004

 

Bruce Power

 

53

 

5

 

195

 

130

 

Western operations

 

33

 

25

 

123

 

138

 

Eastern operations

 

68

 

31

 

137

 

108

 

Power LP investment

 

 

7

 

29

 

29

 

General, administrative, support costs and other

 

(28

)

(19

)

(102

)

(89

)

Operating and other income

 

126

 

49

 

382

 

316

 

Financial charges

 

(4

)

(4

)

(11

)

(13

)

Income taxes

 

(40

)

(14

)

(118

)

(94

)

 

 

82

 

31

 

253

 

209

 

Gains related to Power LP and Paiton Energy

 

115

 

 

308

 

187

 

Net Earnings

 

197

 

31

 

561

 

396

 

 

Power’s net earnings of $197 million in fourth quarter 2005 increased $166 million compared to $31 million in fourth quarter 2004.  The gain on sale of Paiton Energy accounted for $115 million of this increase.  Excluding this gain, Power’s net earnings in fourth quarter 2005 of $82 million increased $51 million compared to the same period in 2004, primarily due to higher operating and other income from Bruce Power and Eastern Operations.

 

Bruce Power’s contribution to operating and other income increased by $48 million in fourth quarter 2005 compared to fourth quarter 2004, primarily due to higher realized power prices on uncontracted volumes sold into Ontario’s wholesale spot market, higher generation volumes and an increased ownership interest in the Bruce A facilities effective October 31, 2005.

 

Western Operations’ operating and other income was $8 million higher in fourth quarter 2005 compared to fourth quarter 2004 primarily due to increased margins in fourth quarter 2005 as a

 

11



 

result of higher market heat rates on uncontracted volumes of power sold.  Partially offsetting this increase was lower contributions from the Bear Creek cogeneration facility which remained on an unplanned outage throughout the quarter.

 

Eastern Operations’ operating and other income was $37 million higher in fourth quarter 2005 compared to fourth quarter 2004 primarily due to contributions from TransCanada Hydro Northeast, Inc. (TC Hydro), which holds the hydroelectric generation assets acquired from USGen New England, Inc. on April 1, 2005, and from the Grandview cogeneration facility placed into service in January 2005.  Partially offsetting these increases was a fourth quarter 2004 positive impact due to a restructuring transaction relating to Ocean State Power (OSP) power purchase contracts and the loss of operating income associated with the expiration of certain long-term sales contracts in 2004.

 

General, administrative, support costs and other increased $9 million in fourth quarter 2005 compared to fourth quarter 2004 primarily due to higher business development costs expensed in 2005 and the positive impact in fourth quarter 2004 of the recognition of unrealized foreign exchange gains on Power LP’s U.S. dollar denominated debt. 

 

Net earnings for the year ended December 31, 2005 of $561 million increased $165 million compared to $396 million in 2004.  Excluding the gain on sale of Paiton Energy of $115 million in 2005 and gains related to Power LP of $193 million and $187 million in 2005 and 2004, respectively, Power’s net earnings for the year ended December 31, 2005 of $253 million increased $44 million compared to $209 million in 2004.  The increase was primarily due to higher operating and other income from Bruce Power and Eastern Operations, partially offset by reduced contributions from Western Operations and higher general, administrative, support costs and other.

 

Bruce Power

 

On October 31, 2005, Bruce Power and the OPA, completed a long-term agreement whereby Bruce A will 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.  As a result of the agreement between Bruce Power and the OPA, and Cameco Corporation’s decision not to participate in the restart and refurbishment program, a new partnership was created. The new Bruce A partnership subleases the Bruce A facilities, which are comprised of Units 1 to 4, from Bruce B. The effect of these transactions was that TransCanada and BPC each incurred a net cash outlay of approximately $100 million after each receiving a special distribution of $200 million.  As at December 31, 2005, TransCanada and BPC each owned a 47.9 per cent interest in Bruce A.  The remaining 4.2 per cent is owned by the Power Workers’ Union Trust No. 1 and The Society of Energy Professionals Trust.

 

12



 

The day-to-day operations of the Bruce Power facility are expected to be unaffected by the formation of the Bruce A partnership and TransCanada continues to own 31.6 per cent of the Bruce B Units 5 to 8.

 

Upon reorganizing, 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 the full six-unit operation for all periods.  The Bruce Power information below includes adjustments to eliminate the effects of intercompany transactions between Bruce A and Bruce B.

 

13



 

 

Bruce Power Results-at-a-Glance

 

 

 

Three months ended December 31

 

Year ended December 31

 

(millions of dollars)

 

2005

 

2004

 

2005

 

2004

 

Bruce Power (100 per cent basis)

 

 

 

 

 

 

 

 

 

Revenues

 

 

 

 

 

 

 

 

 

Power

 

476

 

351

 

1,907

 

1,563

 

Other (1)

 

13

 

4

 

35

 

20

 

 

 

489

 

355

 

1,942

 

1,583

 

Operating expenses

 

 

 

 

 

 

 

 

 

Operations and maintenance

 

(231

)

(244

)

(871

)

(793

)

Fuel

 

(19

)

(17

)

(77

)

(68

)

Supplemental rent

 

(41

)

(40

)

(164

)

(156

)

Depreciation and amortization

 

(53

)

(44

)

(198

)

(161

)

 

 

(344

)

(345

)

(1,310

)

(1,178

)

Operating income

 

145

 

10

 

632

 

405

 

Financial charges under equity accounting – to October 31, 2005

 

(6

)

(17

)

(58

)

(67

)

 

 

139

 

(7

)

574

 

338

 

TransCanada’s proportionate share

 

51

 

(2

)

188

 

107

 

Adjustments

 

2

 

7

 

7

 

23

 

TransCanada’s operating and other income from

 

 

 

 

 

 

 

 

 

Bruce Power (2)

 

53

 

5

 

195

 

130

 

 

 

 

 

 

 

 

 

 

 

Bruce Power – Other Information

 

 

 

 

 

 

 

 

 

Plant availability

 

79

%

72

%

80

%

82

%

Sales volumes (GWh) (3)

 

 

 

 

 

 

 

 

 

Bruce Power – 100 per cent

 

8,300

 

7,500

 

32,900

 

33,600

 

TransCanada’s proportionate share

 

2,946

 

2,351

 

10,732

 

10,608

 

Results per MWh (4)

 

 

 

 

 

 

 

 

 

Power revenues

 

$

57

 

$

47

 

$

58

 

$

47

 

Fuel

 

$

2

 

$

2

 

$

2

 

$

2

 

Total operating expenses (5)

 

$

41

 

$

46

 

$

40

 

$

35

 

Percentage of output sold to spot market

 

35

%

47

%

49

%

52

%

 


(1)   Includes fuel cost recoveries for Bruce A of $4 million for the three months and year ended December 31, 2005.

(2)   TransCanada’s consolidated equity income includes $168 million and $26 million which represents TransCanada’s 31.6 per cent share of Bruce Power earnings for the ten months and one month ended October 31, 2005, respectively.

(3)   Gigawatt hours

(4)   Megawatt hours

(5)   Net of cost recoveries

 

14



 

TransCanada’s operating and other income from its combined investment in Bruce Power increased $48 million in fourth quarter 2005 compared to fourth quarter 2004, primarily due to higher realized power prices on uncontracted volumes sold into Ontario’s wholesale spot market, higher generation volumes and an increased ownership interest in Bruce A.  TransCanada’s share of Bruce Power’s combined generation for fourth quarter 2005 increased 595 GWh to 2,946 GWh compared to fourth quarter 2004 generation of 2,351 GWh as a result of fewer planned maintenance outage days in fourth quarter 2005 than during the same period in 2004.

 

Combined Bruce Power prices achieved during fourth quarter 2005 (excluding other revenues) were $57 per MWh, compared to $47 per MWh in fourth quarter 2004.  Combined Bruce Power operating expenses (net of fuel cost recoveries) in fourth quarter 2005 decreased to $41 per MWh from $46 MWh in fourth quarter 2004 primarily due to increased output in fourth quarter 2005.

 

Approximately 66 reactor days of planned maintenance outages as well as 35 reactor days of unplanned outages occurred on the six operating units in fourth quarter 2005.  In fourth quarter 2004, Bruce Power experienced 100 reactor days of planned maintenance outages and 35 reactor days of unplanned outages.  The Bruce Power units ran at a combined average availability of 79 per cent in fourth quarter 2005, compared to a 72 per cent average availability during fourth quarter 2004.  Unit 5 returned to service in December 2005 after a 75 day outage, including a nine day unplanned extension to the outage.  During fourth quarter 2005, there were minor unplanned outages on Units 3, 4 and 6.  All of those units were returned to service during the quarter and as at December 31, 2005, all six Bruce Power units were operating.

 

TransCanada’s operating and other income from its combined investment in Bruce Power for the year ended December 31, 2005 was $195 million compared to $130 million for 2004.  The increase of $65 million was primarily due to higher realized prices in 2005 and was offset in part by higher maintenance costs, higher depreciation and lower capitalization of labour and other in-house costs following the restart of Unit 3 in first quarter 2004.  Adjustments to TransCanada’s combined interest in Bruce Power’s income before income taxes for the three months and year ended December 31, 2005 were lower than in the comparable periods in 2004 primarily due to a lower amortization of the purchase price allocated to the fair value of sales contracts in place at the time of acquisition.

 

Combined Bruce Power prices achieved during the year ended December 31, 2005 (excluding other revenues) were $58 per MWh compared to $47 per MWh in 2004.  Bruce Power’s combined operating expenses (net of fuel cost recoveries) increased to $40 per MWh for the year ended December 31, 2005 from $35 per MWh in 2004.  This was primarily the result of one additional planned maintenance outage in 2005 compared to 2004 as well as higher maintenance costs, higher depreciation and lower capitalization of

 

15



 

labour and other in-house costs following the restart of Unit 3.  The Bruce units ran at a combined average availability of 80 per cent in 2005, compared to 82 per cent in 2004.

 

Income from Bruce B is directly impacted by fluctuations in wholesale spot market prices for electricity and income from both Bruce A and Bruce B units is impacted by overall plant availability which, in turn, is impacted by scheduled and unscheduled maintenance.  To reduce its exposure to spot market prices, Bruce B has entered into fixed price sales contracts to sell forward approximately 13 terawatt hours (TWh) of 2006 output and 3.6 TWh of 2007 output.  As a result of the contract with the OPA, all of the output from Bruce A will be sold at a fixed price of $57.37 per MWh, before recovery of fuel costs from the OPA.  Under the terms of the arrangement between Bruce A and the OPA, effective October 31, 2005 Bruce A receives a contract price for power generated, where the price is adjusted for inflation annually on April 1 and capital cost variances associated with the restart and refurbishment project but will not vary with changes in the wholesale price of power in the Ontario market.  The Bruce A fixed price may also be adjusted to reflect cost savings and cost overruns associated with the Bruce A restart and refurbishment project.  As part of this contract, sales from the Bruce B Units 5 to 8 are subject to a floor price of $45 per MWh, adjusted annually for inflation on April 1.  Receipts by Bruce B under this floor price mechanism are refundable if prices subsequently increase above the floor price.

 

The overall plant availability percentage in 2006, for planning purposes, is expected to be in the low 90s for the four Bruce B units and in the low 80s for the two operating Bruce A units.  A planned outage on Bruce A Unit 3 is scheduled to last approximately one month during first quarter 2006 and a two month planned maintenance outage of Bruce A Unit 4 is expected to commence in second quarter 2006.  The only planned maintenance outage for 2006 for Bruce B is an approximate two month outage scheduled for Unit 8 beginning in third quarter 2006.

 

Bruce Power made cash distributions, excluding the special distribution, of $185 million to its partners in fourth quarter 2005. TransCanada’s share was $58 million.  For the year ended December 31, 2005, cash distributions, excluding the special distribution, to partners were $400 million of which TransCanada’s share was $126 million.  No distributions were made to partners in 2004.  The 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 project.

 

Bruce Power’s capital program for the restart and refurbishment work is expected to total approximately $4.25 billion and TransCanada’s approximate $2.125 billion share will be financed through capital contributions to 2011.  A capital cost risk and reward sharing schedule with OPA is in place for spending below or in excess of the $4.25 billion base case estimate.  Work to

 

16



 

restart Units 1 and 2 has commenced with the first unit expected to be online in 2009, subject to approval by the Canadian Nuclear Safety Commission.  Restarting Units 1 and 2, which have a combined capacity of approximately 1,500 MW, will boost the Bruce facilities’ overall output to more than 6,200 MW.  As at December 31, 2005, Bruce A had capitalized $324 million with respect to the refurbishment project.

 

Western Operations

 

Western Operations Results-at-a–Glance (1)

 

 

 

Three months ended December 31

 

Year ended December 31

 

(millions of dollars)

 

2005

 

2004

 

2005

 

2004

 

Revenue

 

 

 

 

 

 

 

 

 

Power

 

235

 

160

 

715

 

606

 

Other (2)

 

50

 

33

 

158

 

120

 

 

 

285

 

193

 

873

 

726

 

Cost of sales

 

 

 

 

 

 

 

 

 

Power

 

(163

)

(103

)

(476

)

(377

)

Other (3)

 

(37

)

(17

)

(104

)

(64

)

 

 

(200

)

(120

)

(580

)

(441

)

Other costs and expenses

 

(47

)

(43

)

(149

)

(125

)

Depreciation

 

(5

)

(5

)

(21

)

(22

)

Operating and other income

 

33

 

25

 

123

 

138

 

 


(1)   ManChief is included until April 30, 2004.

(2)   Includes Cancarb Thermax and natural gas sales.

(3)   Includes the cost of natural gas sold.

 

17



 

Western Operations Sales Volumes (1)

 

 

 

Three months ended December 31

 

Year ended December 31

 

(GWh)

 

2005

 

2004

 

2005

 

2004

 

Supply

 

 

 

 

 

 

 

 

 

Generation

 

554

 

673

 

2,245

 

2,105

 

Purchased

 

 

 

 

 

 

 

 

 

Sundance A & B PPAs

 

1,837

 

1,757

 

6,974

 

6,842

 

Other purchases

 

684

 

706

 

2,687

 

2,748

 

 

 

3,075

 

3,136

 

11,906

 

11,695

 

Contracted vs. Spot

 

 

 

 

 

 

 

 

 

Contracted

 

2,804

 

2,848

 

10,374

 

10,705

 

Spot

 

271

 

288

 

1,532

 

990

 

 

 

3,075

 

3,136

 

11,906

 

11,695

 

 


(1) ManChief is included until April 30, 2004.

 

Western Operations’ operating and other income of $33 million in fourth quarter 2005 was $8 million higher compared to fourth quarter 2004.  Operating and other income was higher primarily due to increased margins in fourth quarter 2005 from higher market heat rates on uncontracted volumes of power generated.  The market heat rate is determined by dividing the average price of power per MWh by the average price of natural gas per gigajoule (GJ) for a given period.  Market heat rates increased by approximately 21 per cent in the quarter as a result of an approximate 112 per cent ($61.65 per MWh) increase in spot market power prices in fourth quarter 2005 compared to the same period in 2004, while average spot market natural gas prices in Alberta increased by approximately 75 per cent ($4.60 per GJ). Partially offsetting the positive impact of the increase in market heat rates was lower contributions from the Bear Creek cogeneration facility which remained on an unplanned outage throughout the quarter.  A significant portion of plant generation in Western Operations in 2005 was sold under long-term contract to mitigate price risk, although some output was intentionally not committed under long-term contract to assist in managing the overall portfolio of generation in Alberta.  This approach to portfolio management assists in minimizing costs in situations where TransCanada would otherwise have to purchase electricity in the open market to fulfill its contractual obligations.

 

Operating and other income for the year ended December 31, 2005 was $123 million or $15 million lower compared to $138 million earned in 2004.  This decrease was primarily due to reduced margins in 2005 resulting from overall lower market heat rates on uncontracted volumes of power generated, fee revenues earned in 2004 from Power LP, and lower contributions from Bear Creek.

 

Western Operations’ power sales revenues and power cost of sales increased in fourth quarter 2005 compared to fourth quarter 2004 primarily due to higher realized prices in fourth quarter 2005. Generation volumes of 554 GWh in fourth quarter 2005 decreased 119 GWh compared to fourth quarter 2004 primarily due to a planned maintenance outage in 2005 at MacKay River and an unplanned outage

 

18



 

at Bear Creek.  Bear Creek continued to experience operational difficulties in fourth quarter 2005 and technical evaluation continues regarding a long-term solution.  In fourth quarter of 2005 and 2004, approximately nine per cent of power sales volumes were sold into the spot market.  To reduce its exposure to spot market prices on uncontracted volumes, as at December 31, 2005, Western Operations had fixed price sales contracts to sell approximately 9,800 GWh for 2006 and approximately 6,000 GWh for 2007.

 

Eastern Operations

 

Eastern Operations Results-at-a–Glance (1)

 

 

 

Three months ended December 31

 

Year ended December 31

 

(millions of dollars)

 

2005

 

2004

 

2005

 

2004

 

Revenue

 

 

 

 

 

 

 

 

 

Power

 

125

 

120

 

505

 

535

 

Other (2)

 

158

 

70

 

412

 

238

 

 

 

283

 

190

 

917

 

773

 

Cost of sales

 

 

 

 

 

 

 

 

 

Power

 

(32

)

(60

)

(215

)

(288

)

Other (2)

 

(136

)

(54

)

(373

)

(211

)

 

 

(168

)

(114

)

(588

)

(499

)

Other costs and expenses

 

(40

)

(41

)

(167

)

(146

)

Depreciation

 

(7

)

(4

)

(25

)

(20

)

Operating and other income

 

68

 

31

 

137

 

108

 

 


(1) Curtis Palmer is included until April 30, 2004.

(2) Other includes natural gas.

 

Eastern Operations Sales Volumes (1)

 

 

 

Three months ended December 31

 

Year ended December 31

 

(GWh)

 

2005

 

2004

 

2005

 

2004

 

Supply

 

 

 

 

 

 

 

 

 

Generation

 

873

 

365

 

2,879

 

1,467

 

Purchased

 

489

 

1,117

 

2,627

 

4,731

 

 

 

1,362

 

1,482

 

5,506

 

6,198

 

Contracted vs. Spot

 

 

 

 

 

 

 

 

 

Contracted

 

1,154

 

1,473

 

4,919

 

6,055

 

Spot

 

208

 

9

 

587

 

143

 

 

 

1,362

 

1,482

 

5,506

 

6,198

 

 


(1) Curtis Palmer is included until April 30, 2004.

 

Operating and other income in fourth quarter 2005 from Eastern Operations of $68 million was $37 million higher compared to $31 million in fourth quarter 2004. The increase was primarily due to income resulting from the April 1, 2005 acquisition of the TC Hydro hydroelectric generation assets and from the Grandview cogeneration facility placed into service in January 2005Partially offsetting these increases was a $16 million pre-tax ($10 million after-tax) restructuring transaction gain in fourth

 

19



 

quarter 2004 relating to power purchase contracts and a loss of operating income primarily associated with the expiration of certain long-term sales contracts in 2004.

 

Operating and other income for the year ended December 31, 2005 was $137 million or $29 million higher than the $108 million earned in 2004.  Incremental income from the acquisition of the TC Hydro assets and income from the Grandview cogeneration facility were the primary reasons for the increase.  Partially offsetting these increases were a $16 million pre-tax ($10 million after-tax) contract restructuring payment made by OSP to its natural gas fuel suppliers in first quarter 2005, a $16 million pre-tax ($10 million after-tax) reduction in income as a result of the sale of Curtis Palmer to Power LP in April 2004 and a loss of operating income primarily associated with the expiration of long-term sales contracts.  The contract restructuring at OSP reduced the term of the long-term natural gas supply contracts by approximately three years (now ending in October 2008) and adjusted the pricing to track spot market pricing of natural gas at the Niagara delivery point instead of the previously arbitrated pricing that had resulted in above-market cost of natural gas for OSP.

 

Generation volumes in fourth quarter 2005 increased 508 GWh to 873 GWh compared to fourth quarter 2004 primarily due to the acquisition of the TC Hydro assets and the placing into service of the Grandview cogeneration facility.  Partially offsetting these increases was reduced generation from the OSP facility resulting from a planned maintenance outage at OSP Phase II which was completed in January 2006.

 

Eastern Operations’ power sales revenues of $125 million increased $5 million in fourth quarter 2005 due to higher realized prices resulting from increased sales generation volumes into a higher priced wholesale spot market partially offset by lower volumes sold.  The increased sales to the wholesale spot market were primarily due to high water flows through the TC Hydro facilities.  Sales volumes of 1,362 GWh for fourth quarter 2005 were lower than the same period in 2004 due primarily to the expiration of certain long-term sales contracts in 2004.  Power cost of sales of $32 million was lower in fourth quarter 2005 due to the impact of lower purchased power volumes partially offset by higher prices for purchased power.  Purchased power volumes of 489 GWh were significantly lower in fourth quarter 2005 due to lower contracted sales volumes and the incremental power generation from the purchase of the TC Hydro assets.  Volumes generated from the TC Hydro assets reduced the requirement to purchase power to fulfill contractual sales obligations.  Fourth quarter 2005 other revenue and other cost of sales of $158 million and $136 million, respectively, increased year-over-year primarily as a result of natural gas purchased and resold under the new natural gas supply contracts at OSP.  Other costs and expenses in fourth quarter 2005 of $40 million, which include fuel gas consumed in generation, was relatively unchanged from the prior year as the operating costs of the TC Hydro assets were offset by a decrease in fuel usage costs at the OSP facility.

 

20



 

In fourth quarter 2005, approximately 15 per cent of power sales volumes were sold into the spot market compared to approximately one per cent in fourth quarter 2004 reflecting the sale of a portion of the generation from the TC Hydro assets into the spot market.  Eastern Operations is focused on selling the majority of its power under contract to wholesale, commercial and industrial customers while managing a portfolio of power supplies sourced from its own generation and wholesale power purchases.  To reduce its exposure to spot market prices, as at December 31, 2005, Eastern Operations had entered into fixed price sales contracts to sell approximately 5,000 GWh of power for 2006 and approximately 3,500 GWh of power for 2007, although certain contracted volumes are dependent on customer usage levels.

 

General, Administrative, Support Costs and Other

 

General, administrative, support costs and other of $28 million and $102 million for the three months and year ended December 31, 2005, respectively, increased $9 million and $13 million, respectively, compared to the same periods in 2004. The increases were primarily due to higher business development costs expensed in 2005 and the positive impact in 2004 of the recognition of unrealized foreign exchange gains on Power LP’s U.S. dollar denominated debt.

 

Sales Volumes and Plant Availability

 

Power Sales Volumes

 

 

 

Three months ended December 31

 

Year ended December 31

 

(GWh)

 

2005

 

2004

 

2005

 

2004

 

Bruce Power (1)

 

2,946

 

2,351

 

10,732

 

10,608

 

Western operations (2)

 

3,075

 

3,136

 

11,906

 

11,695

 

Eastern operations (2)

 

1,362

 

1,482

 

5,506

 

6,198

 

Power LP investment (2) (3)

 

 

669

 

1,865

 

2,419

 

Total

 

7,383

 

7,638

 

30,009

 

30,920

 

 


(1)   Sales volumes reflect TransCanada’s proportionate share of Bruce Power output.

(2)   ManChief and Curtis Palmer volumes are included in Power LP investment effective April 30, 2004.

(3)   TransCanada operated and managed Power LP until August 31, 2005. The volumes in the table represent 100 percent of Power LP’s sales volumes up to August 31, 2005.

 

21



 

 

 

Three months ended December 31

 

Year ended December 31

 

Weighted Average Plant Availability (1)

 

2005

 

2004

 

2005

 

2004

 

Bruce Power (2)

 

79

%

72

%

80

%

82

%

Western operations (3)

 

81

%

92

%

85

%

95

%

Eastern operations (3) (4)

 

90

%

88

%

83

%

95

%

Power LP investment (3) (5)

 

 

98

%

94

%

97

%

All plants, excluding Bruce Power investment

 

88

%

93

%

87

%

96

%

All plants

 

84

%

85

%

84

%

90

%

 


(1)   Plant availability represents the percentage of time in the period that the plant is available to generate power, whether actually running or not and is reduced by planned and unplanned outages.

(2)   Unit 3 is included effective March 1, 2004.

(3)   ManChief and Curtis Palmer are included in Power LP investment effective April 30, 2004.

(4)   TC Hydro is included in Eastern Operations effective April 1, 2005.

(5)   Power LP is included to August 31, 2005.

 

Corporate

 

Net expenses for the three months and year ended December 31, 2005 were $7 million and $36 million, respectively, compared to $3 million and $2 million for the corresponding periods in 2004.

 

The $4 million increase in Corporate net expenses for the three months ended December 31, 2005 compared to the same period in 2004 was primarily due to increased net interest costs offset by an income tax refund received in fourth quarter 2005 relating to prior years.

 

The $34 million increase in net expenses in 2005 compared to 2004 was primarily due to increased interest expense on higher average long-term debt and commercial paper balances in 2005 as well as the release in third quarter 2004 of previously established restructuring provisions.  Income tax refunds and positive tax adjustments were comparable in 2004 and 2005.

 

Other Recent Developments

 

Gas Transmission

 

Wholly-Owned Pipelines

 

Canadian Mainline

 

During fourth quarter 2005, the NEB announced that the formula-based ROE for 2006 is 8.88 per cent.  In December 2005, the NEB approved the tolls for transportation services that TransCanada proposed to charge on an interim basis, effective January 1, 2006.  TransCanada is currently engaged in settlement discussions with its stakeholders on matters related to the Canadian Mainline’s 2006 tolls and tariff.

 

22



 

Alberta System

 

TransCanada continued to charge interim tolls throughout 2005 for transportation service on the Alberta System.  The interim tolls, approved by the EUB in December 2004, will remain in effect until final tolls are established following the Phase II proceeding of the Alberta System’s 2005 GRA.  In this second phase of the EUB’s rate making process, the allocation of 2005 approved costs among transportation services and rate design will be determined.  The EUB commenced a hearing for Phase II on October 4, 2005.  The two week oral hearing on Phase II concluded October 19 with written argument and reply filed November 10 and November 24, respectively.  A decision is expected in February 2006.

 

During fourth quarter 2005, the EUB announced that the formula-based ROE for 2006 is 8.93 per cent.

 

Foothills and BC Systems

 

Following an agreement with CAPP and other stakeholders to increase the deemed equity component of the capital structure from 30 per cent to 36 per cent for the Foothills and BC Systems and discussions with its shippers on those two systems, on December 2, 2005, TransCanada filed applications with the NEB for final 2006 tolls.  Both the Foothills System and BC System 2006 toll applications reflect a deemed common equity ratio of 36 per cent.  On December 21, 2005, the NEB approved the Foothills System 2006 tolls as final tolls, effective January 1, 2006.  On the BC System, no issue was raised with respect to the capital structure; however a concern was raised with respect to proposed pricing of Short-Term Firm Service (STFS).  Therefore, the NEB approved the applied-for BC System tolls on an interim basis, effective January 1, 2006, pending the final resolution of the STFS concern.

 

Other Gas Transmission

 

Keystone

 

In November 2005, TransCanada signed a Memorandum of Understanding with ConocoPhillips Company and CPPL which commits ConocoPhillips Company to ship crude oil on the proposed Keystone pipeline, and gives CPPL the right to acquire up to a fifty per cent ownership interest in the pipeline.  On January 31, 2006, TransCanada announced it has secured firm, long-term contracts totalling 340,000 barrels per day through the binding Open Season held during fourth quarter 2005.  The Keystone pipeline, expected to cost approximately US$2.1 billion, will be capable of transporting approximately 435,000 barrels per day of crude oil from Hardisty, Alberta to Patoka, Illinois through a 2,950 kilometre pipeline system.

 

Broadwater

 

TransCanada, on behalf of the Broadwater Energy project, filed on January 30, 2006, a formal application with FERC for federal approval to construct and operate the Broadwater project.  The

 

23



 

proposed facility, which would be located in the New York State waters of Long Island Sound, would be capable of receiving, storing, and re-gasifying imported liquefied natural gas with an average annual send-out capacity of approximately one bcf a day of natural gas. The estimated cost of construction is US$700 million to $1 billion.  Broadwater is being developed jointly by TransCanada and Shell US Gas and Power.

 

Mackenzie

 

The Mackenzie Gas Pipeline Project continued to progress in fourth quarter 2005, with substantial milestones being achieved in reaching agreement with certain of the northern aboriginal groups as to the terms of land access for the pipeline right of way.  In late 2005, the project proponents agreed to proceed to the public hearings phase of the regulatory process.  Hearings in this respect commenced in January, 2006 and are expected to continue throughout the year.

 

In 2003, TransCanada entered into an agreement with the Mackenzie Valley Aboriginal Pipeline Limited Partnership (known as the APG) by which TransCanada agreed to finance the APG’s one-third share of the pipeline pre-development costs associated with the Mackenzie Gas Pipeline Project.  TransCanada’s advances to the APG were originally estimated to total approximately $90 million, with an acknowledgement that these costs could rise as a result of project delays and increased project costs.  Given that the project has experienced delays and is entering into a protracted regulatory hearing process, the total loan advances by TransCanada on behalf of the APG are currently forecast to increase to approximately $145 million.  As at December 31, 2005, TransCanada had funded $87 million of this advance.

 

Power

 

Sheerness PPA

 

Effective December 31, 2005, TransCanada acquired the remaining rights and obligations of the 756 MW Sheerness PPA from the Alberta Balancing Pool for $585 million.  There is an approximate 15 year term remaining on the PPA.

 

Other

 

Canadian Medium-Term Notes Issue

 

In January 2006, the company’s wholly-owned subsidiary, TCPL, issued $300 million of five-year medium-term notes bearing interest of 4.3 per cent under its Canadian base shelf program.

 

Calpine Corporation

 

Calpine Corporation and certain of its subsidiaries (Calpine) filed for bankruptcy protection on December 20, 2005.  Calpine has transportation contracts on certain of TransCanada’s Canadian and

 

24



 

U.S. pipelines.  TransCanada presently holds the maximum financial assurances allowable under the respective tariffs.  To date, Calpine has not accepted or rejected their transportation contracts.  TransCanada is monitoring the Calpine bankruptcy closely regarding any actions/decisions that take place and their impacts.

 

25



 

Consolidated Income

 

 

 

Three months ended December 31

 

Year ended December 31

 

(millions of dollars except per share amounts)

 

2005

 

2004

 

2005

 

2004

 

Revenues

 

1,771

 

1,480

 

6,124

 

5,497

 

 

 

 

 

 

 

 

 

 

 

Operating Expenses

 

 

 

 

 

 

 

 

 

Cost of sales

 

368

 

234

 

1,168

 

940

 

Other costs and expenses

 

576

 

460

 

1,889

 

1,615

 

Depreciation

 

265

 

246

 

1,017

 

948

 

 

 

1,209

 

940

 

4,074

 

3,503

 

Operating Income

 

562

 

540

 

2,050

 

1,994

 

 

 

 

 

 

 

 

 

 

 

Other Expenses/(Income)

 

 

 

 

 

 

 

 

 

Financial charges

 

211

 

221

 

836

 

858

 

Financial charges of joint ventures

 

17

 

15

 

66

 

63

 

Equity income

 

(51

)

(26

)

(247

)

(213

)

Interest income and other

 

(14

)

(1

)

(63

)

(59

)

Gain on sale of Paiton Energy

 

(118

)

 

(118

)

 

Gains related to Power LP

 

 

 

(245

)

(197

)

Gain on sale of PipeLines LP units

 

 

 

(82

)

 

Gain on sale of Millennium

 

 

 

 

(7

)

 

 

45

 

209

 

147

 

445

 

Income from Continuing Operations before Income

 

 

 

 

 

 

 

 

 

Taxes and Non-Controlling Interests

 

517

 

331

 

1,903

 

1,549

 

 

 

 

 

 

 

 

 

 

 

Income Taxes

 

 

 

 

 

 

 

 

 

Current

 

121

 

85

 

550

 

414

 

Future

 

22

 

39

 

60

 

77

 

 

 

143

 

124

 

610

 

491

 

Non-Controlling Interests

 

 

 

 

 

 

 

 

 

Preferred share dividends

 

5

 

5

 

22

 

22

 

Other

 

19

 

17

 

62

 

56

 

 

 

24

 

22

 

84

 

78

 

Net Income from Continuing Operations

 

350

 

185

 

1,209

 

980

 

Net Income from Discontinued Operations

 

 

 

 

52

 

Net Income

 

350

 

185

 

1,209

 

1,032

 

 

 

 

 

 

 

 

 

 

 

Net Income Per Share

 

 

 

 

 

 

 

 

 

Basic

 

 

 

 

 

 

 

 

 

Continuing operations

 

$

0.72

 

$

0.38

 

$

2.49

 

$

2.02

 

Discontinued operations

 

 

 

 

0.11

 

 

 

$

0.72

 

$

0.38

 

$

2.49

 

$

2.13

 

Diluted

 

 

 

 

 

 

 

 

 

Continuing operations

 

$

0.71

 

$

0.38

 

$

2.47

 

$

2.01

 

Discontinued operations

 

 

 

 

0.11

 

 

 

$

0.71

 

$

0.38

 

$

2.47

 

$

2.12

 

Average Shares Outstanding (millions)

 

 

 

 

 

 

 

 

 

Basic

 

487.1

 

484.7

 

486.2

 

484.1

 

Diluted

 

490.4

 

487.1

 

489.1

 

486.7

 

 

26



 

Consolidated Cash Flows

 

 

 

Three months ended December 31

 

Year ended December 31

 

(millions of dollars)

 

2005

 

2004

 

2005

 

2004

 

 

 

 

 

 

 

 

 

 

 

Cash Generated From Operations

 

 

 

 

 

 

 

 

 

Net income from continuing operations

 

350

 

185

 

1,209

 

980

 

Depreciation

 

265

 

246

 

1,017

 

948

 

Gain on sale of Paiton Energy, net of current tax

 

(121

)

 

(121

)

 

Gain on sale of PipeLines LP units, net of current tax

 

 

 

(31

)

 

Gains related to Power LP, net of current tax

 

 

 

(166

)

(197

)

Gain on sale of Millennium, net of current tax

 

 

 

 

(7

)

Equity income in excess of distributions received

 

(1

)

(3

)

(71

)

(113

)

Future income taxes

 

22

 

39

 

60

 

77

 

Non-controlling interests

 

24

 

22

 

84

 

78

 

Pension funding in excess of expense

 

(4

)

(8

)

(9

)

(29

)

Other

 

(5

)

(6

)

(21

)

(34

)

Funds generated from operations

 

530

 

475

 

1,951

 

1,703

 

Decrease/(increase) in operating working capital

 

124

 

(23

)

(49

)

29

 

Net cash provided by operations

 

654

 

452

 

1,902

 

1,732

 

 

 

 

 

 

 

 

 

 

 

Investing Activities

 

 

 

 

 

 

 

 

 

Capital expenditures

 

(345

)

(203

)

(754

)

(530

)

Acquisitions, net of cash acquired

 

(685

)

(1,453

)

(1,317

)

(1,516

)

Disposition of assets, net of current tax

 

125

 

2

 

671

 

410

 

Deferred amounts and other

 

(29

)

(4

)

64

 

(12

)

Net cash used in investing activities

 

(934

)

(1,658

)

(1,336

)

(1,648

)

 

 

 

 

 

 

 

 

 

 

Financing Activities

 

 

 

 

 

 

 

 

 

Dividends on common shares

 

(148

)

(139

)

(586

)

(552

)

Distributions paid to non-controlling interest

 

(12

)

(20

)

(74

)

(87

)

Notes payable issued, net

 

579

 

546

 

416

 

179

 

Long-term debt issued

 

 

398

 

799

 

1,090

 

Reduction of long-term debt

 

(151

)

(487

)

(1,113

)

(1,005

)

Long-term debt of joint ventures issued

 

33

 

79

 

38

 

217

 

Reduction of long-term debt of joint ventures

 

(61

)

(94

)

(80

)

(112

)

Partnership units of joint ventures issued

 

 

 

 

88

 

Common shares issued

 

5

 

7

 

44

 

32

 

Net cash provided by/(used in) financing activities

 

245

 

290

 

(556

)

(150

)

 

 

 

 

 

 

 

 

 

 

Effect of Foreign Exchange Rate Changes on Cash

 

 

 

 

 

 

 

 

 

and Short-Term Investments

 

1

 

(31

)

11

 

(87

)

(Decrease)/Increase in Cash and Short-Term Investments

 

(34

)

(947

)

21

 

(153

)

Cash and Short-Term Investments

 

 

 

 

 

 

 

 

 

Beginning of period

 

246

 

1,138

 

191

 

344

 

Cash and Short-Term Investments

 

 

 

 

 

 

 

 

 

End of period

 

212

 

191

 

212

 

191

 

 

27



 

Consolidated Balance Sheet

 

(millions of dollars)

 

December 31, 2005

 

December 31, 2004

 

 

 

 

 

 

 

ASSETS

 

 

 

 

 

Current Assets

 

 

 

 

 

Cash and short-term investments

 

212

 

191

 

Accounts receivable

 

796

 

616

 

Inventories

 

281

 

174

 

Other

 

277

 

120

 

 

 

1,566

 

1,101

 

Long-Term Investments

 

400

 

1,098

 

Plant, Property and Equipment

 

20,038

 

18,764

 

Other Assets

 

2,109

 

1,459

 

 

 

24,113

 

22,422

 

 

 

 

 

 

 

LIABILITIES AND SHAREHOLDERS’ EQUITY

 

 

 

 

 

Current Liabilities

 

 

 

 

 

Notes payable

 

962

 

546

 

Accounts payable

 

1,494

 

1,135

 

Accrued interest

 

222

 

214

 

Current portion of long-term debt

 

393

 

774

 

Current portion of long-term debt of joint ventures

 

41

 

85

 

 

 

3,112

 

2,754

 

Deferred Amounts

 

1,196

 

783

 

Future Income Taxes

 

703

 

509

 

Long-Term Debt

 

9,640

 

9,749

 

Long-term Debt of Joint Ventures

 

937

 

808

 

Preferred Securities

 

536

 

554

 

 

 

16,124

 

15,157

 

Non-Controlling Interests

 

 

 

 

 

Preferred shares of subsidiary

 

389

 

389

 

Other

 

394

 

311

 

 

 

783

 

700

 

Shareholders’ Equity

 

 

 

 

 

Common shares

 

4,755

 

4,711

 

Contributed surplus

 

272

 

270

 

Retained earnings

 

2,269

 

1,655

 

Foreign exchange adjustment

 

(90

)

(71

)

 

 

7,206

 

6,565

 

 

 

24,113

 

22,422

 

 

28



 

Consolidated Retained Earnings

 

 

 

Year ended December 31

 

(millions of dollars)

 

2005

 

2004

 

 

 

 

 

 

 

Balance at beginning of year

 

1,655

 

1,185

 

Net income

 

1,209

 

1,032

 

Common share dividends

 

(595

)

(562

)

 

 

2,269

 

1,655

 

 

29



 

Segmented Information

 

Three months ended December 31

 

Gas Transmission

 

Power

 

Corporate

 

Total

 

(millions of dollars)

 

2005

 

2004

 

2005

 

2004

 

2005

 

2004

 

2005

 

2004

 

Revenues

 

1,086

 

1,077

 

685

 

403

 

 

 

1,771

 

1,480

 

Cost of sales

 

 

 

(368

)

(234

)

 

 

(368

)

(234

)

Other costs and expenses

 

(389

)

(349

)

(187

)

(111

)

 

 

(576

)

(460

)

Depreciation

 

(235

)

(229

)

(30

)

(17

)

 

 

(265

)

(246

)

Operating income/(loss)

 

462

 

499

 

100

 

41

 

 

 

562

 

540

 

Financial charges and non-controlling interests

 

(200

)

(228

)

 

(2

)

(35

)

(13

)

(235

)

(243

)

Financial charges of joint ventures

 

(13

)

(13

)

(4

)

(2

)

 

 

(17

)

(15

)

Equity income

 

25

 

21

 

26

 

5

 

 

 

51

 

26

 

Interest income and other

 

4

 

2

 

 

3

 

10

 

(4

)

14

 

1

 

Gain on sale of Paiton Energy

 

 

 

118

 

 

 

 

118

 

 

Income taxes

 

(118

)

(124

)

(43

)

(14

)

18

 

14

 

(143

)

(124

)

Net Income from Continuing Operations

 

160

 

157

 

197

 

31

 

(7

)

(3

)

350

 

185

 

Net Income from Discontinued Operations

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Income

 

 

 

 

 

 

 

 

 

 

 

 

 

350

 

185

 

 

Year ended December 31

 

Gas Transmission

 

Power

 

Corporate

 

Total

 

(millions of dollars)

 

2005

 

2004

 

2005

 

2004

 

2005

 

2004

 

2005

 

2004

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

4,163

 

3,929

 

1,961

 

1,568

 

 

 

6,124

 

5,497

 

Cost of sales

 

 

 

(1,168

)

(940

)

 

 

(1,168

)

(940

)

Other costs and expenses

 

(1,380

)

(1,228

)

(505

)

(384

)

(4

)

(3

)

(1,889

)

(1,615

)

Depreciation

 

(938

)

(876

)

(79

)

(72

)

 

 

(1,017

)

(948

)

Operating income/(loss)

 

1,845

 

1,825

 

209

 

172

 

(4

)

(3

)

2,050

 

1,994

 

Financial charges and non-controlling interests

 

(788

)

(848

)

(2

)

(9

)

(130

)

(79

)

(920

)

(936

)

Financial charges of joint ventures

 

(57

)

(59

)

(9

)

(4

)

 

 

(66

)

(63

)

Equity income

 

79

 

83

 

168

 

130

 

 

 

247

 

213

 

Interest income and other

 

25

 

8

 

5

 

14

 

33

 

37

 

63

 

59

 

Gain on sale of Paiton Energy

 

 

 

118

 

 

 

 

118

 

 

Gains related to Power LP

 

 

 

245

 

197

 

 

 

245

 

197

 

Gain on sale of PipeLines LP units

 

82

 

 

 

 

 

 

82

 

 

Gain on sale of Millennium

 

 

7

 

 

 

 

 

 

 

7

 

Income taxes

 

(502

)

(430

)

(173

)

(104

)

65

 

43

 

(610

)

(491

)

Net Income from Continuing Operations

 

684

 

586

 

561

 

396

 

(36

)

(2

)

1,209

 

980

 

Net Income from Discontinued Operations

 

 

 

 

 

 

 

 

 

 

 

 

 

 

52

 

Net Income

 

 

 

 

 

 

 

 

 

 

 

 

 

1,209

 

1,032

 

 

 

30



 

Teleconference – Audio and Slide Presentation

 

TransCanada will hold a teleconference today at 11 a.m. (Mountain) / 1 p.m. (Eastern) to discuss the fourth quarter 2005 financial results and general developments and issues concerning the company. Analysts, members of the media and other interested parties wanting to participate should phone 1-866-226-1799 or 416-340-2220 (Toronto area) at least 10 minutes prior to the start of the teleconference.  No passcode is required. A live audio and slide presentation webcast of the teleconference will also be available on TransCanada’s website at www.transcanada.com.

 

The conference will begin with a short address by members of TransCanada’s executive management, followed by a question and answer period for investment analysts.  A question and answer period for members of the media will immediately follow.

 

A replay of the teleconference will be available two hours after the conclusion of the call until midnight (Eastern) February 7, 2006 by dialing 1-800-408-3053 or 416-695-5800 (Toronto area) and entering passcode 3173826. The webcast will be archived and available for replay on www.transcanada.com.

 

About TransCanada

 

TransCanada is a leader in the responsible development and reliable operation of North American energy infrastructure. TransCanada’s network of approximately 41,000 kilometres (25,600 miles) of pipeline transports the majority of Western Canada’s natural gas production to key Canadian and U.S. markets. A growing independent power producer, TransCanada owns, or has interests in, approximately 6,700 megawatts of power generation in Canada and the United States. TransCanada’s common shares trade on the Toronto and New York stock exchanges under the symbol TRP.

 

Forward-Looking Information

 

Certain information in this news release is forward-looking and is subject to important risks and uncertainties.  The results or events predicted in this information may differ from actual results or events.  Factors which 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, proper execution and completion of major pipeline and power infrastructure projects, the availability and price of energy commodities, regulatory decisions, competitive factors in the pipeline and power industry sectors, and the prevailing economic conditions in North America.  For additional information on these and other factors, see the reports filed by TransCanada with Canadian securities regulators and with the United States Securities and Exchange Commission.  TransCanada disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

 

TransCanada welcomes questions from shareholders and potential investors.

 

31



 

Please telephone:

 

Investor Relations, at 1-800-361-6522 (Canada and U.S. Mainland) or direct dial David Moneta at (403) 920-7911. The investor fax line is (403) 920-2457. Media Relations: Jennifer Varey at (403) 920-7859

 

Visit TransCanada’s Internet site at: http://www.transcanada.com

 

32