U.S. SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 40-F
[ ] REGISTRATION STATEMENT PURSUANT TO SECTION 12 OF THE SECURITIES
EXCHANGE ACT OF 1934
OR
[ X ] ANNUAL REPORT PURSUANT TO SECTION 13(a) OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended DECEMBER 31, 2003 Commission File Number 1-8887
----------------- ------
TRANSCANADA PIPELINES LIMITED
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
CANADA
(JURISDICTION OF INCORPORATION OR ORGANIZATION)
4922, 4923, 4924, 5172
(PRIMARY STANDARD INDUSTRIAL CLASSIFICATION CODE NUMBER (IF APPLICABLE))
NOT APPLICABLE
(I.R.S. EMPLOYER IDENTIFICATION NUMBER (IF APPLICABLE))
TRANSCANADA TOWER, 450 - 1 STREET S.W.
CALGARY, ALBERTA, CANADA, T2P 5H1
(403) 920-2000
(ADDRESS AND TELEPHONE NUMBER OF REGISTRANT'S PRINCIPAL EXECUTIVE OFFICES)
CT CORPORATION, SUITE 2610, 520 PIKE STREET
SEATTLE, WASHINGTON, 98101; (206) 622-4511; 1-800-456-4511
(NAME, ADDRESS (INCLUDING ZIP CODE) AND TELEPHONE NUMBER (INCLUDING AREA CODE)
OF AGENT FOR SERVICE IN THE UNITED STATES)
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
8.25% PREFERRED SECURITIES DUE 2047 New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Securities for which there is a reporting obligation pursuant to
Section 15(d) of the Act: None
For annual reports, indicate by check mark the information filed with this Form:
[ X ] Annual Information Form [ X ] Audited annual financial statements
Indicate the number of outstanding shares of each of the issuer's classes of
capital or common stock as of the close of the period covered by the annual
report.
AT DECEMBER 31, 2003,
4,000,000 CUMULATIVE REDEEMABLE FIRST PREFERRED SHARES SERIES U
AND 4,000,000 CUMULATIVE REDEEMABLE FIRST PREFERRED SHARES SERIES Y
WERE ISSUED AND OUTSTANDING
ALL OF THE REGISTRANT'S COMMON SHARES ARE OWNED BY TRANSCANADA CORPORATION.
Indicate by check mark whether the Registrant by filing 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
(the "Exchange Act"). If "Yes" is marked, indicate the file number assigned to
the Registrant in connection with such Rule.
Yes No X
----- -----
Indicate by check mark whether the Registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12
months (or such shorter period that the Registrant was required to file such
reports) and (2) has been subject to such filing requirements for the past 90
days.
Yes X No
----- -----
The documents (or portions thereof) forming part of this Form 40-F are
incorporated by reference in Post-Effective Amendment No. 1 on Form F-9 to
Registration Statement on Form F-10 (Reg. No. 333-101140) under the Securities
Act of 1933, as amended.
CONSOLIDATED AUDITED ANNUAL FINANCIAL STATEMENTS AND
MANAGEMENT'S DISCUSSION & ANALYSIS
A. AUDITED ANNUAL FINANCIAL STATEMENTS
The Registrant's consolidated audited annual financial statements,
including the report of independent chartered accountants with respect
thereto are included herein, see pages F-3 to F-38. See Note 19 of the Notes
to Consolidated Financial Statements on pages F-33 through F-38 of the
Registrant's consolidated audited annual financial statements, reconciling
the important differences between Canadian and United States generally
accepted accounting principles.
B. MANAGEMENT'S DISCUSSION & ANALYSIS
For management's discussion and analysis, see the Management's Discussion &
Analysis on pages M-1 through M-42 included herein.
UNDERTAKING
The Registrant undertakes to make available, in person or by telephone,
representatives to respond to inquiries made by the Commission staff, and to
furnish promptly, when requested to do so by the Commission staff, information
relating to: the securities registered pursuant to Form 40-F; the securities in
relation to which the obligation to file an Annual Report on Form 40-F arises;
or transactions in said securities.
DISCLOSURE CONTROLS AND PROCEDURES
Pursuant to the Sarbanes-Oxley Act of 2002 as adopted by the U.S.
Securities and Exchange Commission, the Registrant's management evaluates the
effectiveness of the design and operation of the company's disclosure controls
and procedures (disclosure controls). This evaluation is done under the
supervision of, and with the participation of, the President and Chief Executive
Officer and the Chief Financial Officer.
As of the end of the period covered by this Annual Report, the Registrant's
management evaluated the effectiveness of its disclosure controls. Based on that
evaluation, the President and Chief Executive Officer and the Chief Financial
Officer have concluded that the Registrant's disclosure controls are effective
in ensuring that material information relating to the Registrant is made known
to management on a timely basis, and is included in this Form 40-F.
No change in the Registrant's internal control over financial reporting
occurred during the period covered by this annual report that has materially
affected, or is reasonably likely to materially affect, the Registrant's
internal control over financial reporting.
AUDIT COMMITTEE FINANCIAL EXPERT
The Registrant's board of directors has determined that it has at least one
audit committee financial expert serving on its audit committee. Mr. Harry G.
Schaefer has been determined to be such audit committee financial expert and is
independent, as that term is defined by the New York Stock Exchange's listing
standards applicable to the Registrant. The SEC has indicated that the
designation of Mr. Schaefer as an audit committee financial expert does not make
Mr. Schaefer an "expert" for any purpose, impose any duties, obligations or
liability on Mr. Schaefer that are greater than those imposed on members of the
audit committee and board of directors who do not carry this designation or
affect the duties, obligations or liability of any other member of the audit
committee.
CODE OF ETHICS
The Registrant has adopted codes of business ethics for its employees and
officers, its principal executive officer, principal financial officer and
controller and its directors. The Registrant's codes are available on its
website at www.transcanada.com. There has been no waiver of the codes granted
during the 2003 fiscal year.
PRINCIPAL ACCOUNTANT FEES AND SERVICES
The aggregate fees for professional services rendered by KPMG LLP for
TransCanada PipeLines Limited and its subsidiaries for the 2003 and 2002
fiscal years are shown in the table below:
--------------------------------------------------------------
Fees in millions of dollars 2003 2002
--------------------------------------------------------------
Audit Fees $ 1.78 $ 1.80
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Audit-Related Fees 0.05 0.02
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Tax Fees 0.06 0.10
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All Other Fees 0.05 -
--------------------------------------------------------------
Total $ 1.94 $ 1.92
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The nature of each category of fees is described below.
AUDIT FEES
Audit fees were incurred for professional services rendered by the auditors
for the audit of the Registrant's annual financial statements or services
provided in connection with statutory and regulatory filings or engagements, the
review of interim consolidated financial statements and information contained in
various prospectuses and other offering documents.
AUDIT-RELATED FEES
Audit-related fees were incurred for the audit of the financial statements
of the Registrant's various pension plans.
TAX FEES
Tax fees were incurred for tax compliance and tax advice. These services
consisted of: tax compliance including the review of original and amended tax
returns, assistance with questions regarding tax audits, the preparation of
employee tax returns under the Registrant's expatriate tax services program and
assistance in completing routine tax schedules and calculations; and tax
services relating to common forms of domestic and international taxation (i.e.,
income tax, capital tax, Goods and Services Tax and Value Added Tax).
ALL OTHER FEES
Fees disclosed in the table above under the item "all other fees" were
incurred for services other than the audit fees, audit-related fees and tax fees
described above. These services consisted of advice with regards to compliance
with the Sarbanes-Oxley Act of 2002.
PRE-APPROVAL POLICIES AND PROCEDURES
The Registrant's Audit Committee has adopted a pre-approval policy with
respect to permitted non-audit services. Under the policy, the Audit Committee
has granted pre-approval for engagements of $25,000 CDN or less and within
management's annual pre-approved limit. For engagements of $25,000 CDN or less
which are not within management's annual pre-approved limit, and for engagements
between $25,000 CDN and $100,000 CDN, approval of the Audit Committee Chairman
is required and the Audit Committee is to be informed of the engagement at the
next scheduled Audit Committee meeting. In all cases, regardless of dollar
amount involved, where there is a potential for conflict of interest for the
external auditor to arise on an engagement, the Audit Committee Chairman shall
pre-approve the assignment.
The Registrant has not approved any non-audit services on the basis of the
de-minimis exemptions. All non-audit services are pre-approved by the Audit
Committee in accordance with the pre-approval policy referenced herein.
OFF-BALANCE SHEET ARRANGEMENTS
The Registrant has no off-balance sheet arrangements, as defined in this
Form, other than the guarantees described in Notes 17 and 19 of the Notes to the
Consolidated Financial Statements. The disclosure relating to guarantees in
Notes 17 and 19 to the Consolidated Financial Statements is incorporated herein
by reference.
TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS
LESS THAN MORE THAN
CONTRACTUAL OBLIGATIONS TOTAL 1 YEAR 1-3 YEARS 3-5 YEARS 5 YEARS
----------------------------------------------------------------------------------------------------------------------------------
Long-Term Debt Obligations 10,795 569 1,225 1,191 7,810
Capital (Finance) Lease Obligations
Operating Lease Obligations 118 18 36 34 30
Purchase Obligations(1) 6,586 1,036 1,349 889 3,312
Other Long-Term Liabilities Reflected on the Registrant's Balance
Sheet under the GAAP of the primary financial statements
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Total 17,499 1,623 2,610 2,114 11,152
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(1) The amounts in this table exclude expected funding contributions of
approximately $80 million in 2004 to the Registrant's pension plans.
For further information on purchase obligations see "Management's Discussion and
Analysis - Contractual Obligations - Purchase Obligations", which is
incorporated herein by reference.
IDENTIFICATION OF THE AUDIT COMMITTEE
The Registrant has a separately-designated standing Audit Committee. The
members of the Audit Committee are:
Chair: H.G. Schaefer
Members: P. Gauthier
K.L. Hawkins
S.B. Jackson
J.R. Paul
FORWARD-LOOKING INFORMATION
Documents and statements herein and documents herein incorporated by
reference, and other reports and filings made with the securities regulatory
authorities include forward-looking statements. All forward looking
statements are based on TCPL's current beliefs as well as assumptions made by
and information currently available to TCPL and relate to, among other
things, anticipated financial performance, business prospects, strategies,
regulatory developments, new services, market forces, commitments and
technological developments. By its nature, such forward-looking information
is subject to various risks and uncertainties, including those discussed
herein, which could cause TCPL's actual results and experience to differ
materially from the anticipated results or other expectations expressed.
Readers are cautioned not to place undue reliance on this forward-looking
information, which is as of the date hereof, and TCPL undertakes no
obligation to update publicly or revise any forward-looking information,
whether as a result of new information, future events or otherwise.
SIGNATURES
Pursuant to the requirements of the Exchange Act, the Registrant certifies
that it meets all of the requirements for filing on Form 40-F and has duly
caused this Annual Report to be signed on its behalf by the undersigned, thereto
duly authorized, in the City of Calgary, Province of Alberta, Canada.
TRANSCANADA PIPELINES LIMITED
Per: /s/ Russell K. Girling
--------------------------------------------
RUSSELL K. GIRLING, Executive Vice-President,
Corporate Development and Chief Financial Officer
Date: March 15, 2004
DOCUMENTS FILED AS PART OF THIS REPORT
1. TransCanada PipeLines Limited Annual Information Form for the year
ended December 31, 2003.
2. Management's Discussion and Analysis included herein on pages M-1
through M-42.
3. 2003 Consolidated Audited Financial Statements included herein on
pages F-3 through F-38.
4. U.S. GAAP reconciliation included herein on pages F-33 through F-38 of
the 2003 Consolidated Audited Financial Statements.
EXHIBITS
1. Consent of KPMG LLP, Chartered Accountants.
2. Certification of Chief Executive Officer pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002.
3. Certification of Chief Financial Officer pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002.
4. Certification of Chief Executive Officer regarding Periodic Report
containing Financial Statements.
5. Certification of Chief Financial Officer regarding Periodic Report
containing Financial Statements.
[LOGO]
TRANSCANADA PIPELINES LIMITED
RENEWAL
ANNUAL INFORMATION FORM
FOR THE YEAR ENDED DECEMBER 31, 2003
FEBRUARY 24, 2004
TABLE OF CONTENTS
PAGE
--------
TABLE OF CONTENTS....................... i
REFERENCE INFORMATION................... ii
PRESENTATION OF INFORMATION............. ii
FORWARD-LOOKING INFORMATION............. ii
THE COMPANY............................. 1
TransCanada PipeLines Limited......... 1
Subsidiaries.......................... 1
Gas Transmission Business............. 2
Power Business........................ 3
GENERAL DEVELOPMENT OF THE BUSINESS..... 3
Developments in Gas Transmission
Business............................ 3
Developments in Power Business........ 4
Recent Developments................... 5
BUSINESS OF TCPL........................ 6
Gas Transmission...................... 6
Wholly-Owned Pipelines.............. 7
Other Gas Transmission.............. 11
Regulation of North American
Pipelines......................... 13
Competition in Gas Transmission..... 14
Research and Development............ 14
Power................................. 14
TransCanada Power, L.P.............. 15
Power Performance................... 16
Regulation of Power................. 16
Competition in Power................ 17
Other Interests....................... 17
Cancarb Limited..................... 17
TransCanada Turbines................ 17
TransCanada Calibrations............ 17
Discontinued Operations............... 17
Gas Marketing and Trading........... 17
PAGE
--------
International....................... 17
Midstream........................... 18
HEALTH, SAFETY AND ENVIRONMENT.......... 18
Climate Change........................ 19
PATENTS, LICENCES AND TRADEMARKS........ 19
LEGAL PROCEEDINGS....................... 19
RISK FACTORS............................ 19
Gas Transmission.................... 19
Power............................... 20
International....................... 20
Corporate........................... 20
FINANCIAL INFORMATION................... 21
Three Year Selected Consolidated
Financial Information............... 21
Dividends............................. 21
MARKET FOR SECURITIES................... 21
DIRECTORS AND OFFICERS.................. 22
Directors........................... 22
Officers............................ 24
CORPORATE GOVERNANCE.................... 26
ADDITIONAL INFORMATION.................. 27
SCHEDULE "A"............................ 28
Exchange Rate of the Canadian
Dollar.............................. 28
Metric Conversion Table............... 28
SCHEDULE "B"............................ 29
SCHEDULE "C"............................ 37
SCHEDULE "D"............................ 41
SCHEDULE "E"............................ 43
SCHEDULE "F"............................ 44
SCHEDULE "G"............................ 50
SCHEDULE "H"............................ 53
SCHEDULE "I"............................ 55
TRANSCANADA PIPELINES LIMITED i
REFERENCE INFORMATION
For the reference information noted below, please refer to Schedule "A".
- Exchange Rate of the Canadian Dollar
- Metric Conversion Table
PRESENTATION OF INFORMATION
Unless otherwise noted, the information contained in this Renewal Annual
Information Form ("AIF") is given as at December 31, 2003 ("YEAR END").
This AIF has been prepared to reflect the presentation of the operations of
TransCanada PipeLines Limited ("TCPL") as they are presented in TCPL's 2003
Audited Consolidated Financial Statements. TCPL's Management's Discussion and
Analysis dated February 24, 2004 ("MD&A") and Notes 1, 17 and 18 of TCPL's 2003
Audited Consolidated Financial Statements are hereby incorporated by reference.
Unless the context indicates otherwise, a reference in this AIF to "TCPL"
includes the subsidiaries of TCPL through which its various business operations
are conducted. The term "subsidiary", when referred to in this AIF, means direct
and indirect wholly-owned subsidiaries of TCPL.
Trends impacting TCPL's gas transmission and power businesses are discussed in
the MD&A under the headings "Gas Transmission" (under the subheadings
"Opportunities", "Challenges" and "Canadian Regulatory Development") and "Power"
(under the subheadings "Opportunities" and "Challenges").
FORWARD-LOOKING INFORMATION
Documents incorporated by reference in this AIF and other reports and filings
made with the securities regulatory authorities include forward-looking
statements. All forward looking statements are based on TCPL's current beliefs
as well as assumptions made by and information currently available to TCPL and
relate to, among other things, anticipated financial performance, business
prospects, strategies, regulatory developments, new services, market forces,
commitments and technological developments. Much of this information also
appears in the MD&A. By its nature, such forward-looking information is subject
to various risks and uncertainties, including those discussed in this AIF, which
could cause TCPL's actual results and experience to differ materially from the
anticipated results or other expectations expressed. Readers are cautioned not
to place undue reliance on this forward-looking information, which is given as
of the date it is expressed in this AIF or otherwise, and TCPL undertakes no
obligation to update publicly or revise any forward-looking information, whether
as a result of new information, future events or otherwise.
ii TRANSCANADA PIPELINES LIMITED
THE COMPANY
TRANSCANADA PIPELINES LIMITED
TCPL is a Canadian public company. Significant dates and events are set forth
below:
DATE EVENT
---- -----
March 21, 1951 Incorporated by Special Act of Parliament as Trans-Canada
Pipe Lines Limited.
April 19, 1972 Continued under the CANADA CORPORATIONS ACT by Letters
Patent, which included the alteration of its capital and
change of name to TransCanada PipeLines Limited.
June 1, 1979 Continued under the CANADA BUSINESS CORPORATIONS ACT.
July 2, 1998 Certificate of Arrangement issued in connection with the
Plan of Arrangement with NOVA Corporation ("NOVA") through
which the companies merged and then split off the commodity
chemicals business carried on by NOVA into a separate public
company.
January 1, 1999 Certificate of Amalgamation issued reflecting TCPL's
vertical short form amalgamation with a wholly-owned
subsidiary, Alberta Natural Gas Company Ltd.
January 1, 2000 Certificate of Amalgamation issued reflecting TCPL's
vertical short form amalgamation with a wholly-owned
subsidiary, NOVA Gas International Ltd.
May 4, 2001 Restated TransCanada PipeLines Limited Articles of
Incorporation issued.
June 20, 2002 Restated TransCanada PipeLines Limited By-Laws.
May 15, 2003 Certificate of Arrangement issued in connection with the
plan of arrangement with TransCanada Corporation
("TRANSCANADA"). TransCanada was incorporated pursuant to
the provisions of the CANADA BUSINESS CORPORATION ACT on
February 25, 2003. The arrangement was approved by TCPL
common shareholders on April 25, 2003 and following court
approval, Articles of Arrangement were filed making the
arrangement effective May 15, 2003. The common shareholders
of TCPL exchanged each of their TCPL common shares for one
common share of TransCanada. The debt securities and
preferred shares of TCPL remained obligations and securities
of TCPL. TCPL continues to hold the assets it held prior to
the arrangement and continues to carry on business as the
principal operating subsidiary of the TransCanada group of
entities.
TCPL's registered office and executive office are located at 450 - 1st Street
S.W., Calgary, Alberta, T2P 5H1.
At Year End, TCPL had approximately 2,325 employees in Canada and the
United States, and two employees posted abroad.
SUBSIDIARIES
TCPL's significant subsidiaries at Year End are noted below. The list excludes
certain of TCPL's subsidiaries where:
- the total assets and total revenue of the individual excluded subsidiaries
do not constitute more than ten per cent of the consolidated assets and
revenues of TCPL at the most recent year end; and
TRANSCANADA PIPELINES LIMITED 1
- the aggregate assets and operating revenues of the excluded subsidiaries
represent less than 20 per cent of the consolidated assets and revenues of
TCPL at the most recent year end.
PERCENTAGE OWNERSHIP
ORGANIZED UNDER BY TCPL OF VOTING
SUBSIDIARY(1) THE LAWS OF SHARES
------------- --------------- --------------------
NOVA Gas Transmission Ltd................................... Alberta 100
TransCanada PipeLine USA Ltd................................ Nevada 100
701671 Alberta Ltd.......................................... Alberta 100
TransCanada Energy Ltd.................................... Canada 100
NOTE:
(1) Names shown without indentation are direct subsidiaries of TCPL. The
indentation of the name of a subsidiary indicates that such subsidiary is
held by a subsidiary of TCPL. The percentage ownership shown for a
subsidiary is that held directly by its immediate parent.
GAS TRANSMISSION BUSINESS
CANADA
TCPL, through subsidiaries, has substantial Canadian natural gas pipeline
holdings, including:
- a natural gas transmission system throughout the province of Alberta
("ALBERTA SYSTEM");
- a Canadian mainline natural gas transmission system ("CANADIAN MAINLINE");
- a natural gas transmission system in southeastern B.C., southern Alberta
and southwestern Saskatchewan ("FOOTHILLS SYSTEM");
- a natural gas transmission system in southeastern British Columbia (the
"BC SYSTEM"); and
- a 50 per cent interest in Trans Quebec & Maritimes Pipeline Inc. ("TQM")
which operates a natural gas transmission system in southeastern Quebec
("TQM SYSTEM").
UNITED STATES
TCPL, through subsidiaries, has natural gas pipeline holdings in the
United States including:
- a 50 per cent interest in Great Lakes Gas Transmission Limited Partnership
("GREAT LAKES");
- a 41 per cent interest in the Iroquois Gas Transmission System
("IROQUOIS");
- a 61.7 per cent interest in the Portland Natural Gas Transmission System
Partnership ("PORTLAND");
- a 12.3 per cent voting interest in Northern Border Pipeline Company
("NORTHERN BORDER") through Northern Border Partners, L.P. ("NBP L.P.")
and a 30 per cent interest in Northern Border through
TC PipeLines, L.P.; and
- a one per cent interest in Tuscarora Gas Transmission Company
("TUSCARORA").
TCPL holds a 33.4 per cent interest in TC PipeLines, L.P., a publicly held
limited partnership of which a subsidiary of TCPL acts as the general partner.
The remaining interest of TC PipeLines, L.P. is widely held by the public.
TC PipeLines, L.P. holds a 30 per cent interest in Northern Border and a
49 per cent interest in Tuscarora.
2 TRANSCANADA PIPELINES LIMITED
POWER BUSINESS
TCPL owns and/or operates or has under construction or development a number of
power plants, and purchases power under a number of power purchase arrangements.
TCPL's power plants and power purchase arrangements, in the aggregate, represent
approximately 4,667 megawatts ("MW") of power generation capacity.
TCPL holds a 35.6 per cent interest in TransCanada Power, L.P. ("POWER LP"),
with the remaining interest being widely held by the public. A subsidiary of
TCPL acts as the general partner of Power LP. Power LP owns seven power plants
which are managed by TCPL.
GENERAL DEVELOPMENT OF THE BUSINESS
The general development of TCPL's business during the last three financial
years, and the significant events or conditions which have had an influence on
that development, are summarized below. Most of these events are discussed in
greater detail under the heading "Business of TCPL" in this AIF.
DEVELOPMENTS IN GAS TRANSMISSION BUSINESS
TCPL's focus has been to sustain, grow and optimize its natural gas transmission
business, including to pursue changes to the regulated business models that are
applicable to TCPL's operations. Summarized below are significant developments
that have occurred in TCPL's natural gas transmission business over the last
three years.
2003
In August 2003, TCPL acquired the remaining interests in Foothills Pipe Lines
Ltd. ("FOOTHILLS") that it did not previously own. The Foothills System, which
is owned by Foothills, complements TCPL's existing western Canadian facilities.
It extends 1,040 kilometres and carries over 30 per cent of all Canadian natural
gas exports to the United States.
TCPL, through Foothills, holds certificates for both the Alaskan and Canadian
segments of the Alaska Highway Pipeline Project and also holds significant
right-of-way assets for the project in both Canada and Alaska.
In June 2003, TCPL, the Mackenzie Delta Producers Group ("MACKENZIE PRODUCERS")
and Mackenzie Valley Aboriginal Pipeline L.P. ("ABORIGINAL PIPELINE GROUP" or
"APG") reached a funding and participation agreement. TCPL agreed to finance the
APG's share of project definition costs in exchange for several options
including an ownership interest in the pipeline, certain rights of first refusal
in the Mackenzie Gas Pipeline Project and the right to have the Mackenzie Delta
gas flow into the Alberta System.
In September 2003, TCPL and ConocoPhillips Company ("CONOCOPHILLIPS") announced
the Fairwinds Partnership to jointly evaluate a liquefied natural gas ("LNG")
regasification facility in Harpswell, Maine. TCPL also continues to pursue other
LNG projects in North America.
TCPL increased its ownership interest in Portland in the northeastern
United States from 33.3 per cent to 61.7 per cent through acquisitions that took
place in September and December 2003.
For further information about Gas Transmission Developments in 2003, refer to
the headings "Business of TCPL -- Gas Transmission -- Wholly-Owned Pipelines"
and "Business of TCPL -- Gas Transmission -- Other Gas Transmission" below.
2002
In August 2002, TCPL completed the acquisition of a portion of the
two per cent general partnership interest in NBP L.P., a publicly held limited
partnership which provides TCPL with a 17.5 per cent voting interest on its
partnership policy committee. NBP L.P. owns interests in pipelines and gas
processing plants in the United States and Canada, including a 70 per cent
interest in Northern Border.
TRANSCANADA PIPELINES LIMITED 3
2001
In January 2001, TCPL announced that it had reached a settlement in principle
regarding 2001 and 2002 tolls and services on the Alberta System. The settlement
established the Alberta System's fixed revenue requirement for the next two
years. The settlement, approved by the Alberta Energy and Utilities Board
("EUB"), together with the receipt point specific rate design previously
approved by the EUB, formed the basis of the Alberta System's tolls in 2002.
In February 2001, TCPL announced that it had reached a settlement regarding the
2001 and 2002 services and pricing on the Canadian Mainline that resolved all
issues other than cost of capital. The parties agreed that the issue of cost of
capital would be determined in a different forum. The National Energy Board
("NEB") approved the settlement.
By December 31, 2001, TCPL had sold the majority of its natural gas marketing
and trading operations, including its structured products business, most of its
natural gas transportation and storage contracts and its net back pool
operations.
DEVELOPMENTS IN POWER BUSINESS
In the past three years, TCPL has grown its power business and in particular,
has increased its generation capacity from approximately 2,253 MW in 2001 to
4,667 MW in 2003. In addition, net earnings from power operations has increased
by $52 million over the same period. Summarized below are significant
developments that have occurred in TCPL's power business over the last
three years.
2003
In February 2003, TCPL, as part of a consortium, acquired a 31.6 per cent
interest in Bruce Power L.P. ("BRUCE POWER") and a 33.3 per cent interest in
Bruce Power Inc., the general partner of Bruce Power. Bruce Power leases its
generation facilities from Ontario Power Generation Inc. ("OPG"). The facilities
consist of eight nuclear reactors, five of which were operational at Year End
with a capacity of 3,910 MW. An additional reactor with capacity of 750 MW was
restarted in January 2004.
The members of the purchasing consortium of Bruce Power have severally, on a
pro-rata basis, guaranteed certain contingent financial obligations of Bruce
Power related to operator licenses, the OPG lease agreement, power sales
agreements and contractor services. Bruce Power continues to be operated by its
pre-acquisition management which is comprised of experienced nuclear power plant
operators. Spent fuel and decommissioning liabilities remain with OPG under the
terms of the lease.
In 2003, TCPL announced that it would construct two new power plants. The first
of these is the 550 MW natural gas-fired Becancour cogeneration power plant near
Trois-Rivieres, Quebec ("BECANCOUR PLANT") which will supply its entire power
output to Hydro-Quebec. Distribution is provided for under a 20 year power
purchase contract. The cost of the Becancour Plant is estimated to be
$550 million, including capitalized interest, and the plant is expected to be in
service in late 2006. TCPL is also constructing the 90 MW Grandview natural
gas-fired cogeneration power plant on the site of the Irving Oil refinery in
Saint John, New Brunswick ("GRANDVIEW PLANT"). Under a 20 year tolling
arrangement, a subsidiary of Irving Oil Limited will provide fuel to the
Grandview Plant and has contracted for 100 per cent of the Grandview Plant's
heat and electricity output. The cost of the Grandview Plant is estimated to be
approximately $90 million. Construction of the Grandview Plant began in 2003 and
has an expected in-service date at the end of 2004. In addition, construction of
the 165 MW MacKay River power plant was completed in 2003 and the plant is
expected to be put into commercial service in the first quarter of 2004.
2002
In November 2002, TCPL completed the acquisition of the 300 MW ManChief power
plant, situated approximately 145 kilometres northeast of Denver, Colorado. The
ManChief power plant is operated under contract by an unaffiliated third party.
4 TRANSCANADA PIPELINES LIMITED
2001
In 2001, TCPL acquired 50 per cent of the power purchase arrangements for the
Sundance B power plant located near Edmonton, Alberta. Sundance B has capacity
to generate 706 MW. In addition, TCPL completed construction of two natural gas
fired plants: an 80 MW power plant near Carseland, Alberta and a 40 MW power
plant near Redwater, Alberta. Finally, TCPL acquired Curtis Palmer Hydroelectric
Company, L.P. in July 2001, which owns and operates two hydroelectric plants
near Corinth, New York which have a combined generating capacity of 60 MW. The
entire output from the Curtis Palmer plants are committed to a purchaser under a
long-term, fixed-price power purchase arrangement.
RECENT DEVELOPMENTS
On February 24, 2004, TransCanada announced an agreement to acquire Gas
Transmission Northwest Corporation ("GTNC") from National Energy & Gas
Transmission, Inc. ("NEGT") for approximately US$1.703 billion, including
US$500 million of assumed debt and subject to typical closing adjustments. The
acquisition of GTNC is subject to bankruptcy court approval, including
completion of a court sanctioned auction process, and to regulatory approval.
The agreement contemplates that final bankruptcy court approval of the sale will
be obtained within 75 days of signing the agreement.
GTNC is a natural gas pipeline company that owns and operates two pipeline
systems. The first of these is the Gas Transmission Northwest pipeline system,
formerly known as Pacific Gas Transmission, which extends more than
2,174 kilometres from a connection point on TCPL's BC System near Kingsgate,
British Columbia on the British Columbia -- Idaho border to a point near Malin,
Oregon on the Oregon -- California border. The second pipeline system, the North
Baja pipeline system, extends 128 kilometres from a point near Ehrenberg,
Arizona to a point near Ogilby, California on the California -- Baja California,
Mexico border. The natural gas transported on North Baja system comes primarily
from supplies in the southwestern United States for markets in Northern Baja
California, Mexico. The sale of the North Baja pipeline is subject to a right of
first refusal held by an unaffiliated company.
In a referendum held on March 9, 2004, the residents of Harpswell, Maine voted
against leasing a town-owned site for an LNG regasification facility which the
Fairwinds Partnership had been evaluating for development. The Fairwinds
Partnership subsequently announced that it has suspended any further work on the
project in Harpswell, Maine.
TRANSCANADA PIPELINES LIMITED 5
BUSINESS OF TCPL
The following table shows TCPL's revenues from operations by segment, classified
geographically, for the years ended December 31, 2003 and 2002.
2003 2002
--------------------- ---------------------
(millions of dollars) (millions of dollars)
GAS TRANSMISSION
Canada -- Domestic Deliveries............................. 2,492 2,076
Canada -- Export Deliveries(1)............................ 1,291 1,641
United States............................................. 173 204
----- -----
3,956 3,921
----- -----
POWER
Canada -- Domestic Deliveries............................. 765 655
Canada -- Export Deliveries(1)............................ 2 --
United States............................................. 634 638
----- -----
1,401 1,293
----- -----
TOTAL REVENUES(2)........................................... 5,357 5,214
===== =====
NOTES:
(1) Export deliveries include gas transmission revenues attributable to
deliveries to United States pipelines and power deliveries to United States
markets.
(2) Revenues are attributed to countries based on country of origin of product
or service.
GAS TRANSMISSION
TCPL's transmission business principally includes the operation of the Canadian
Mainline, the Alberta System, the Foothills System, the BC System and TCPL's
other investments in natural gas pipelines located primarily in Canada and the
United States.
Canadian natural gas transmission services are provided under gas transportation
tariffs that provide for cost recovery including return of and return on capital
as approved by the applicable regulatory authorities. In some cases, such
tariffs are determined under agreements with customers and other interested
parties, subject to regulatory approval. The net income of the gas transmission
business is generated based on such tariffs. Under the current regulatory model,
net income is not affected by fluctuations in the commodity price of natural
gas, but such fluctuations influence both production levels and the natural gas
basins from which North American natural gas users elect to purchase natural gas
supplies.
The volume of natural gas shipments on the Canadian Mainline, the Alberta
System, the Foothills System and the BC System depends on the volume of natural
gas produced and sold both in and outside of Alberta, and on the construction
and availability of other pipeline capacity. The natural gas transported by TCPL
comes primarily from the Western Canada Sedimentary Basin ("WCSB"). The WCSB's
estimated remaining established reserves of natural gas are approximately 57
trillion cubic feet ("TCF") with a remaining reserve-to-production ratio of
approximately nine years at current levels of production. Incremental reserves
are continually being discovered, and generally maintain the
reserve-to-production ratio at close to nine years. Production of natural gas
from the WCSB has not increased since 2001. With the expansion of capacity on
TCPL'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, TCPL anticipates there will be excess pipeline
capacity out of the WCSB for the foreseeable future.
In addition to the information concerning the gas transmission segment of TCPL's
business set out herein, further information can be found in the MD&A under the
heading "Gas Transmission -- Wholly-Owned Pipelines -- Business Risks".
6 TRANSCANADA PIPELINES LIMITED
WHOLLY-OWNED PIPELINES
ALBERTA SYSTEM
The Alberta System, held by NOVA Gas Transmission Ltd. ("NGTL"), a subsidiary of
TCPL, is an Alberta-wide natural gas transmission system that collects and
transports natural gas for use in Alberta and for delivery to connecting
pipelines, such as the Canadian Mainline, the Foothills System and the BC
System, as well as to other unaffiliated pipelines, at various points on the
Alberta border for delivery to eastern Canada, British Columbia and the
United States. The Alberta System includes approximately 22,700 kilometres of
mainlines and laterals.
Capital expenditures, which are dependent in part upon requests for increased
transportation service by customers, were $53 million in 2003. TCPL anticipates
approximately $90 million of capital spending on the Alberta System in 2004.
These capital expenditures will be primarily related to capacity expansion.
The following table sets forth the annual volumes delivered off the Alberta
System for the years ended December 31, 2003 and 2002.
2003 2002
-------------------- --------------------
DELIVERY POINTS VOLUME(1) PER CENT VOLUME(2) PER CENT
--------------- --------- -------- --------- --------
(Bcf) (Bcf)
Alberta..................................................... 539 14 475 11
Eastern Canada and Eastern United States.................... 1,552 40 1,738 42
Western United States....................................... 665 17 750 18
Midwestern United States.................................... 1,117 29 1,155 28
British Columbia............................................ 10 -- 28 1
----- --- ----- ---
TOTAL....................................................... 3,883 100 4,146 100
===== === ===== ===
NOTES:
(1) Of the total volumes transported in 2003, 1.89 Tcf of natural gas was
delivered to the Canadian Mainline, 674 billion cubic feet ("BCF") of
natural gas was delivered to the BC System (including the BC portion of the
Foothills System) and 777 Bcf of natural gas was delivered to the
Saskatchewan portion of the Foothills System.
(2) Of the total volumes transported in 2002, 2.09 Tcf of natural gas was
delivered to the Canadian Mainline, 773 Bcf of natural gas was delivered to
the BC System (including the BC portion of the Foothills System) and
779 Bcf of natural gas was delivered to the Saskatchewan portion of the
Foothills System.
ALBERTA SYSTEM CONTRACTED FIRM TRANSPORTATION SERVICES
As of Year End, the Alberta System was providing transportation for 182 shippers
pursuant to approximately 15,500 firm service transportation contracts.
As of Year End, the weighted average remaining term of firm transportation
contracts was approximately 2.4 years compared to a weighted average remaining
term of 3.0 years as of December 31, 2002. Currently, these contracts are
renewable by the customer providing notice to NGTL at least twelve months prior
to the expiry of the current contract term. The Alberta System has seen a
30 per cent decrease in firm contracted capacity since the 1998-1999 contract
year. Further information about the Alberta System can be found in the MD&A
under the headings "Gas Transmission -- Wholly-Owned Pipelines -- Financial
Review" and "Gas Transmission -- Wholly-Owned Pipelines -- Business Risks".
REGULATION OF THE ALBERTA SYSTEM
The construction and operation of the Alberta System is regulated by the EUB
primarily under the provisions of the GAS UTILITIES ACT (Alberta) and the
PIPELINE ACT (Alberta). NGTL also requires the EUB's approval for rates, tolls
and charges, and the terms and conditions under which it provides its services.
Under the provisions of the PIPELINE ACT, the EUB oversees various matters,
including the economic, orderly and efficient development of the pipeline, the
operation and abandonment of the pipeline, and certain related pollution and
environmental conservation issues. In addition to requirements under the
PIPELINE ACT, the construction and operation of
TRANSCANADA PIPELINES LIMITED 7
natural gas pipelines in Alberta are subject to certain provisions of, and
require certain approvals under, other provincial legislation such as the
ENVIRONMENTAL PROTECTION AND ENHANCEMENT ACT (Alberta).
Alberta System tolls are designed to generate sufficient revenues for NGTL to
recover operating expenses, depreciation, taxes and financing costs of the
Alberta System, including interest on debt and payments on securities
attributable to the Alberta System, together with a return on deemed common
equity.
In February 2003, NGTL negotiated the Alberta System 2003 Revenue Requirement
Settlement ("2003 SETTLEMENT") with certain shippers and other interested
parties. Under the Alberta System 2003 Settlement, approved by the EUB on
June 24, 2003, NGTL's 2003 revenue requirement was fixed at $1.277 billion,
subject to certain adjustments, including variances from previous agreements,
CO(2) management service costs, and annual foreign exchange amortization
amounts.
In March 2003, NGTL negotiated the 2003 Tariff Settlement with certain shippers
and interested parties. The 2003 Tariff Settlement, approved by the EUB on
June 24, 2003, established NGTL's 2003 rates, tolls and charges for services,
certain new services and new terms and conditions for certain existing services.
In July 2003, NGTL filed evidence in the EUB's generic cost of capital
proceeding ("GCOC"). NGTL is seeking a return of 11 per cent on a deemed common
equity of 40 per cent for the Alberta System. NGTL has been advised by the EUB
that it expects to adopt a standardized approach to determining return and
capital structure for utilities under its jurisdiction through the GCOC. NGTL
expects the EUB to issue its decision in the third quarter of 2004.
In September 2003, NGTL filed Phase 1 of its Alberta System 2004 General Rate
Application ("GRA-PHASE 1") with the EUB. As part of the GRA-Phase 1, NGTL
applied to increase the composite depreciation rate from 4.00 per cent to
4.13 per cent. NGTL filed Phase 2 of the GRA, dealing with rate design and
services, in November 2003 ("GRA-PHASE 2"). The EUB will consider the
GRA-Phase 1 and GRA-Phase 2 in hearings scheduled to commence on April 1, 2004
and June 1, 2004, respectively.
On December 16, 2003, the EUB approved interim rates effective January 1, 2004,
which will remain in place until final 2004 rates are determined.
TOLLING METHODOLOGY FOR THE ALBERTA SYSTEM
The current tolling methodology and rate design for the Alberta System features
differentiated pricing for each gas receipt point on the Alberta System. The
receipt-point price is dependent on geographic location, the diameter of the
pipe through which the customer's natural gas travels, and the term of the
transportation contract.
CANADIAN MAINLINE
The Canadian Mainline consists of approximately 14,900 kilometres of pipeline
system transporting natural gas from the Alberta border east to various delivery
points in Canada and at the United States border.
Capital expenditures on the Canadian Mainline in 2003 were approximately
$48 million. These expenditures were primarily for maintenance capital and plant
retirement projects. TCPL anticipates approximately $120 million of capital
spending on the Canadian Mainline in 2004. The expected 2004 capital
expenditures primarily relate to capacity capital, maintenance capital and plant
retirement projects.
8 TRANSCANADA PIPELINES LIMITED
The following table sets forth the revenues earned and volumes delivered for the
years ended December 31, 2003 and 2002 for the Canadian Mainline.
2003 2002
-------------------------------- --------------------------------
REVENUES PER CENT REVENUES(1) PER CENT
--------------------- -------- --------------------- --------
(millions of dollars) (millions of dollars)
REVENUES
Domestic........................................ 1,035 46 610 28
Export.......................................... 1,214 54 1,568 72
----- --- ----- ---
TOTAL........................................... 2,249 100 2,178 100
===== === ===== ===
2003 2002
-------------------------------- --------------------------------
VOLUME PER CENT VOLUME PER CENT
------ -------- ------ --------
(Bcf) (Bcf)
VOLUMES TRANSPORTED
Domestic........................................ 1,295 49 1,223 47
Export.......................................... 1,333 51 1,407 53
----- --- ----- ---
TOTAL........................................... 2,628 100 2,630 100
===== === ===== ===
NOTE:
(1) 2002 domestic revenues were reduced as a result of transportation service
credits related to two new services offered in that year. Total credits of
$662 million were reported against 2002 domestic revenues. These services
were discontinued in 2003.
CANADIAN MAINLINE CONTRACTED FIRM TRANSPORTATION SERVICES
As of Year End, the Canadian Mainline was providing transportation for 127
shippers pursuant to 352 firm service transportation contracts. Approximately
51 per cent of the total daily transportation volume represented by these
contracts relates to contracts for delivery of natural gas at United States
border points.
As of Year End, the weighted average remaining term of firm transportation
contracts on the Canadian Mainline was approximately 3.2 years compared to a
weighted average remaining term of 3.7 years at December 31, 2002. These
contracts are renewable by the customer providing notice to TCPL at least six
months prior to the expiry of the current contract term. The Canadian Mainline
last operated at capacity with one year or longer firm service contracts during
the 1998-1999 contract year. Since then, the Canadian Mainline has seen a
36 per cent decrease in firm contracted deliveries and a 15 per cent decrease in
total deliveries originating at the Alberta border and in Saskatchewan. Further
information can be found in the MD&A under the headings "Gas
Transmission -- Wholly-Owned Pipelines -- Financial Review" and "Gas
Transmission -- Wholly-Owned Pipelines -- Business Risks".
REGULATION OF THE CANADIAN MAINLINE
Under the terms of the NATIONAL ENERGY BOARD ACT (Canada), the NEB regulates the
construction, operation, tolls and tariffs of the Canadian Mainline. The NEB is
the authority under the CANADIAN ENVIRONMENTAL ASSESSMENT ACT responsible for
considering the environmental and social impacts of proposed pipeline projects.
The Canadian Mainline tolls are designed to generate sufficient revenues for
TCPL to recover operating expenses, depreciation, taxes and financing costs of
the Canadian Mainline, including interest on debt and payments on preferred
securities attributable to the Canadian Mainline, together with a return on
deemed common equity.
The tolls are composed of a demand charge component and a commodity charge
component. The demand charge is independent of the volumes shipped and is
designed to recover fixed costs, such as fixed operating expenses, financing
costs (including a return on deemed common equity), taxes and depreciation. The
commodity charge is designed to recover variable operating costs. These charges
are paid by shippers under transportation contracts with TCPL.
TRANSCANADA PIPELINES LIMITED 9
In June 2002, the NEB denied TCPL's request to adopt an after-tax weighted
average cost of capital methodology for establishing investment return and an
after-tax weighted average cost of capital of 7.5 per cent, equivalent to a
12.5 per cent rate of return on deemed common equity of 40 per cent ("FAIR
RETURN DECISION"). The NEB instead affirmed a formula established in 1995 for
setting return on common equity. Under this formula, the rate of return on
common equity for the Canadian Mainline was 9.61 per cent in 2001,
9.53 per cent in 2002 and 9.79 per cent in 2003. The NEB increased deemed common
equity to 33 per cent from the previously approved level of 30 per cent. In
September 2002, TCPL filed a request for a review and variance of the Fair
Return Decision which was denied by the NEB in February 2003. TCPL maintains
that the Fair Return Decision issued in June 2002 does not recognize the
long-term business risks of the Canadian Mainline and therefore, initiated an
appeal of the NEB's decision not to review and vary the Fair Return Decision, to
the Federal Court of Appeal. In May 2003, TCPL was granted leave to appeal. The
appeal hearing was heard the week of February 16, 2004 and the Federal Court of
Appeal's decision is expected to be rendered later in 2004.
In September 2002, TCPL filed an application with the NEB to approve new tolls
on the Canadian Mainline to be effective January 1, 2003 and the related public
hearings began in February 2003. In July 2003, the NEB issued its decision on
this matter which approved all key components of the application including an
increase in the composite depreciation rate from 2.89 per cent to
3.42 per cent, introduction of a new tolling zone in southwestern Ontario, an
increase to the Interruptible Transportation bid floor price and continuation of
the Fuel Gas Incentive Program. The rates approved in this decision are still
considered interim pending the disposition of TCPL's appeal to the Federal Court
of Appeal regarding the Fair Return Decision.
On December 18, 2003, the NEB approved interim rates effective January 1, 2004,
which should remain in place until final 2004 tolls are determined.
On January 26, 2004, TCPL filed an application with the NEB to determine tolls
applicable to the Canadian Mainline, effective January 1, 2004. In this
application, TCPL has requested an 11 per cent return on deemed common equity of
40 per cent.
FOOTHILLS SYSTEM
The Foothills System, which is regulated by the NEB and the Northern Pipeline
Agency of Canada, is a 1,040 kilometre natural gas pipeline that transports
western Canadian natural gas from central Alberta to connecting pipelines for
transportation to markets in the U.S. Midwest, Pacific Northwest, California and
Nevada and is owned by TCPL. TCPL merged Foothills' operations with its own in
February 2004. TCPL previously held a 50 per cent interest in Foothills and in
August 2003, acquired the remaining interest.
The Alaska Highway Pipeline Project, which would bring Prudhoe Bay natural gas
from Alaska to markets in Canada and the United States, involves pipeline
construction in Canada and Alaska. Foothills holds the certificates to build the
Canadian portion of the Alaska highway pipeline project and subsidiaries of
Foothills and TCPL hold certificates to build the Alaskan part of this project.
TCPL anticipates that it will spend approximately $7 million on the Foothills
System in 2004, which expenditures will primarily be for maintenance capital.
BC SYSTEM
The BC System consists of approximately 200 kilometres of pipeline that carries
natural gas from a connecting point with the Alberta System through the
southeastern corner of British Columbia to connect with the GTNC pipeline system
at the Canada-United States border near Kingsgate, British Columbia. The GTNC
pipeline system connects to California and the northwestern United States.
Further information can be found about the GTNC pipeline system under the
heading "General Development of the Business -- Recent Developments", above.
In 2003, capital expenditures on the BC System were approximately $2 million,
primarily for maintenance capital. TCPL anticipates approximately $2 million of
capital spending on the BC System in 2004, primarily for maintenance capital.
10 TRANSCANADA PIPELINES LIMITED
The BC System is regulated by the NEB on a complaint basis and the tolls are
based on a cost-of-service methodology. In December 2003, the NEB adopted
interim rates and charges for 2004 pending the resolution of certain issues with
shippers on the BC System.
OTHER GAS TRANSMISSION
TCPL actively pursues natural gas pipeline and pipeline-related development,
acquisition and operation opportunities in Canada and the United States, where
these opportunities are driven by strong customer demand.
GREAT LAKES
TCPL holds a 50 per cent interest in Great Lakes which operates a
3,387 kilometre pipeline system. This system transports Canadian natural gas
from its interconnection with the Canadian Mainline at Emerson, Manitoba to
markets in central Canada at St. Clair, Ontario and serves markets in the
eastern and midwestern United States. Great Lakes' rates are based on a five
year settlement agreement which was approved by the U.S. Federal Energy
Regulatory Commission ("FERC") in 2001 and is effective until
October 31, 2005.
TC PIPELINES, L.P.
TC PipeLines, L.P., a U.S. publicly-held limited partnership, was formed to
acquire, own and participate in the management of U.S. based pipeline assets. In
May 1999, TCPL's 30 per cent general partner interest in Northern Border was
conveyed to TC PipeLines, L.P. in exchange for cash and a 33.4 per cent interest
in TC PipeLines, L.P., 31.4 per cent of which is comprised of common units and
subordinated units, and two per cent of which is a general partnership interest.
TC PipeLines, L.P. also issued common units to the public. Northern Border
operates a 2,010 kilometre natural gas pipeline system which connects with the
Foothills System in Saskatchewan and serves the midwestern United States,
terminating at North Hayden, Indiana. In October 2001, Northern Border completed
a 55 kilometre pipeline extension and installed additional compression that
provides 545 MMcf/d of incremental transportation capacity to North Hayden,
Indiana and expanded Northern Border's delivery capability into the Chicago area
by approximately 30 per cent.
On September 1, 2000, TC PipeLines, L.P. acquired a 49 per cent general partner
interest in Tuscarora from TCPL, and TCPL, through a subsidiary, retains a one
per cent general partner interest in Tuscarora. Tuscarora is a 386 kilometre
natural gas pipeline system which has been in operation since December 1995.
This system transports natural gas from Malin, Oregon to Wadsworth, Nevada and
delivers to points in northeastern California. The Hungry Valley lateral
extension, Tuscarora's second city-gate connection into Reno, Nevada, was
completed in January 2001. On December 1, 2002, Tuscarora completed construction
and placed into service an expansion of its pipeline system, consisting of two
compressor stations and a 17 kilometre pipeline extension from the previous
terminus near Reno, Nevada to Wadsworth, Nevada. The expansion serves growing
power generation and residential requirements in northern Nevada. Tuscarora's
current contracted capacity is approximately 180 MMcf/d. In December 2003,
Tuscarora received management approval for an expansion project which will
provide for approximately 57 MMcf/d of incremental capacity on its system. The
capital cost for this expansion project is estimated to be US$16.6 million and
the expansion is scheduled to commence service in November 2005.
A subsidiary of TCPL acts as the general partner of TC PipeLines, L.P.
TRANSCANADA PIPELINES LIMITED 11
IROQUOIS
Iroquois connects with the Canadian Mainline near Waddington, New York and
delivers natural gas to customers in the northeastern United States ("IROQUOIS
SYSTEM"). TCPL's aggregate interest in the Iroquois System, through two
subsidiaries, is 41 per cent.
Iroquois' Eastchester extension and expansion was completed and the facilities
were put into service in February 2004. This expansion extends the Iroquois
System from Long Island into New York City, adding 59 kilometres to the Iroquois
System and will provide an additional 230 MMcf/d of new service into this
market. The Iroquois System is now 663 kilometres in length.
In October 2003, FERC approved Iroquois' rate settlement ("IROQUOIS
SETTLEMENT"), which was filed in August 2003. The Iroquois Settlement is
effective from January 1, 2004 until December 31, 2007, during which period
Iroquois will reduce rates by approximately 13 per cent. Iroquois filed a
separate rate application with FERC in January 2004 to establish rates for the
Eastchester expansion. FERC has issued an order accepting Iroquois' application
and the approved rates will become effective July 1, 2004, subject to refund and
conditions.
TRANS QUEBEC & MARITIMES
TCPL holds a 50 per cent interest in the 572 kilometre TQM System which connects
with the Canadian Mainline. TQM serves markets in Quebec and connects with the
Portland system. In January 2003, TCPL began performing the majority of
operating and administrative functions of TQM pursuant to a services agreement.
The TQM System is regulated by the NEB.
PORTLAND
In September 2003, TCPL purchased an additional 10.1 per cent ownership interest
in Portland for approximately US$19 million. In December 2003, TCPL purchased a
further 18.3 per cent interest for approximately US$32 million. As a result of
these two transactions, TCPL currently holds a 61.7 per cent controlling
interest in Portland.
Portland is a 471 kilometre interstate pipeline that interconnects with the
pipeline system of TQM at the United States-Canada border near East Hereford,
Quebec, and with the Tennessee Gas Pipeline in Haverhill and Dracut,
Massachusetts. The southern sections of Portland's system, consisting of
163 kilometres of pipeline, are part of the joint facilities shared with the
Maritimes and Northeast Pipeline. Portland holds a one-third ownership interest
in the joint facilities.
Portland and customer representatives reached an agreement on new tolls and
Portland submitted an uncontested agreement to FERC in October 2002, which was
approved in its entirety in January 2003. The settlement agreement is effective
from April 1, 2002 until April 1, 2008.
NORTHERN DEVELOPMENT
In 2003, TCPL continued to pursue pipeline opportunities to move both Mackenzie
Delta and Alaska North Slope natural gas to markets throughout North America.
TCPL worked with key stakeholders in the interest of participating in any
potential pipeline project.
TCPL, the Mackenzie Producers and the APG reached funding and participation
agreements in June 2003 that enable the APG to become a full participant in the
largest component of the proposed Mackenzie Gas Pipeline Project which involves
a natural gas pipeline system in the Mackenzie Valley that would move Mackenzie
Delta natural gas through a natural gas pipeline being constructed from Inuvik,
Northwest Territories to the northern border of Alberta, where it would then
connect with the Alberta System. TCPL has agreed to finance the APG for its
one-third share of project definition costs. This share is currently estimated
to be $90 million over three years. This loan will be repaid from the APG's
share of future pipeline revenues if the project proceeds. In 2003, TCPL funded
$34 million of this loan. Under the terms of the agreement, TCPL gains an
immediate opportunity to acquire up to five per cent equity ownership of the
pipeline at the time of construction. In addition, TCPL also gains certain
rights of first refusal if any of the Mackenzie Producers choose to sell their
equity. TCPL would be entitled to acquire 50 per cent of any divestitures of
existing partners and to obtain a one-third interest
12 TRANSCANADA PIPELINES LIMITED
in all expansion opportunities once the APG reaches a one-third share, with the
Mackenzie Producers and the APG sharing the balance.
TCPL continued to work with other Alaska Highway pipeline stakeholders in 2003
to advance the project. Resolution of Foothills' Special Charge was reached with
Foothills shippers and the Canadian Association of Petroleum Producers, and
subsequently approved by the NEB in March 2003. The resolution waives Foothills'
obligation to repay all past and future Special Charge collections when the
Alaskan gas starts flowing on the Foothills System. In October 2003, the
Government of Canada, reaffirmed its preference to utilize the framework
provided in the NORTHERN PIPELINE ACT (Canada) which granted Foothills the
certificates to transport Alaskan gas across Canada.
In January 2004, Foothills and the Kaska First Nation signed an Agreement in
Principle that provides the framework for a future participation agreement. The
Agreement in Principle marks the completion of the second stage of negotiations
that is expected to lead to a participation agreement for the Alaska Highway
Pipeline Project.
LIQUEFIED NATURAL GAS
In September 2003, TCPL and ConocoPhillips announced the Fairwinds Partnership
to jointly evaluate a site in Harpswell, Maine for the development of an LNG
regasification facility. Approval must first be obtained for the Fairwinds
Partnership to lease a town-owned site for the LNG regasification facility and
the residents of the Town of Harpswell are expected to vote on this matter at a
referendum which is to be held in March 2004.
VENTURES LP
TransCanada Pipeline Ventures Limited Partnership ("VENTURES LP"), which is a
subsidiary of TCPL, owns a 121 kilometre pipeline and related facilities, which
supply natural gas to the oil sands region of northern Alberta, and a
27 kilometre pipeline which supplies natural gas to a petrochemical complex at
Joffre, Alberta.
CROSSALTA
TCPL holds a 60 per cent interest in Crossfield Storage Joint Venture which
controls an underground gas storage facility near Crossfield, Alberta. The
facility is commercially operated on behalf of the joint venture by CrossAlta
Gas Storage & Services Ltd., in which TCPL also holds a 60 per cent interest.
TRANSGAS
TCPL holds a 46.5 per cent interest in TransGas de Occidente S.A., a Colombian
joint venture project which operates a 344 kilometre natural gas pipeline,
between the cities of Mariquita and Cali, Colombia.
REGULATION OF NORTH AMERICAN PIPELINES
Under the NATIONAL ENERGY BOARD ACT (Canada), the NEB regulates the construction
and operation of interprovincial pipelines and the Canadian portion of
international pipelines as well as the traffic, tolls and tariffs applicable to
those pipelines. The NEB also approves the import and export of natural gas.
Pipelines located within provincial boundaries are regulated by the applicable
provincial regulatory body.
The construction and operations of the Alberta System, Ventures LP's northern
Alberta oil sands pipeline and Joffre pipeline are regulated by the EUB.
With respect to TCPL's United States pipeline investments, the NATURAL GAS ACT
OF 1938 ("NGA") establishes the framework for regulation of interstate natural
gas transportation, facilities construction and terms and conditions of service.
FERC is charged with implementing the NGA's requirements. The terms and
conditions of service under which TCPL transports natural gas on the Great
Lakes' system are subject to NGA authorizations issued by FERC. Interconnected
natural gas pipelines and other United States interstate pipeline projects in
which TCPL has investments are subject to FERC and NGA regulation, as well as
certain state regulatory requirements.
TRANSCANADA PIPELINES LIMITED 13
Further information about the regulation of the Canadian Mainline, Alberta
System and other pipeline systems, can be found under the headings "Gas
Transmission -- Wholly-Owned Pipelines" and "Gas Transmission -- Other Gas
Transmission" above and in the MD&A under the heading "Gas
Transmission -- Canadian Regulatory Environment".
COMPETITION IN GAS TRANSMISSION
TCPL's wholly-owned pipelines are connected to and supplied by one of North
America's largest natural gas basins, the WCSB. However, the WCSB is maturing
and it will be a challenge for producers to increase production in this basin.
Other pipeline systems connected to the WCSB, including some of TCPL's
interconnected pipelines, have expanded in the last few years. These expansions
have provided shippers with additional flexibility and competitive choices when
moving WCSB supplies to market. The WCSB gas supply is not expected to increase.
The Alberta System is the primary transporter of natural gas within the province
of Alberta and to provincial boundary points. However, there are a number of
alternative pipelines which offer price advantages and which compete with the
Alberta System. In anticipation of and in response to these developments, the
Alberta System's current tolling methodology was designed to enhance NGTL's
ability to provide competitive pricing and service flexibility and to provide
TCPL with the ability to respond to potential future bypass pipelines.
The Canadian Mainline is now one of five natural gas pipelines providing
transportation service from the WCSB. Increased competition has led to the
non-renewal of some of the firm service contracts on the Alberta System and the
Canadian Mainline, and has led to decreased utilization on certain pipeline
segments.
Further information about business risks in Gas Transmission can be found under
the heading "Risk Factors -- Gas Transmission" below and in the MD&A under the
headings "Gas Transmission -- Wholly-Owned Pipelines -- Business Risks" and "Gas
Transmission -- Other Gas Transmission -- Business Risks".
RESEARCH AND DEVELOPMENT
In 2003, TCPL spent approximately $9.3 million on research and development
activities of which approximately $3.5 million related to research on pipeline
integrity management, approximately $2.8 million on other regulated pipeline
activities and approximately $3.0 million on non-regulated pipeline ventures.
POWER
The power segment of TCPL's business includes the construction, ownership,
operation and management of power plants and the marketing of electricity, and
provides electricity account services to energy and industrial customers. This
segment operates in Canada and the United States.
TCPL owns and operates:
- cogeneration plants in Alberta at Carseland (80 MW), Redwater (40 MW),
Bear Creek (80 MW) and MacKay River (165 MW);
- a waste-heat fuelled power plant at the Cancarb facility in Medicine Hat,
Alberta (27 MW);
- the Curtis Palmer hydroelectric power facility near Corinth, New York
(60 MW); and
- the gas-fired, combined-cycle Ocean State Power plant in Burrillville,
Rhode Island (560 MW).
TCPL has long-term power purchase arrangements in place for:
- 100 per cent of the production of the Sundance A (560 MW) and
50 per cent interest, through a partnership, of the production of Sundance
B (353 MW of 706 MW) power facilities near Wabamun, Alberta.
TCPL operates the following facilities owned by Power LP:
- five cogeneration power plants in Ontario and one wood-fired power plant
in British Columbia (264 MW); and
14 TRANSCANADA PIPELINES LIMITED
- one cogeneration power plant in the United States (64 MW).
TCPL owns, but does not operate:
- the simple-cycle ManChief power plant near Brush, Colorado (300 MW);
- a 31.6 per cent interest in the nuclear power generation facilities of
Bruce Power in Ontario (1,472 MW of 4,660 MW total that is in operation
and under commissioning); and
- a 17 per cent interest in Huron Wind L.P. (2 MW of a total of 9 MW).
TCPL owns the following facilities which are under construction:
- the 550 MW cogeneration Becancour plant, which is expected to be complete
in late 2006; and
- the 90 MW cogeneration Grandview plant, which is expected to be complete
by the end of 2004.
While a significant portion of TCPL's western plant generation is sold under
long-term contract, in order to mitigate price risk, some power positions are
held for short-term transactions. The western power marketing group's primary
function is to manage those open positions in order to maximize the value of
TCPL's power assets.
TCPL has a power marketing office in Westborough, Massachusetts to manage the
Ocean State Power purchase agreements and market supply obligations, and to take
advantage of additional marketing opportunities in the New England and New York
markets. The office also markets the output of Power LP's Castleton power plant.
Output from the Curtis Palmer facilities is sold under a fixed-price, long-term
power purchase agreement to Niagara Mohawk Power Corporation for a term of more
than 25 years. In 2000, the Curtis Palmer facility was re-licensed by FERC to
operate for a period of 40 years.
The entire capacity of the ManChief power plant is sold under long-term tolling
contracts that expire in 2012. Operations and maintenance services for the
ManChief power plant will continue to be supplied by the current contracted
unaffiliated service provider.
Operations and maintenance services for the Bruce Power plants continue to be
supplied by the pre-acquisition management and staff of Bruce Power. Bruce Power
sells the output from the Bruce Power plants through a combination of
fixed-price contracts and spot market sales.
TCPL and OPG, through their limited partnership, Portlands Energy Centre L.P.,
continue to study the feasibility of developing a 550 MW combined-cycle natural
gas-fuelled cogeneration power plant on a former power generation site in the
Portlands area of the Toronto, Ontario downtown waterfront.
TCPL continues to investigate potential power investment opportunities
throughout North America.
TRANSCANADA POWER, L.P.
TCPL manages, operates and is the largest unit holder of Power LP, a
publicly-held limited partnership that owns seven power plants. TCPL holds
35.6 per cent of the units of Power LP.
Power LP owns combined-cycle power plants, fuelled by a combination of natural
gas and waste heat from adjacent TCPL compression facilities, in Nipigon,
Kapuskasing, North Bay and Tunis, Ontario. It also owns a natural gas
cogeneration plant at Castleton-on-Hudson, New York and wood-waste fuelled power
plants near Hearst, Ontario and at Williams Lake, British Columbia.
TCPL supplies the natural gas fuel for certain of Power LP's plants.
Power LP's seven plants have a total generating output of 328 MW. It is the
largest publicly traded power limited partnership in Canada with a market
capitalization of approximately $1.4 billion.
TRANSCANADA PIPELINES LIMITED 15
POWER PERFORMANCE
The following tables set forth the revenues earned, power volumes marketed and
generation capacity in Canada and the United States for the years ended
December 31, 2003 and 2002 from TCPL's power operations.
2003 2002
-------------------------------- --------------------------------
REVENUES PER CENT REVENUES PER CENT
--------------------- -------- --------------------- --------
(millions of dollars) (millions of dollars)
REVENUES
Canada -- Domestic............................. 765 55 655 51
Canada -- Export............................... 2 -- -- --
United States.................................. 634 45 638 49
----- --- ----- ---
TOTAL.......................................... 1,401 100 1,293 100
===== === ===== ===
2003 2002
--------------------------- ---------------------------
VOLUME PER CENT VOLUME PER CENT
---------------- -------- ---------------- --------
(gigawatt hours) (gigawatt hours)
VOLUMES SOLD(1)(2)(3)
Canada -- Domestic............................. 20,575 74 12,560 62
Canada -- Export............................... 38 -- 10 --
United States.................................. 7,397 26 7,541 38
------ --- ------ ---
TOTAL.......................................... 28,010 100 20,111 100
====== === ====== ===
2003 2002
-------------------------- --------------------------
GENERATION PER CENT GENERATION PER CENT
--------------- -------- --------------- --------
(MW) (MW)
GENERATION CAPACITY(1)(2)(3)(4)
Canada......................................... 2,641 73 1,404 59
United States.................................. 984 27 984 41
----- --- ----- ---
TOTAL.......................................... 3,625 100 2,388 100
===== === ===== ===
NOTES:
(1) Includes 100 per cent of volumes sold by, and the generation capacity of,
Power LP (after eliminating intercompany transactions with TCPL).
(2) TCPL, directly or indirectly, acquires 560 MW from Sundance A and 353 MW
from Sundance B through long-term power purchase arrangements, which
represent 100 per cent of the Sundance A and 50 per cent of the Sundance B's
power plant output, respectively.
(3) Includes 31.6 per cent of Bruce Power.
(4) Excludes MacKay River (165 MW), Becancour (550 MW), Grandview (90 MW) and
Bruce A, Unit 3 (237 MW) which were not in commercial service at Year End.
REGULATION OF POWER
TCPL's investments in Ocean State Power, Curtis Palmer, ManChief, and TCPL's
United States electric power marketing activities are subject to the
jurisdiction of FERC under the U.S. FEDERAL POWER ACT, as well as the
jurisdiction of certain state regulatory authorities.
Deregulation of the power industry is proceeding at different stages throughout
most of the markets in which TCPL currently operates, which are primarily
Alberta, Ontario and the northeastern United States. In 2001, Alberta
deregulated its generation assets and opened the market for retailers and
wholesalers. In May 2002, the government of Ontario began the operation of a
competitive, bid-based wholesale market for electricity in Ontario, a process
that began with legislation first enacted under the ELECTRICITY ACT in 1998.
Later in 2002, after considerable volatility and rising prices under this
bid-based wholesale market, the government of Ontario put in place price caps at
the retail level, effectively shielding eligible customers from the wholesale
price volatility. In late 2003, after a change in government in Ontario, these
retail caps were adjusted upwards to be effective on April 1, 2004, to better
reflect the real cost of electricity. These caps do not directly affect the
wholesale market
16 TRANSCANADA PIPELINES LIMITED
in which TCPL is primarily focused through its interests in Ontario power
generation assets. More recently, however, the government of Ontario has
suggested it is considering further changes to the structure and operations of
the Ontario electricity market and the legislation that governs it. It is
possible that future legislative changes may have an impact on TCPL's Ontario
operations. In 1998 and 1999, respectively, the FERC began operations of
competitive, bid-based wholesale power markets in New England and New York. In
2003, New England adopted a reformed wholesale market, in line with the FERC's
long-term vision for a Standard Market Design.
COMPETITION IN POWER
TCPL's power business has operated and continues to operate in highly
competitive markets that are driven mainly by price. However, the majority of
TCPL's power generation business, excluding Bruce Power, is underpinned by
long-term or medium-term, fixed-price contracts that are unaffected by
short-term price changes in the marketplace.
Further information about business risks in TCPL's Power business can be found
in the MD&A under the headings "Risk Factors -- Power" and "Power -- Business
Risks".
OTHER INTERESTS
CANCARB LIMITED
TCPL owns Cancarb Limited, a thermal carbon black manufacturing facility located
in Medicine Hat, Alberta.
TRANSCANADA TURBINES
TCPL owns a 50 per cent interest in TransCanada Turbines Ltd., a repair and
overhaul business for aero-derivative industrial gas turbines. This business
operates primarily out of facilities in Calgary, Alberta, with offices in
Bakersfield, California; East Windsor, Connecticut; and Liverpool, England.
TRANSCANADA CALIBRATIONS
TCPL owns an 80 per cent interest in TransCanada Calibrations Ltd., a gas meter
calibration business certified by Measurement Canada, located at Ile des Chenes,
Manitoba.
DISCONTINUED OPERATIONS
Between 1999 and 2002, TCPL continued to focus on natural gas transmission and
power generation. During that time, TCPL sold substantially all of its assets in
international, midstream, and oil and gas marketing businesses that were
identified for disposition. For further information about Discontinued
Operations please refer to Note 18 of TCPL's 2003 Audited Consolidated Financial
Statements.
GAS MARKETING AND TRADING
TCPL's Board of Directors ("BOARD") approved a plan in July 2001 to dispose of
TCPL's gas marketing business and TCPL's exit from gas marketing was
substantially completed by December 31, 2001. TCPL remains contingently liable
for certain residual obligations.
INTERNATIONAL
In December 1999, TCPL announced its intention to exit from all of its
international operations and during 2000 and 2001, sold the majority of its
international businesses and assets. TCPL's remaining material international
investments are described in the following section and will be accounted for as
part of continuing operations as of Year End due to the length of time it has
taken TCPL to dispose of these assets:
TCPL holds:
- a 30 per cent interest in Gasoducto del Pacifico ("GAS PACIFICO"), a
540 kilometre natural gas pipeline from Argentina to Concepcion, Chile;
TRANSCANADA PIPELINES LIMITED 17
- a 30 per cent interest in INNERGY Holdings S.A., an industrial natural gas
transportation and marketing company operating in the area of Concepcion,
Chile, which transports gas on the Gas Pacifico system; and
- an indirect ten per cent net interest in PT Paiton Energy Company, which
owns a power project consisting of two 615-megawatt coal-fired power units
located in Indonesia.
REGULATION IN INTERNATIONAL
The majority of countries in which TCPL continues to have business interests
have various government entities in charge of drafting and implementing the
policies and regulations with respect to exploration, production,
transportation, refining, processing and distribution of hydrocarbons, as well
as all other activities related to the energy sector.
COMPETITION IN INTERNATIONAL
TCPL's international businesses are conducted in a highly competitive
environment, comprised of major energy companies and consortia with years of
international experience and established relationships. Projects were generally
awarded by way of international tender.
TCPL's international investments are subject to a number of risks unique to
international business. Such risks are mitigated by insurance policies,
participation of local and foreign partners, prudent commercial structuring and
other measures.
For additional information about international business risks, please see "Risk
Factors -- International", below.
MIDSTREAM
In 2000 and 2001, TCPL sold substantially all of its portfolio of natural gas
gathering, processing, straddle plant and extraction assets in western Canada.
In January of 2003, TCPL sold its last remaining midstream asset, the Harmattan
gas plant located near Didsbury, Alberta, thus concluding TCPL's involvement in
midstream activities.
HEALTH, SAFETY AND ENVIRONMENT
TCPL is committed to providing a safe and healthy environment for its employees
and the public, and to the protection of the environment. Health, safety and
environment ("HS&E") is a priority in all of TCPL's operations. The HS&E
Committee of the Board monitors compliance with the TCPL HS&E corporate policy
through regular reporting by TCPL's department of Community, Safety &
Environment. TCPL's senior executives are also committed to ensuring TCPL is in
compliance with its policies and is an industry leader. Senior executives are
regularly advised of all important operational issues and initiatives relating
to HS&E.
TCPL has an HS&E management system modeled after ISO 14001 elements to
facilitate the focus of resources on the areas of greatest risk to the
organization's business activities relating to HS&E. It highlights opportunities
for improvement, enables TCPL to work towards defined HS&E expectations and
objectives, and provides a competitive business advantage. HS&E audits,
management system assessments and planned inspections are used to assess both
the effectiveness of implementation of HS&E programs, processes and procedures,
and TCPL's compliance with regulatory requirements.
TCPL employs full-time staff dedicated to HS&E matters, and incorporates HS&E
policies and principles into the planning, development, construction and
operation of all its projects. Environmental protection requirements have not
had a material impact on the capital expenditures of TCPL to date; however there
can be no assurance that such requirements will not have a material impact on
TCPL's financial or operating results in future years. Such requirements can be
dependent on a variety of factors including the regulatory environment in which
TCPL operates.
18 TRANSCANADA PIPELINES LIMITED
CLIMATE CHANGE
Climate change is a strategic issue for TCPL, particularly in light of the
Canadian government's ratification of the Kyoto Protocol in December 2002. TCPL
has had a comprehensive climate change strategy in place since 1999, which
includes five key areas of activity:
- Participation in policy forums;
- Direct emissions reduction programs;
- Long-term technology development;
- Emissions offset analysis; and
- Pursuit of business opportunities.
Activities in each of these areas occurred in 2003 and will continue in 2004.
TCPL received a fifth consecutive gold level reporting status for its 2003
Voluntary Challenge and Registry ("VCR") report. To achieve gold level status,
VCR reports are rated in several categories. Only 12 per cent of the submissions
to the registry have received gold level reporting recognition.
The Kyoto Protocol, ratified by the Canadian Federal Government in
December 2002, requires Canada to reduce its greenhouse gas emissions
significantly. The Canadian government is currently developing the policies
relating to how it intends to meet these reduction targets, and until it is
completed, TCPL cannot predict the degree to which it will be affected.
PATENTS, LICENCES AND TRADEMARKS
TCPL is the beneficial owner and, in some cases, the licensee of a number of
trademarks, patents and licenses. While these trademarks, patents and licenses
constitute valuable assets, TCPL does not regard any single trademark, patent or
license as being material to its operations as a whole.
LEGAL PROCEEDINGS
TCPL is subject to various legal proceedings and actions arising in the normal
course of business. For further information, refer to Note 17 of TCPL's 2003
Audited Consolidated Financial Statements.
RISK FACTORS
A number of factors, including but not limited to those discussed in this
section, could cause actual results or events to differ materially from current
expectations.
TCPL's businesses are highly complex and are dispersed over tens of thousands of
square kilometres, often in remote locations. Pipeline and power facilities are
subject to operational risks, including mechanical failure, physical
degradation, operator error, manufacturer defects, labour disputes, terrorism,
failure of supply, catastrophic events and natural disasters. The occurrence or
continuation of such events could increase TCPL's costs and reduce its ability
to transport natural gas or generate power.
GAS TRANSMISSION
The Canadian Mainline, the Alberta System, the BC System and the Foothills
System transport natural gas from the WCSB. Continuing use of these systems is
dependent on a number of factors including the level of exploration and
development within the basin, the price of and demand for natural gas, the
ability of natural gas producers to deliver natural gas to the various pipeline
systems, the development of northern natural gas reserves, and the regulatory
environment for producers, transporters and consumers of natural gas.
Further information about competition risks in TCPL's natural gas transmission
business can be found under the heading "Business of TCPL -- Gas
Transmission -- Competition in Transmission" above and in the MD&A under the
headings "Gas Transmission -- Wholly-Owned Pipelines -- Business Risks" and
"Other Gas Transmission -- Business Risks".
TRANSCANADA PIPELINES LIMITED 19
POWER
TCPL's power business and investments rely on feed stocks of natural gas,
biomass, water, coal and uranium. Failure to obtain adequate supplies of feed
stocks could affect TCPL's ability to generate electricity and fulfill its
supply obligations, and changes in prices of feed stocks could affect TCPL's
financial results. Although TCPL takes appropriate actions to mitigate most of
these risks, there can be no assurance that such actions will be adequate in all
circumstances.
TCPL does not operate the Bruce Power facility, the ManChief Power Plant or the
assets underlying the Sundance A or Sundance B power purchase arrangements.
Failure by the operators of these facilities to operate at the cost or in the
manner projected by TCPL could negatively affect TCPL's financial position.
TCPL does not own any of the power transmission lines over which its electricity
is transmitted and delivered. Any disruption in transmission could affect TCPL's
ability to supply electricity and could have an adverse impact on TCPL's
financial results.
Further information about competition risks in TCPL's power business can be
found under the headings "Business of TCPL -- Power -- Competition in Power"
above and in the MD&A under the heading "Power -- Business Risks".
INTERNATIONAL
TCPL's international investments are subject to a number of risks unique to
international business. These risks include exchange controls and fluctuation of
the local currency, political risk, community actions, changes in laws, price
control, the availability and quality of local labour skills, and labour unrest,
among others. Such risks are mitigated by insurance policies, participation of
local and foreign partners, prudent commercial structuring and other measures.
CORPORATE
TCPL carries on its businesses with numerous counterparties with a wide range of
creditworthiness. While processes are followed to address the creditworthiness
of certain of these counterparties, the failure of any counterparty to meet its
financial obligations could have an impact on TCPL's financial position. Such
failure could result from a number of factors beyond TCPL's control, including
(but not limited to) fluctuating commodity energy prices and interest rates,
changes in regulatory and economic environments, political instability and
legally reviewable activities.
TCPL operates in Canada and the United States and as a result, its financial
performance can be impacted by interest rates and foreign exchange rates. TCPL
has an active hedging program in place to address interest and foreign exchange
rate risks, but there can be no assurance that such hedging will be adequate to
address the risks.
TCPL's growth strategy is dependent upon acquiring or constructing facilities
and businesses that align with its current businesses. TCPL may incur costs in
the pursuit of acquisitions or development of power or natural gas transmission
assets that may not be completed. Failure by TCPL to consummate negotiated
acquisitions or new developments may result in contractual liabilities,
liquidated damages, additional costs and expenses which could affect financial
performance.
TCPL's growth is also dependent on access to capital markets in the
United States and Canada. Although significant credit facilities are currently
available, changing market conditions could result in a materially increased
cost of capital which would reduce TCPL's ability to pursue this growth.
Further information about TCPL's risk factors and risk management can be found
in the MD&A under the headings "Gas Transmission -- Wholly-Owned
Pipelines -- Business Risks", "Gas Transmission -- Other Gas
Transmission -- Business Risks", "Power -- Power-Business Risks" and "Liquidity
and Capital Resources -- Risk Management".
20 TRANSCANADA PIPELINES LIMITED
FINANCIAL INFORMATION
THREE YEAR SELECTED CONSOLIDATED FINANCIAL INFORMATION
Selected consolidated financial information for the years ended December 31,
2003, 2002 and 2001 is found in the MD&A under the heading "Selected Three Year
Consolidated Financial Data".
For a discussion on the factors affecting the comparability of the financial
data, including discontinued operations, refer to Notes 1 and 18 of TCPL's 2003
Audited Consolidated Financial Statements.
DIVIDENDS
TCPL has no formal dividend policy. The Board annually reviews the financial
performance of TCPL and makes a determination of the appropriate level of
dividend to be declared in the following year.
Certain of TCPL's outstanding preferred shares contain restrictions requiring
that no dividends shall be declared or paid on common shares unless all
dividends payable on all shares ranking in priority to the common shares with
respect to payment of dividends have been declared and paid. In addition, there
are provisions in the various trust indentures and credit agreements to which
TCPL is a party, which restrict the payment of dividends on TCPL's common shares
in certain limited circumstances. At Year End, such provisions did not restrict
or alter TCPL's ability to declare or pay dividends.
MARKET FOR SECURITIES
TCPL's common shares are not listed as they are owned by TransCanada.
TCPL's Cumulative Redeemable First Preferred Shares, Series U and Series Y are
listed on the Toronto Stock Exchange.
TCPL's 8.25% preferred securities due 2047, are listed on the New York Stock
Exchange.
TCPL's 16.50% First Mortgage Pipe Line Bonds due 2007, are listed on the London
Stock Exchange.
NGTL's 7.875% debentures due April 1, 2023, are listed on the New York Stock
Exchange.
TRANSCANADA PIPELINES LIMITED 21
DIRECTORS AND OFFICERS
All of the issued and outstanding common shares of TCPL are owned by TransCanada
and thus, the directors and officers of TCPL hold no common shares in TCPL.
DIRECTORS
Set forth below are the names of the twelve directors who served on TCPL's Board
at Year End, together with their municipalities of residence, all positions and
offices held by them with TCPL and its significant affiliates, their principal
occupations or employment during the past five years and the year from which
each director has served as a director of TCPL. Current positions and offices
held with TCPL are, since the arrangement with TransCanada, also held by such
person at TransCanada.
NAME PRINCIPAL OCCUPATION DURING THE FIVE PRECEDING YEARS DIRECTOR SINCE
---- ---------------------------------------------------- ---------------
Douglas D. Baldwin, P. Eng. Chairman, Talisman Energy Inc., (oil and gas) since 1999
Calgary, Alberta May 2003. President and Chief Executive Officer,
TCPL from August 1999 to April 2001. Director,
Calgary Airport Authority, Citadel Group of Funds,
Resolute Energy Inc. and UTS Energy Corporation.
Member, Board of Governors, University of Calgary.
Wendy K. Dobson Professor, Rotman School of Management and Director, 1992
Uxbridge, Ontario Institute for International Business, University of
Toronto (education). Director, MDS Inc., The
Toronto-Dominion Bank and Vice Chair, Canadian
Public Accountability Board.
The Hon. Paule Gauthier, Senior Partner, Desjardins Ducharme Stein Monast 2002
P.C., O.C., O.Q., Q.C. (law firm). Director, Royal Bank of Canada, The
Quebec, Quebec Royal Trust Corporation of Canada, The Royal Trust
Company, Rothmans Inc. and Metro Inc. Chair,
Security Intelligence Review Committee. President,
Fondation de la Maison Michel Sarrazin and
President, Institut Quebecois des Hautes Etudes
Internationales, Laval University.
Richard F. Haskayne, Chairman of the Board, TransCanada and TCPL. Prior 1998
O.C., F.C.A. to February 19, 2003, Chairman, Fording Inc. (coal (NOVA, 1991)(1)
Calgary, Alberta and wolastonite). Director, EnCana Corporation and
Weyerhaeuser Company.
Kerry L. Hawkins President, Cargill Limited (grain handlers, 1996
Winnipeg, Manitoba merchants, transporters, processors of agricultural
products and gas marketers). Director, NOVA
Chemicals Corporation, Shell Canada Limited and
Hudson's Bay Company.
S. Barry Jackson Chairman, Resolute Energy Inc. (oil and gas) since 2002
Calgary, Alberta 2002 and Chairman, Deer Creek Energy Limited (oil
and gas) since 2001. President and Chief Executive
Officer, Crestar Energy Inc. (oil and gas) from 1993
to 2000. Director, Nexen Inc.
22 TRANSCANADA PIPELINES LIMITED
NAME PRINCIPAL OCCUPATION DURING THE FIVE PRECEDING YEARS DIRECTOR SINCE
---- ---------------------------------------------------- ---------------
Harold N. Kvisle, P. Eng. President and Chief Executive Officer, TransCanada 2001
Calgary, Alberta since May 2003 and TCPL since May 2001. Executive
Vice-President, Trading and Business Development,
TCPL from June 2000 to April 2001. Senior
Vice-President, Trading and Business Development,
TCPL from April 2000 to June 2000. Senior
Vice-President and President, Energy Operations,
TCPL, from September 1999 to April 2000. Prior to
September 1999, President, Fletcher Challenge Energy
Canada Inc. (oil and gas). Director, Norske Skog
Canada Limited, PrimeWest Energy Inc. and
TransCanada Power, L.P.. Chair, Interstate National
Gas Association of America and Chair, Mount Royal
College.
David P. O'Brien(2) Chairman, EnCana Corporation (oil and gas) since 2001
Calgary, Alberta April 2002. Chairman and Chief Executive Officer,
PanCanadian Energy Corporation (oil and gas) from
October 2001 to April 2002. Chairman, President and
Chief Executive Officer, Canadian Pacific Limited
(transportation, energy and hotels) from May 1996 to
October 2001. Director, Royal Bank of Canada,
Fairmont Hotels & Resorts Inc., Inco Limited,
Molson Inc., Profico Energy Management Ltd. and The
E & P Limited Partnership.
James R. Paul Chairman, James and Associates (private investment 1996
Kingwood, Texas firm). Member of the Advisory Board, AMEC PLC.
Harry G. Schaefer, F.C.A. President, Schaefer & Associates (business advisory 1987
Calgary, Alberta services). Vice-Chairman of the Board, TransCanada
and TCPL. Chairman, Crestar Energy Inc. (oil and
gas) from May 1996 to November 2000. Director,
Agrium Inc. and Fording Canadian Coal Trust.
Chairman, Alberta Chapter, Institute of Corporate
Directors and Chair, The Mount Royal College
Foundation.
W. Thomas Stephens Corporate Director. Chief Executive Officer, 1999
Greenwood Village, Colorado MacMillan Bloedel Limited (forest products) from
October 1997 to October 1999. Director, Xcel
Energy Inc., Norske Skog Canada Limited, Qwest
Communications International Inc. and The Putnam
Funds.
Joseph D. Thompson, Chairman, PCL Construction Group Inc. (general 1995
P. Eng. construction contractors). Director, NOVA Chemicals
Edmonton, Alberta Corporation.
NOTES:
(1) NOVA Corporation merged with TCPL on July 2, 1998.
(2) Mr. O'Brien was a director with Air Canada on April 1, 2003 when Air Canada
filed for protection under the COMPANIES' CREDITORS ARRANGEMENT ACT
(Canada). Mr. O'Brien resigned as a director from Air Canada in
November 2003.
Each director holds office until the next annual meeting or until his or her
successor is earlier elected or appointed.
TRANSCANADA PIPELINES LIMITED 23
TCPL has four Board committees: the Audit Committee, the Governance Committee,
the Health, Safety and Environment Committee and the Human Resources Committee.
The members of each of these committees are identified below:
AUDIT COMMITTEE GOVERNANCE COMMITTEE
Chair: H.G. Schaefer Chair: W.K. Dobson
Members: P. Gauthier Members: D.D. Baldwin
K.L. Hawkins D.P. O'Brien
S.B. Jackson J.R. Paul
J.R. Paul H.G. Schaefer
HEALTH, SAFETY & ENVIRONMENT COMMITTEE HUMAN RESOURCES COMMITTEE
Chair: D.D. Baldwin Chair: K.L. Hawkins
Members: P. Gauthier Members: W.K. Dobson
S.B. Jackson D.P. O'Brien
W.T. Stephens W.T. Stephens
J.D. Thompson J.D. Thompson
Further information about TCPL's Board committees and corporate governance can
be found in TransCanada's Management Proxy Circular dated February 24, 2004
under the heading "Compensation and Other Information -- Corporate Governance".
OFFICERS
All of the executive officers and corporate officers of TCPL reside in Calgary,
Alberta. Current positions and offices held with TCPL are also held by such
person at TransCanada. As of February 24, 2004, the officers of TCPL, their
present positions within TCPL and their principal occupations during the five
preceding years are as follows:
EXECUTIVE OFFICERS
NAME PRESENT POSITION HELD PRINCIPAL OCCUPATION DURING THE FIVE PRECEDING YEARS
---- ---------------------------------- ----------------------------------------------------
Harold N. Kvisle President and Chief Executive Executive Vice-President, Trading and Business
Officer Development, June 2000 to April 2001. Senior
Vice-President, Trading and Business Development,
April 2000 to June 2000. Senior Vice-President and
President, Energy Operations, September 1999 to
April 2000. Prior to September 1999, President,
Fletcher Challenge Energy Canada Inc. (oil and gas).
Albrecht W.A. Bellstedt, Q.C.(1) Executive Vice-President, Law and Senior Vice-President, Law and General Counsel,
General Counsel April 2000 to June 2000. Senior Vice-President, Law
and Administration, September 1999 to April 2000.
Prior to September 1999, Senior Vice-President, Law
and Chief Compliance Officer.
24 TRANSCANADA PIPELINES LIMITED
NAME PRESENT POSITION HELD PRINCIPAL OCCUPATION DURING THE FIVE PRECEDING YEARS
---- ---------------------------------- ----------------------------------------------------
Russell K. Girling Executive Vice-President, Executive Vice-President and Chief Financial
Corporate Development and Chief Officer, June 2000 to March 2003. Senior
Financial Officer Vice-President and Chief Financial Officer,
August 1999 to June 2000. Prior to August 1999,
Vice-President, Finance.
Dennis J. McConaghy Executive Vice-President, Gas Senior Vice-President, Business Development,
Development October 2000 to
May 2001. Senior Vice-President,
Midstream/Divestments, June 2000 to October 2000.
Prior to June 2000 Vice-President, Corporate
Strategy and Planning.
Alexander J. Pourbaix Executive Vice-President, Power Executive Vice-President, Power Development,
May 2001 to March 2003. Senior Vice-President,
Power Ventures, June 2000 to May 2001. Prior to
June 2000, Vice-President, Corporate Development,
Power Services.
Sarah E. Raiss Executive Vice-President, Executive Vice-President, Human Resources and Public
Corporate Services Sector Relations, June 2000 to January 2002. Senior
Vice-President, Human Resources and Public Sector
Relations, February 2000 to June 2000. Senior
Vice-President, Human Resources, March 1999 to
February 2000. President of S.E. Raiss Group, Inc.
(organizational consulting) prior to March 1999.
Ronald J. Turner Executive Vice-President, Gas Executive Vice-President, Operations and
Transmission Engineering, December 2000 to March 2003. Executive
Vice-President, International, June 2000 to December
2000. Senior Vice-President, International, April
2000 to June 2000. President, International, August
1999 to April 2000 and Senior Vice-President, July
1998 to April 2000.
Donald M. Wishart Executive Vice-President, Senior Vice-President, Field Operations, June 2000
Operations and Engineering to March 2003. August 1999 to June 2000, Senior
Vice-President, Operations, Transmission Division.
Prior to August 1999, Senior Vice-President, Project
Development, TransCanada International Ltd.
NOTE:
(1) Mr. Bellstedt, who serves as a trustee of Atlas Cold Storage Income Trust,
is subject to an Ontario Securities Commission cease trade order issued in
respect of all insiders of Atlas Cold Storage Income Trust.
TRANSCANADA PIPELINES LIMITED 25
CORPORATE OFFICERS
NAME PRESENT POSITION HELD PRINCIPAL OCCUPATION DURING THE FIVE PRECEDING YEARS
---- ---------------------------------- ----------------------------------------------------
Ronald L. Cook Vice-President, Taxation Prior to April 2002, Director, Taxation.
Rhondda E.S. Grant Vice-President and Corporate Prior to September 1999, Corporate Secretary and
Secretary Associate General Counsel, Corporate.
Lee G. Hobbs Vice-President and Controller Director, Accounting, May 1999 to July 2001. Prior
to May 1999, Chief Financial Officer, Snow Leopard
Resources Inc. (oil and gas).
Garry E. Lamb Vice-President, Risk Management Vice-President, Audit and Risk Management,
June 2000 to October 2001. Vice-President, Risk
Management, February 2000 to June 2000.
Vice-President, Risk Identification and
Quantification, September 1999 to February 2000.
Prior to September 1999, General Manager,
Counterparty Risk.
Donald R. Marchand Vice-President, Finance and Prior to September 1999, Director, Finance.
Treasurer
CORPORATE GOVERNANCE
The Board and members of TCPL's management are committed to the highest
standards of corporate governance. TCPL is subject to a variety of corporate
governance guidelines and requirements enacted by the Toronto Stock Exchange
("TSX"), the Canadian Securities Administrators ("CSA"), the New York Stock
Exchange ("NYSE"), and by the U.S. Securities and Exchange Commission ("SEC")
under the United States SARBANES-OXLEY ACT of 2002. TCPL's corporate governance
practices comply with the TSX Company Corporate Governance Guidelines,
governance rules of the NYSE applicable to foreign issuers and applicable
requirements of the CSA and SEC. TCPL is also in substantial early compliance
with the CSA Multilateral Instrument 52-110 pertaining to audit committees that
comes into force on March 30, 2004 and becomes applicable to TCPL in 2005, and
with proposed corporate governance guidelines released for comment by the CSA on
January 16, 2004 which are expected to be in force in 2005. Full disclosure of
TCPL's corporate governance practices are set out in TransCanada's Management
Proxy Circular dated February 24, 2004. The following corporate governance
disclosure documents are attached to this AIF for reference:
Schedule "B" -- Corporate Governance Guidelines
Schedule "C" -- Code of Business Ethics for Employees
Schedule "D" -- Code of Business Ethics for Directors
Schedule "E" -- Code of Business Ethics for the President & Chief Executive
Officer, Chief Financial Officer and Controller
Schedule "F" -- Charter of the Audit Committee
Schedule "G" -- Charter of the Governance Committee
Schedule "H" -- Charter of the Health, Safety & Environment Committee
Schedule "I" -- Charter of the Human Resources Committee
26 TRANSCANADA PIPELINES LIMITED
ADDITIONAL INFORMATION
1. Additional information including compensation of directors and officers,
indebtedness of directors and officers, principal holders of TCPL's
securities, options to purchase securities and interests of insiders in
material transactions (all where applicable), is contained in TCPL's Annual
Filing of Reporting Issuer (Form 28) dated February 24, 2004 ("AFF"), which
can be obtained upon request from the Corporate Secretary of TCPL.
2. Additional financial information is provided in TCPL's 2003 Audited
Consolidated Financial Statements.
3. TCPL will provide to any person or company upon request to the Corporate
Secretary of TCPL:
(a) when the securities of TCPL are in the course of a distribution under a
preliminary short form prospectus or a short form prospectus:
(i) one copy of TCPL's latest Annual Information Form, together with one
copy of any document, or the pertinent pages of any document,
incorporated by reference in the Annual Information Form;
(ii) one copy of the comparative financial statements of TCPL for TCPL's
most recently completed financial year for which financial
statements have been filed, together with the accompanying report
of the auditor and one copy of the most recent interim financial
statements of TCPL that have been filed, if any, for any period
after the end of its most recently completed financial year;
(iii) one copy of any annual filing of reporting issuers of TCPL; and
(iv) one copy of any other documents incorporated by reference into the
preliminary short form prospectus or the short form prospectus and
are not required to be provided under (i), (ii) or (iii) above; or
(b) at any other time, one copy of any other document referred to in
paragraphs (3)(a)(i), (ii) and (iii) above, provided that TCPL may
require the payment of a reasonable charge if the request is made by a
person or company who is not a security holder of TCPL.
4. Additional information, including director's and officer's remuneration and
indebtedness, principal holders of TCPL's securities, options to purchase
securities and interests of insiders in material transactions, if
applicable, is contained in TCPL's AFF and additional information is
provided in TCPL's comparative financial statements for its most recently
completed financial year.
TRANSCANADA PIPELINES LIMITED 27
SCHEDULE "A"
EXCHANGE RATE OF THE CANADIAN DOLLAR
All dollar amounts are in Canadian dollars, except where otherwise indicated.
The following table shows the high and low spot rates, the 90 day average noon
rates and the year-end noon spot rates for the United States dollar for the past
five years, each expressed in Canadian dollars, as reported by the Bank
of Canada.
AS AT DECEMBER 31
----------------------------------------------------------------
2003 2002 2001 2000* 1999
-------- -------- -------- -------- --------
High................................................ 1.2970 1.5801 1.5975 1.5035 1.4551
Low................................................. 1.2839 1.5768 1.5899 1.4946 1.4420
90 Day Average Noon Rate............................ 1.2975 1.5853 1.5934 1.4976 1.4402
Year-End Noon....................................... 1.2924 1.5796 1.5926 1.5002 1.4433
* Exchange rates for 2000 are as at December 29, 2000.
On February 24, 2004, the noon rate for the United States dollar as reported by
the Bank of Canada was US $1.00 = Cdn. $1.3280.
METRIC CONVERSION TABLE
The conversion factors set out below are approximate factors. To convert from
Metric to Imperial multiply by the factor indicated. To convert from Imperial to
Metric divide by the factor indicated.
METRIC IMPERIAL FACTOR
------ -------- ------
Kilometres Miles 0.62
Millimetres Inches 0.04
Gigajoules Million British thermal units 0.95
("MMBTU")
Cubic metres* Cubic feet 35.3
Kilopascals Pounds per square inch ("PSI") 0.15
Degrees Celsius Degrees Fahrenheit to convert to Fahrenheit multiply by
1.8, then add 32 degrees;
to convert to Celsius subtract
32 degrees, then divide by 1.8
* The conversion is based on natural gas at a base pressure of
101.325 kilopascals and at a base temperature of 15(o) Celsius.
28 TRANSCANADA PIPELINES LIMITED
SCHEDULE "B"
--------------------------------------------------------------------------------
TRANSCANADA PIPELINES LIMITED
CORPORATE GOVERNANCE GUIDELINES
FEBRUARY 2004
--------------------------------------------------------------------------------
TRANSCANADA PIPELINES LIMITED 29
TABLE OF CONTENTS
PAGE
--------
A. INTRODUCTION........................................................ 31
B. BOARD ORGANIZATION AND MEMBERSHIP................................... 31
1. Chair of the Board.......................................... 31
2. Non-Executive Chair......................................... 31
3. Lead Director Concept....................................... 31
4. Board Size.................................................. 31
5. Inside and Outside Directors................................ 32
6. "Independence" of Outside Directors......................... 32
7. Primary Employment Status Change............................ 32
8. Officers' Board Membership.................................. 32
9. Criteria for Board Membership............................... 32
10. Selection of New Director Candidates........................ 32
11. New Director Orientation.................................... 33
12. Fixed Terms for Membership on the Board..................... 33
13. Retirement Age.............................................. 33
14. Board Compensation.......................................... 33
15. Share Ownership by Directors................................ 33
C. BOARD MEETINGS AND MATERIALS........................................ 33
1. Board Meeting Agendas....................................... 33
2. Meeting Materials Distributed in Advance.................... 33
3. Presentations............................................... 34
4. Non-Directors at Board Meetings............................. 34
5. Outside Directors........................................... 34
D. COMMITTEE ORGANIZATION AND MEETINGS................................. 34
1. Board Committees............................................ 34
2. Outside, Unrelated and Independent Directors................ 34
3. Assignment and Rotation of Committee Members................ 34
4. Committee Meetings.......................................... 34
5. Committee Agendas........................................... 34
E. BOARD AND MANAGEMENT RESPONSIBILITIES............................... 34
1. Board Relationship with Management.......................... 34
2. Corporate Strategy.......................................... 35
3. Limits to Management Authority.............................. 35
4. Formal Evaluation of the President and Chief Executive 35
Officer.....................................................
5. Succession Planning and Management Development.............. 35
6. Principal Risks............................................. 35
7. Internal Controls and Management Information Systems........ 35
8. Board Communications Policy................................. 36
9. Outside Advisors for Individual Directors................... 36
10. Assessing the Performance of the Board, Committees and 36
Individual Directors........................................
30 TRANSCANADA PIPELINES LIMITED
TRANSCANADA PIPELINES LIMITED
(THE "COMPANY")
CORPORATE GOVERNANCE GUIDELINES
A. INTRODUCTION
The board of directors of the Company and its management are committed to
maintaining a high standard of corporate governance. This commitment
includes adherence to the definition of corporate governance included in the
1994 Toronto Stock Exchange Committee Report on Corporate Governance in
Canada. The report defined corporate governance as meaning "the process and
structure used to direct and manage the business and affairs of a company
with the objective of enhancing shareholder value, which includes ensuring
the financial viability of the business. The process and structure define
the division of power and establish mechanisms for achieving accountability
among shareholders, the board of directors and management. The direction and
management of the business should take into account the impact on other
stakeholders such as employees, customers, suppliers and communities".
The Company is subject to a variety of corporate governance guidelines and
requirements enacted by the Toronto Stock Exchange ("TSX"), the Canadian
Securities Administrators ("CSA"), the New York Stock Exchange ("NYSE") and
by the U.S. Securities and Exchange Commission ("SEC") under its rules and
those mandated by the United States Sarbanes-Oxley Act of 2002 ("SOX"). The
Company's corporate governance practices comply with the TSX Company Manual
Corporate Governance Guidelines, governance rules of the NYSE applicable to
foreign issuers and applicable requirements of the CSA and the SEC. The
Company is also in substantial compliance with the CSA's Multilateral
Instrument pertaining to audit committees that comes into force on
March 30, 2004 and is applicable in 2005, and with the proposed corporate
governance guidelines released for comment by the CSA on January 16, 2004
and which are expected to be in force in 2005.
The board has the responsibility for the overall stewardship of the Company,
establishing the overall policies and standards for the Company in the
operation of its businesses, and reviewing and approving the strategic
plans. In addition, the board monitors and assesses overall performance and
progress in meeting the Company's goals. Day to day management is the
responsibility of the president and chief executive officer and senior
management. To this end, the board has adopted the following guidelines to
assist it in its corporate governance responsibilities.
B. BOARD ORGANIZATION AND MEMBERSHIP
1. CHAIR OF THE BOARD
The board has currently determined to separate the positions of chairman
of the board ("chair") and president and chief executive officer.
2. NON-EXECUTIVE CHAIR
The board has determined the chair of the Company shall serve in a
non-executive capacity and shall be appointed by the board based on the
recommendations of the Governance Committee, the committee of the board
that has been delegated the responsibility to assess candidates for the
position.
3. LEAD DIRECTOR CONCEPT
The board has adopted a policy that it have an independent director
assume the responsibility of chairing scheduled meetings of outside
directors or other responsibilities which the outside directors as a
whole might designate from time to time. This will be the Chairman, if an
outside director, or the chair of the Governance Committee, if not.
4. BOARD SIZE
Although the maximum number of directors permitted by TransCanada's
Articles is 20, the board has determined that it is in the best interests
of the Company to maintain a smaller board, in the range of
TRANSCANADA PIPELINES LIMITED 31
12 to 14. It is the board's belief that this range is currently
sufficient to provide a diversity of expertise and opinions and allow
effective committee organization, yet small enough for efficient meetings
and decision-making.
The Governance Committee is mandated to review the size of the board from
time to time and recommend changes in size to the board when appropriate.
The board has the ability to increase or decrease its size within limits
defined by Articles of the Company.
5. INSIDE AND OUTSIDE DIRECTORS
The board believes that, as a matter of policy, there should be a
majority of outside, unrelated and independent directors on the Company's
board. To this end, the board has determined the number of officers or
senior managers of the Company or its subsidiaries who may serve as
directors at any one time shall be limited to a maximum of three.
On matters of corporate governance, decisions will be made by the
unrelated directors.
6. "INDEPENDENCE" OF OUTSIDE DIRECTORS
The Governance Committee undertakes an annual review to determine the
existence of any relationships with the Company and to ensure the
majority of directors are independent and unrelated to the Company, that
all Committee members are independent and, where any relationships exist,
the director is acting appropriately. The board annually determines the
independent and unrelated status of each director, based on the
Governance Committee's recommendations.
7. PRIMARY EMPLOYMENT STATUS CHANGE
The board has adopted a policy that requires any director whose primary
employment status changes to notify the chair of the Governance
Committee. A director in such circumstances is also deemed to have
submitted his or her resignation from the Board. The Governance Committee
shall in turn advise the board and provide recommendations on the
member's continued service to the Company as a director. It is not
intended that directors who retire or whose professional positions change
should necessarily leave the board. The Governance Committee has the
responsibility to assess the continued appropriateness of board
membership under such circumstances.
8. OFFICERS' BOARD MEMBERSHIP
The board has determined that management members of the board shall not
automatically stand for re-election after retirement or resignation from
the Company. Any former officer of the Company serving on the board will
be considered to be an inside director for purposes of corporate
governance until such time as the applicable regulatory cooling off
periods have been met and the outside directors determine that sufficient
distance has been established from the officer's former executive duties
to make the officer independent and unrelated to the Company.
9. CRITERIA FOR BOARD MEMBERSHIP
The Governance Committee reviews each year the general and specific
criteria applicable to candidates to be considered for nomination to the
board. The objective of this review is to maintain the composition of the
board in a way that provides the best mix of skills and experience to
guide the long-term strategy and ongoing business operations of the
Company. This review takes into account the desirability of maintaining a
reasonable diversity of backgrounds, skills and experience and personal
characteristics such as age, gender, geographic residence, etc. among the
directors along with the key common qualities required for effective
board participation.
10. SELECTION OF NEW DIRECTOR CANDIDATES
The board is responsible for identifying suitable candidates to be
recommended for election to the board by the shareholders. The Governance
Committee has the responsibility for assessing potential nominees,
screening their qualifications against the current skill and experience
requirements of the board and making recommendations in this regard to
the board. Directors are encouraged to identify potential candidates. The
chair and president and chief executive officer are consulted and have
input
32 TRANSCANADA PIPELINES LIMITED
into the process. An invitation to stand as a nominee for election to the
board will normally be made to a candidate by the board through the chair
or the chair's delegate.
11. NEW DIRECTOR ORIENTATION
New directors are provided with an orientation and education program that
includes written information about the duties and obligations of
directors, the business and operations of the Company, documents from
recent board meetings, and opportunities for meetings and discussion with
senior management and other directors. The details of the orientation of
each new director are tailored to that director's individual needs and
areas of interest.
12. FIXED TERMS FOR MEMBERSHIP ON THE BOARD
The board does not believe it should establish a fixed term for
membership on the board. While fixed terms could help ensure that there
are fresh ideas and views available to the board, they have the
disadvantage of losing the contribution of directors who have developed,
over a period of time, increased insight into the Company and its
operations and who, therefore, can be expected to provide an increasing
contribution to the board as a whole.
13. RETIREMENT AGE
The board reviews the mandatory retirement age for directors from time to
time. The board has currently determined that no person shall stand for
election or re-election to the board if he or she attains the age of
70 years on or before the date of the annual meeting called in relation
to the election of directors.
14. BOARD COMPENSATION
The Governance Committee reviews the compensation of directors on an
annual basis, taking into account such matters as time commitment,
responsibility and compensation provided by comparative companies. The
Committee makes recommendations to the board for consideration when it
believes changes in compensation are warranted.
15. SHARE OWNERSHIP BY DIRECTORS
The board has determined that share ownership by directors is a positive
step in helping directors align their interests with those of the
shareholders. As the Company is a wholly owned subsidiary, of TransCanada
Corporation, directors of the Company fulfill their share ownership
requirement by owning shares in the parent, TransCanada Corporation. The
board has adopted a policy guideline requiring directors to hold at least
five times the value of their annual board retainer in common shares of
TransCanada Corporation. Such holdings can be acquired over a period of
five years and can take the form of actual share ownership or by holding
the equivalent number of units in the Directors' Deferred Share Unit
Plan.
C. BOARD MEETINGS AND MATERIALS
1. BOARD MEETING AGENDAS
The chair and the president and chief executive officer establish the
agenda for each board meeting.
Any board member may suggest the inclusion of items on the agenda in
advance of the meeting.
2. MEETING MATERIALS DISTRIBUTED IN ADVANCE
The board has determined that information and data that are important to
the board's understanding of business issues be distributed to the board
before each board meeting in sufficient time to ensure adequate
opportunity exists for members' review. Management makes every attempt to
make this material as concise as possible while still providing the
desired information and focusing attention on critical issues to be
considered by the board.
TRANSCANADA PIPELINES LIMITED 33
3. PRESENTATIONS
As a general rule and when appropriate, presentation materials are sent
to the board members in advance. Time is allocated at all board meetings
to ensure that members' questions about the material can be answered.
4. NON-DIRECTORS AT BOARD MEETINGS
The board appreciates the value of the regular attendance at each board
meeting of non-board members who are members of the Company's senior
management.
Attendance by senior management is determined by the president and chief
executive officer with the concurrence of the chair.
Management attendees are excused for any agenda items that are reserved
for discussion among directors only.
5. OUTSIDE DIRECTORS
Directors who are not members of management meet at the end of each board
meeting IN-CAMERA to discuss matters of interest independent of
management.
D. COMMITTEE ORGANIZATION AND MEETINGS
1. BOARD COMMITTEES
Each committee operates according to board-approved terms of reference.
The committees are: (1) the Audit Committee; (2) the Governance
Committee; (3) the Health, Safety and Environmental Committee; and
(4) the Human Resources Committee.
2. OUTSIDE, UNRELATED AND INDEPENDENT DIRECTORS
The board believes that, as a matter of policy, each of the Committees
should be composed entirely of independent and unrelated directors. The
applicable requirements are addressed in the charters of each Committee.
3. ASSIGNMENT AND ROTATION OF COMMITTEE MEMBERS
The Governance Committee is responsible for recommending to the board the
assignment of board members to various committees in consultation with
the chair, the president and chief executive officer, and taking into
account the wishes of individual board members.
The board favours the periodic rotation of committee members and
committee chairs. Such rotation, when recommended, will be made in a way
that recognizes and balances the need for renewal of ideas, continuity,
and the utilization of each director's particular expertise.
4. COMMITTEE MEETINGS
Committee chairs, in consultation with committee members, determine the
frequency (consistent with the committee's terms of reference) and length
of the meetings of the committees. Each committee reports to the board on
the results of each meeting.
5. COMMITTEE AGENDAS
The chair of each committee, in consultation with the appropriate members
of management, develops the committee's agendas. The chair of each
committee ensures that the committee meets sufficiently often to
discharge its delegated responsibilities.
E. BOARD AND MANAGEMENT RESPONSIBILITIES
1. BOARD RELATIONSHIP WITH MANAGEMENT
The board supports and encourages the members of the Company's management
in the performance of their duties and individual outside directors are
encouraged to provide their counsel as needed.
34 TRANSCANADA PIPELINES LIMITED
Management makes appropriate use of the board's skills before decisions
are brought forward on key issues.
Board members have complete access to management for relevant
information. It is understood that board members will be prudent and be
sure that this contact is not distracting to the business operation of
the Company and that such contact, if in writing, be copied to the
president and chief executive officer and the chair.
The board encourages senior management to bring managers into board
meetings from time to time to provide additional insight into the items
being discussed. Such managers are expected to be those with growth
potential who would benefit from their exposure to the board.
2. CORPORATE STRATEGY
The board believes that management is responsible for development of
corporate strategy. It is the role of the board to review, question,
validate and approve material changes in the strategies of the Company.
3. LIMITS TO MANAGEMENT AUTHORITY
The board establishes general authority guidelines that places limits on
management's approval authority depending on the nature and size of the
proposed transaction. These limits anticipate that some flexibility
exists within approved budgets but otherwise must not be exceeded without
prior board or appropriate committee approval.
4. FORMAL EVALUATION OF THE PRESIDENT AND CHIEF EXECUTIVE OFFICER
The Human Resources Committee conducts an annual review of the
performance of the president and chief executive officer as measured
against objectives established mutually in the prior year by the Human
Resources Committee and the president and chief executive officer. The
results of this annual review is communicated to the board's unrelated
directors who then make an evaluation of the overall performance of the
president and chief executive officer. This performance evaluation is
communicated to the president and chief executive officer by the chair
and the chair of the Human Resources Committee. The evaluation is used by
the Human Resources Committee in its deliberations concerning the
president and chief executive officer's annual compensation.
5. SUCCESSION PLANNING AND MANAGEMENT DEVELOPMENT
The board believes that succession planning and management development
are key to the ongoing process that contributes substantially to the
success of the Company. The president and chief executive officer
provides a detailed annual report to the Human Resources Committee and a
summary presentation to the board. The president and chief executive
officer makes available to the Human Resources Committee his
recommendation as to a successor in the event of the unexpected
incapacity of the president and chief executive officer.
6. PRINCIPAL RISKS
The board is responsible for understanding the principal risks associated
with the Company's business on an ongoing basis and it is the
responsibility of management to assure that the board and its committees
are kept well informed of these changing risks on a timely basis. It is
important that the board understand and support the key risk decisions of
management, which includes comprehending the appropriate balance between
risks and rewards.
7. INTERNAL CONTROLS AND MANAGEMENT INFORMATION SYSTEMS
Fundamental to the discharge of the board's overall responsibilities is
the existence of control systems that can in part ensure the effective
discharge of these responsibilities. A balance has to be achieved between
controls related to financial or other matters that give the board
reasonable assurances that its responsibilities are discharged and, at
the same time, avoiding the creation of an unnecessarily bureaucratic and
costly system of control mechanisms. The confidence of the board in the
ability and integrity of management is the paramount control mechanism.
TRANSCANADA PIPELINES LIMITED 35
The board has delegated to the Audit Committee the responsibility for the
oversight of internal control procedures, to determine their
effectiveness, and to monitor compliance with the Company's policies and
codes of business ethics. The Audit Committee reports on these matters to
the board.
The Audit Committee requires management to implement and maintain
appropriate systems of internal controls and meets with the Company's
external auditors and its director of internal audit in executive
sessions, and with management, on at least a quarterly basis to oversee
the effectiveness of these systems.
8. BOARD COMMUNICATIONS POLICY
The board, or the appropriate committee thereof, reviews the content of
the Company's major communications to shareholders and the investing
public, including the quarterly and annual reports, and approves the
proxy circular, the annual information form and any prospectuses that may
be issued. The board believes that it is the function of management to
speak for the Company in its communications with the investment
community, the media, customers, suppliers, employees, governments and
the general public. It is understood that the chair or other individual
directors may from time to time be requested by management to assist with
such communications. If communications from stakeholders are made to the
chair or to other individual directors, management is informed and
consulted to determine any appropriate response.
9. OUTSIDE ADVISORS FOR INDIVIDUAL DIRECTORS
Occasionally individual directors may need the services of an advisor or
expert to assist on matters involving their responsibilities as board
members. The board has determined that any director who wishes to engage
an outside advisor at the expense of the Company may do so.
10. ASSESSING THE PERFORMANCE OF THE BOARD, COMMITTEES AND INDIVIDUAL
DIRECTORS
The Governance Committee reports to the board annually on the evaluation
of the performance of the board, each of its committees, and that of
individual directors, based on the results of the directors' annual
self-assessment questionnaire. In addition, formal interviews are
undertaken annually by the chair, based on the results of the
questionnaire and the Company's Individual Director Terms of Reference,
with each member of the board and with each member of the executive
leadership of the Company. The performance of the chair is annually
evaluated against his terms of reference by the chair of the Governance
Committee by means of formal interviews with each of the directors.
36 TRANSCANADA PIPELINES LIMITED
SCHEDULE "C"
CODE OF BUSINESS ETHICS FOR EMPLOYEES
Personnel (includes all regular full, part-time and temporary employees) of
TransCanada and its subsidiaries and affiliates (the "Company") represent the
Company and are expected to act in a manner that will enhance the Company's
reputation for honesty, integrity and reliability. Our Code of Business Ethics
(the "COBE") is a statement on TransCanada's Business Practices and on how we do
business. The COBE applies to all personnel of TransCanada. When you have a
question about ethics or compliance, please refer to this policy.
The COBE will not give you an answer for every situation. If after reviewing it
you have questions, please seek additional guidance. If you have any doubt about
the right thing to do, ask your supervisor, manager, or Human Resources, Law or
Internal Audit Departments. You can also call our anonymous Ethics Help-Line at
1-888-920-2042.
The following Fundamental Principles of appropriate business conduct have been
established for all personnel working for or representing the Company. They are
applicable in all countries in which the Company operates, unless the laws of
those countries require a higher standard.
FUNDAMENTAL PRINCIPLES
A. COMPLIANCE WITH LAWS
The Company will conduct its business in compliance with all laws,
regulations and other legal requirements applicable wherever the Company is
carrying on business. No personnel shall directly or indirectly give, offer
or agree to give or offer a loan, reward, advantage or benefit of any kind
to a foreign public official or to any person for the benefit of a foreign
public official in contravention of the CORRUPTION OF FOREIGN PUBLIC
OFFICIALS ACT.
B. CONFLICT OF INTEREST
Personnel must ensure that no conflict exists between their personal
interests and those of the Company. Personnel should also avoid placing
themselves in positions that may be perceived as conflicts. Some examples of
possible conflicts include:
- FINANCIAL INTEREST -- Personnel and their families (families including
spouse, children or spouse equivalent residing together) shall not own,
control or direct a material financial interest (greater than 5%) in a
supplier, contractor, competitor, or in any business enterprise which does
or seeks to do business with the Company.
- OUTSIDE BUSINESS ACTIVITIES -- Personnel shall not engage in any outside
business or activity that is detrimental to the Company. Unless approved
by the Company or your supervisor, personnel are expected to spend their
full time and attention performing their jobs during normal business hours
or as contracted.
- OUTSIDE DIRECTORSHIPS -- Personnel shall not serve as a director, officer,
partner, consultant or any other role in unaffiliated profit-making
organizations if that activity is detrimental to the Company.
Directorships in unaffiliated entities require the consent of the
personnel's immediate supervisor or contract manager, and of the
Governance Committee of the Board of Directors in the case of an ELT
member.
- GIFTS AND ENTERTAINMENT -- Personnel must be prudent in offering or
accepting gifts (including tickets to sporting, recreational or other
events) to or from a person or entity with which the Company does or seeks
to do business.
- CUSTOMER AND SUPPLIER RELATIONS -- All customers, suppliers and
independent contractors purchasing or furnishing goods and services must
be dealt with fairly. Decisions to hire a subcontractor or source
materials from a particular vendor must be made on the basis of objective
criteria such as quality, reliability, technical excellence, price,
delivery, service and maintenance of adequate sources of supply.
TRANSCANADA PIPELINES LIMITED 37
- GOVERNMENT AND COMMUNITY RELATIONS -- The Company's financial support to
political organizations requires the express approval of the Chief
Executive Officer of the Company. Personnel engaging in personal political
activities must do so in their own right and not on behalf of the Company.
Corporate donations to charities made on behalf of the Company shall be
within budgets approved by the appropriate business unit head.
- PERSONAL RELATIONSHIPS -- Personnel shall avoid any arrangement or
circumstance, including personal relationships that may compromise his or
her ability to act in the best interest of the Company. Personnel shall
not supervise directly or be in a position to influence the career of
someone with whom he or she is engaged in a personal relationship.
C. CONFIDENTIAL INFORMATION
In the course of employment, personnel may have access to information that
is non-public, confidential, privileged, or of value to competitors of the
Company or that may be damaging to the Company if improperly disclosed.
Personnel may also have access to the confidential information of companies
with which the Company does business.
Personnel must protect the confidentiality of information concerning the
Company and its business activities as well as that of companies having
business dealings with the Company. Personnel who leave the Company have an
ongoing obligation to keep such information confidential.
Some situations involving confidential information include:
- TECHNICAL, BUSINESS AND COMMERCIAL DATA -- Personnel must ensure against
improper disclosure of competitive business strategies and plans, special
methods of operation, technical innovations, and other information that
may be of value to competitors of the Company.
- INSIDER TRADING -- Securities laws explicitly prohibit any person in a
special relationship with the Company from trading with knowledge of
"material non-public information" or "insider information" which has not
been generally disclosed. In addition, securities laws prohibit any person
in a special relationship with the Company from informing another person
of any "material non-public" or "insider" information which has not been
generally disclosed.
Employees of TransCanada, and their immediate family members, will not
trade in their personal account in any physical commodity or financial
derivative of any physical or financial commodity related to those traded
by the Company if that employee holds a position at TransCanada that would
make them privy to detailed or inside information about the Company's
commodity trading activities.
- TRADING GUIDELINES FOR ALL PERSONNEL -- Those possessing confidential
information are expected to show integrity and use proper judgement in
timing their investments in accordance with Company policy and regulatory
rules and guidelines.
- MEDIA/PUBLIC DISCUSSION -- If responding to questions by a representative
of the news media or investment community is not part of personnel's
regular duties, the media representative must be referred to the
appropriate Company spokesperson.
D. FISCAL INTEGRITY AND RESPONSIBILITY
All personnel are responsible for protecting Company assets, and leaders are
specifically responsible for establishing and maintaining appropriate
internal controls to safeguard Company assets against loss from unauthorised
or improper use or disposition:
- REPORTING INTEGRITY -- No false, artificial or misleading entries in the
books, records and documents of the Company shall be made for any reason
and no personnel shall engage in any arrangement that results in such
prohibited acts. All periodic reports filed by TransCanada shall be in
accordance with TransCanada's Public Disclosure Policy and will include
full, fair, accurate, timely and understandable disclosure.
38 TRANSCANADA PIPELINES LIMITED
- USE OF COMPANY RESOURCES -- Company resources include Company time,
materials, supplies, equipment, information, electronic mail and computer
systems. These resources are generally only to be used for
Company-specific purposes.
- USE OF INTERNET AND EMAIL -- TransCanada's computer networks and
information resources include our electronic mail and messaging systems,
internal Intranet and the public Internet. TransCanada's computer
resources and networks are provided for company-related business purposes.
Excessive personal use is inappropriate. Use of TransCanada's computer
resources to view, retrieve or send sexually-related or pornographic
messages or material; violent or hate-related messages or material;
bigoted, racist or other offensive messages or other messages or material
related to illegal activities is strictly prohibited.
- USE OF COMPANY NAME -- Personnel must not use their employment status to
obtain personal gain from those doing or seeking to do business with the
Company. Personnel may not use the Company's name or purchasing power to
obtain personal discounts or rebates unless the discounts are made
available to all personnel.
- PATENTS AND INVENTIONS -- Inventions, discoveries, and copyright material,
made or developed by personnel in the course of, and relating to, their
employment with the Company, are the property of the Company unless a
written release is obtained or covered by contract.
- RECORDS RETENTION -- Business documents and records (voice, paper and
electronic) are to be retained in accordance with the law and the
Company's record retention policies.
In protecting the Company's resources, TransCanada reserves the right to
periodically monitor access and contents of the Company's computer systems
and networks. Personnel should not assume they have any right to privacy of
electronic data residing on the Company's computer resources.
E. HEALTH, SAFETY AND ENVIRONMENT
TransCanada is committed to providing a safe and healthy working environment
and protecting the public interest with standards and programs that meet or
exceed industry standards and applicable government codes, standards and
regulations in all jurisdictions in which it does business.
All TransCanada operations are to be conducted in a manner that protects the
health and safety of our personnel and all people in the communities where
the Company operates. All TransCanada personnel are responsible for
supporting TransCanada's commitment to environmental responsibility.
F. EMPLOYMENT PRACTICES
TransCanada is committed to a workplace environment where personnel are
treated with dignity, fairness and respect. All personnel have the right to
work in an atmosphere that provides equal employment opportunities and is
free of discriminatory practices and illegal harassment:
- DISCRIMINATION -- Neither TransCanada nor any person acting on behalf of
the Company shall refuse to employ or continue to employ, nor shall they
discriminate against any person with regard to employment, term or
condition of employment, based on race, national or ethnic origin, colour,
religion, age, sex (including pregnancy or child-birth) sexual
orientation, marital status, family status, disability and conviction for
which a pardon has been granted, all as defined by the Canadian Human
Rights Act.
- HARASSMENT -- Any form of illegal harassment or any other conduct that
interferes with an individual's work performance or creates an
intimidating, hostile, or offensive work environment will not be
tolerated.
- DRUG AND ALCOHOL POLICY -- The Company is committed to providing a safe
and healthy work environment. The use of illicit drugs, the inappropriate
use of alcohol and the misuse of medications and other substances is
prohibited.
TRANSCANADA PIPELINES LIMITED 39
COMPLIANCE / EXCEPTIONS
Personnel are expected to comply with all aspects of the COBE and to support
others in doing so. In the event that personnel violate the COBE, Company
policies and procedures or any of the laws that govern the Company's business,
TransCanada will take immediate and appropriate action up to and including
termination of employment, claims for reimbursement of losses or damages and
reference to criminal authorities.
HOW TO RAISE A CONCERN
Personnel are obligated to promptly report any problems or concerns or any
potential or actual violation of the COBE. The first action should be to raise
the problem with your supervisor. If that is not possible for some reason or if
taking it to your supervisor does not resolve the matter, it is your
responsibility to take it up the chain of management within your organization or
another department such as Human Resources, Legal or Internal Audit. Personnel
can also call the anonymous Ethics Help-Line at 1-888-920-2042. Callers do not
have to reveal their identities.
TransCanada policy strictly prohibits reprisals or retaliation against anyone
who files an ethics concern or complaint. If you feel you have been subjected to
retaliatory or disciplinary action because you have raised an ethics issue, call
the Ethics HelpLine immediately.
CERTIFICATION
It is essential that all personnel understand and adhere to the Company's Code
of Business Ethics.
New personnel of the Company will be asked to certify their review of, and
agreement to be bound by, the COBE as a consideration of employment or contract.
All personnel of the Company will be asked to certify annually their review of
and compliance with the provisions contained in the Code of Business Ethics.
40 TRANSCANADA PIPELINES LIMITED
SCHEDULE "D"
CODE OF BUSINESS ETHICS FOR DIRECTORS
Directors have a duty to manage or supervise the management of, the business and
affairs of the Company. In carrying out this duty the Company expects directors
to act honestly and in good faith with a view to the best interests of the
Company. To this end the Board of Directors has committed itself to maintaining
a high standard of Corporate Governance which incorporates as its basis
principles of good conduct and high ethical behavior.
To discharge their duties the Directors have adopted the following principles
for business conduct and ethical behavior.
COMPLIANCE WITH LAW
The Directors shall conduct all their business and affairs in full compliance
with applicable laws, rules and regulations and shall encourage and promote such
behaviors for themselves, officers and employees.
CONFLICTS OF INTEREST
Directors shall conduct their business and affairs in a manner that ensures
their private or personal interests do not interfere or appear to interfere,
with the interests of the Company including conflicts relative to personal,
financial or other gain. Should conflicts arise, or be perceived to arise,
directors shall immediately make full disclosure in an appropriate manner and
the disclosing Director shall not participate in any decision or action in which
there is a real or apparent conflict.
FAIR DEALING
The Company adheres to a policy of Fair Dealing in all its undertakings.
Directors shall endeavor to deal fairly with the Company's customers, suppliers,
competitors and employees. Taking unfair advantage through manipulation,
concealment, abuse of privilege, misrepresentation and other unfair dealing
practices is unacceptable.
CONFIDENTIALITY
Directors shall maintain the confidentiality of information entrusted to them
except in circumstances where disclosure is authorized or legally mandated.
Confidential information shall not be used for personal gain and Directors shall
adhere to the Company's policy on Trading by Employees and Insiders.
PROTECTION AND PROPER USE OF COMPANY ASSETS
Directors shall ensure that the Company's assets are protected and properly and
efficiently used for legitimate business purposes.
CORPORATE OPPORTUNITIES
Directors owe duty to advance the Company's legitimate interests whenever an
opportunity arises and are prohibited from:
(a) Taking personal advantage of opportunities discovered through the use of
corporate assets, property, information or their position;
(b) Using or deploying corporate assets, property, information or their
position for personal gain; and
(c) Competing with the Company.
INCIDENT REPORTING
Directors are encouraged to promote ethical behavior in all things they do and
to ensure a healthy ethical workplace. The Company, through the principles and
standards adhered to by Directors, encourages officers and leaders to talk with
employees about ethical behaviors and to provide guidance on their ethical
concerns
TRANSCANADA PIPELINES LIMITED 41
including advising employees on appropriate actions to be taken or behaviors to
be followed. Violations of laws, rules, regulations or this Code of Business
Conduct are to be reported to the appropriate officer or leader or to the ethics
hot line.
The Directors on behalf of the Company will not allow any retaliation by
officers or leaders in respect of reports made in good faith by any employee.
WAIVERS
Directors and executive officers whose conduct or actions has failed to meet or
whose future conduct or actions may not meet the principles and standards set
out in this Code of Business Conduct must report such failure or anticipated
failure immediately to the Board of Directors. Such report shall contain a
request for a waiver of such conduct and be filed with the Chairman of the
Governance Committee for review and recommendation by that Committee. The
Governance Committee shall examine the circumstances related to the failure or
requested waiver for anticipated failure and make an appropriate recommendation
to the Board of Directors. Any determination of the Board of Directors that
noncompliance with the Code of Business Conduct has occurred or that, under the
circumstances, a waiver be granted to a Director or executive officer shall be
reported promptly to the shareholders.
ANNUAL REVIEW
Annually, the Company expects each Director to review this Code of Business
Conduct and Ethics and to satisfy themselves that they have adhered to the
stated principles and standards or if they have failed to do so to ensure such
non-compliance has been reported to the Board of Directors.
42 TRANSCANADA PIPELINES LIMITED
SCHEDULE "E"
CODE OF BUSINESS ETHICS FOR THE PRESIDENT AND CHIEF EXECUTIVE OFFICER,
CHIEF FINANCIAL OFFICER AND CONTROLLER
The Company and its shareholders expect honest and ethical conduct in all
aspects of the Company's business from all employees and to that end require
that all employees comply with the Company's Code of Business Ethics. In
addition, with respect to the Company's principal and senior financial officers,
the Company and its shareholders expect the highest possible standards of honest
and ethical conduct and require such officers to acknowledge this heightened
expectation.
I, [NAME] CERTIFY that as [THE CHIEF EXECUTIVE OFFICER/CHIEF FINANCIAL
OFFICER/CONTROLLER] of TransCanada PipeLines Limited (the "Company") I adhere to
and advocate the establishment of standards reasonably necessary to deter
wrongdoing and to promote:
1. Honest and ethical conduct, including the ethical handling of actual or
apparent conflicts of interest between personal and professional
relationships;
2. Full, fair, accurate, timely and understandable disclosure in reports and
documents that the Company files with, or submits to, securities regulators
and in other public communications made by the Company;
3. Compliance with laws, rules and regulations of federal, provincial, state
and local governments, and other appropriate private and public regulatory
agencies; and
4. Compliance with the prompt reporting to the Chair of the Company's audit
committee all violations of this code.
I, [NAME] acknowledge my accountability for adherence to this code. I also
acknowledge that my compliance with this code is a condition of my employment
and that if I fail to comply with this code or applicable laws, rules or
regulations, I may be subject to disciplinary measures, up to and including
discharge from the Company. The Company will disclose any change or waiver of
this code in its disclosure documents and a form of this code shall be posted on
the Company's website.
------------------------------------------------
Signature
TRANSCANADA PIPELINES LIMITED 43
SCHEDULE "F"
CHARTER OF THE AUDIT COMMITTEE
PART I
ESTABLISHMENT OF COMMITTEE AND PROCEDURES
1. COMMITTEE
A Committee of the Directors to be known as the "Audit Committee" is
established. The Committee shall assist the Board of Directors (the "Board")
in overseeing, among other things, the integrity of the financial statements
of the Company, the compliance by the Company with legal and regulatory
requirements and the independence and performance of the Company's internal
and external auditors.
2. COMPOSITION OF COMMITTEE
The Committee shall consist of not less than three and not more than nine
Directors, a majority of whom are resident Canadians (as defined in the
Canada Business Corporations Act), and all of whom are unrelated and/or
independent as defined in the applicable requirements of relevant securities
legislation and the applicable rules of any stock exchange on which the
Company's securities are listed for trading. Each member of the Committee
shall be financially literate and at least one member shall have accounting
or related financial management expertise (as those terms are defined from
time to time under the requirements or guidelines for audit committee
service under securities laws and the applicable rules of any stock exchange
on which the Company's securities are listed for trading or, if it is not so
defined as that term is interpreted by the Board in its business judgment).
3. APPOINTMENT OF COMMITTEE MEMBERS
The members of the Committee shall be appointed by the Board on the
recommendation of the Governance Committee. The members of the Committee
shall be appointed as soon as practicable following each annual meeting of
Shareholders, and shall hold office until the next annual meeting, or until
their successors are earlier appointed, or until they cease to be Directors
of the Company.
4. VACANCIES
Where a vacancy occurs at any time in the membership of the Committee, it
may be filled by the Board on the recommendation of the Governance Committee
and shall be filled by the Board if the membership of the Committee is less
than three Directors or if the Committee ceases to meet the requirements for
audit committees as provided under securities laws and the rules of any
stock exchange upon which the Company's shares are listed for trading.
5. COMMITTEE CHAIR
The Board shall appoint a Chair for the Committee.
6. ABSENCE OF COMMITTEE CHAIR
If the Chair of the Committee is not present at any meeting of the
Committee, one of the other members of the Committee present at the meeting
shall be chosen by the Committee to preside at the meeting.
7. SECRETARY OF COMMITTEE
The Committee shall appoint a Secretary who need not be a Director of the
Company.
44 TRANSCANADA PIPELINES LIMITED
8. MEETINGS
The Chair, or any two members of the Committee, or the internal auditor, or
the external auditors may call a meeting of the Committee. The Committee
shall meet at least quarterly. The Committee shall meet periodically with
management, the internal auditors and the external auditors in separate
executive sessions.
9. QUORUM
A majority of the members of the Committee, present in person or by
telephone or other telecommunication device that permit all persons
participating in the meeting to speak to each other, shall constitute a
quorum.
10. NOTICE OF MEETINGS
Notice of the time and place of every meeting shall be given in writing or
facsimile communication to each member of the Committee at least 24 hours
prior to the time fixed for such meeting; provided, however, that a member
may in any manner waive a notice of a meeting. Attendance of a member at a
meeting is a waiver of notice of the meeting, except where a member attends
a meeting for the express purpose of objecting to the transaction of any
business on the grounds that the meeting is not lawfully called.
11. ATTENDANCE OF COMPANY OFFICERS AND EMPLOYEES AT MEETING
At the invitation of the Chair of the Committee, one or more officers or
employees of the Company may attend any meeting of the Committee.
12. PROCEDURE, RECORDS AND REPORTING
The Committee shall fix its own procedure at meetings, keep records of its
proceedings and report to the Board when the Committee may deem appropriate
but not later than the next meeting of the Board.
13. REVIEWS AND REPORTS
The Committee shall review its terms of reference annually or otherwise, as
it deems appropriate, and if necessary propose changes to the Governance
Committee and the Board. The Committee shall make regular reports to the
Board. The Committee shall annually review the Committee's own performance.
14. OUTSIDE EXPERTS
The Committee, and on behalf of the Committee, the Committee Chair, is
authorized when deemed necessary or desirable to retain independent counsel
and other advisors, at the Company's expense, to advise the Committee
independently on any matter.
15. RELIANCE
Absent actual knowledge to the contrary (which shall be promptly reported to
the Board), each member of the Committee shall be entitled to rely on
(i) the integrity of those persons or organizations within and outside the
Company from which it receives information, (ii) the accuracy of the
financial and other information provided to the Committee by such persons or
organizations and (iii) representations made by Management and the external
auditors, as to any information technology, internal audit and other
non-audit services provided by the external auditors to the Company and its
subsidiaries.
PART II
MANDATE OF COMMITTEE
16. APPOINTMENT OF THE COMPANY'S EXTERNAL AUDITORS
Subject to confirmation by the external auditors of their compliance with
Canadian and U.S. regulatory registration requirements, the Committee shall
recommend to the Board the appointment of the external
TRANSCANADA PIPELINES LIMITED 45
auditors, such appointment to be confirmed by the Company's shareholders at
each annual meeting. The Committee shall also recommend to the Board the
compensation to be paid to the external auditors for audit services and
shall pre-approve the retention of the external auditors for any permitted
non-audit service and the fees for such service. The Committee shall also be
directly responsible for the oversight of the work of the external auditor
(including resolution of disagreements between management and the external
auditor regarding financial reporting) for the purpose of preparing or
issuing an audit report or related work. The external auditor shall report
directly to the Committee.
The Committee shall also receive periodic reports from the external auditors
regarding the auditors' independence, discuss such reports with the
auditors, consider whether the provision of non-audit services is compatible
with maintaining the auditors' independence and the Committee shall take
appropriate action to satisfy itself of the independence of the external
auditors.
17. OVERSIGHT IN RESPECT OF FINANCIAL DISCLOSURE
The Committee to the extent it deems it necessary or appropriate shall:
(a) review, discuss with management and the external auditors and recommend
to the Board for approval, the Company's audited annual financial
statements, annual information form including management discussion and
analysis, all financial statements in prospectuses and other offering
memoranda, financial statements required by regulatory authorities, all
prospectuses and all documents which may be incorporated by reference
into a prospectus, including without limitation, the annual proxy
circular, but excluding any pricing supplements issued under a medium
term note prospectus supplement of the Company;
(b) review, discuss with management and the external auditors and recommend
to the Board for approval the release to the public of the Company's
interim reports, including the financial statements, management
discussion and analysis and press releases on quarterly financial
results;
(c) review and discuss with management and external auditors the use of
"pro forma" or "adjusted" non-GAAP information and the applicable
reconciliation;
(d) review and discuss with management and external auditors financial
information and earnings guidance provided to analysts and rating
agencies; provided, however, that such discussion may be done generally
(consisting of discussing the types of information to be disclosed and
the types of presentations to be made). The Committee need not discuss in
advance each instance in which the Company may provide earnings guidance
or presentations to rating agencies;
(e) review annual and quarterly financial statements and annual disclosure
documents of NOVA Gas Transmission Ltd. ("NGTL");
(f) review with management and the external auditors major issues regarding
accounting and auditing principles and practices, including any
significant changes in the Company's selection or application of
accounting principles, as well as major issues as to the adequacy of the
Company's internal controls and any special audit steps adopted in light
of material control deficiencies that could significantly affect the
Company's financial statements;
(g) review and discuss quarterly reports from the external auditors on:
(i) all critical accounting policies and practices to be used;
(ii) all alternative treatments of financial information within
generally accepted accounting principles that have been discussed
with management, ramifications of the use of such alternative
disclosures and treatments, and the treatment preferred by the
external auditor;
(iii) other material written communications between the external auditor
and management, such as any management letter or schedule of
unadjusted differences;
(h) review with management and the external auditors the effect of
regulatory and accounting initiatives as well as off-balance sheet
structures on the Company's financial statements;
46 TRANSCANADA PIPELINES LIMITED
(i) review with management, the external auditors and, if necessary, legal
counsel, any litigation, claim or contingency, including tax assessments,
that could have a material effect upon the financial position of the
Company, and the manner in which these matters have been disclosed in the
financial statements;
(j) review disclosures made to the Committee by the Company's CEO and CFO
during their certification process for the periodic reports filed with
securities regulators about any significant deficiencies in the design or
operation of internal controls or material weaknesses therein and any
fraud involving management or other employees who have a significant role
in the Company's internal controls;
(k) discuss with management the Company's material financial risk exposures
and the steps management has taken to monitor and control such exposures,
including the Company's risk assessment and risk management policies.
18. OVERSIGHT IN RESPECT OF LEGAL AND REGULATORY MATTERS
(a) review with the Company's General Counsel legal matters that may have a
material impact on the financial statements, the Company's compliance
policies and any material reports or inquiries received from regulators
or governmental agencies.
19. OVERSIGHT IN RESPECT OF INTERNAL AUDIT
(a) review the audit plans of the internal auditors of the Company including
the degree of coordination between such plan and that of the external
auditors and the extent to which the planned audit scope can be relied
upon to detect weaknesses in internal control, fraud or other illegal
acts;
(b) review the significant findings prepared by the internal auditing
department and recommendations issued by the Company or by any external
party relating to internal audit issues, together with management's
response thereto;
(c) review compliance with the Company's policies and avoidance of conflicts
of interest;
(d) review the adequacy of the resources of the internal auditor to ensure
the objectivity and independence of the internal audit function,
including reports from the internal audit department on its audit process
with associates and affiliates;
(e) ensure the internal auditor has access to the Chair of the Committee and
of the Board and to the Chief Executive Officer and meet separately with
the internal auditor to review with him any problems or difficulties he
may have encountered and specifically:
(i) any difficulties which were encountered in the course of the audit
work, including restrictions on the scope of activities or access to
required information, and any disagreements with management;
(ii) any changes required in the planned scope of the internal audit;
and
(iii) the internal audit department responsibilities, budget and
staffing;
and to report to the Board on such meetings;
(f) bi-annually review officers' expenses and aircraft usage reports.
20. OVERSIGHT IN RESPECT OF THE EXTERNAL AUDITORS
(a) review the annual post-audit or management letter from the external
auditors and management's response and follow-up in respect of any
identified weakness, inquire regularly of management and the external
auditors of any significant issues between them and how they have been
resolved, and intervene in the resolution if required;
(b) review the quarterly unaudited financial statements with the external
auditors and receive and review the review engagement reports of external
auditors on unaudited financial statements of the Company and NGTL;
TRANSCANADA PIPELINES LIMITED 47
(c) receive and review annually the external auditors' formal written
statement of independence delineating all relationships between itself
and the Company;
(d) meet separately with the external auditors to review with them any
problems or difficulties the external auditors may have encountered and
specifically:
(i) any difficulties which were encountered in the course of the audit
work, including any restrictions on the scope of activities or
access to required information, and any disagreements with
management; and
(ii) any changes required in the planned scope of the audit;
and to report to the Board on such meetings;
(e) review with the external auditors the adequacy and appropriateness of
the accounting policies used in preparation of the financial statements;
(f) meet with the external auditors prior to the audit to review the
planning and staffing of the audit;
(g) receive and review annually the external auditors' written report on
their own internal quality control procedures; any material issues raised
by the most recent internal quality control review, or peer review, of
the external auditors, or by any inquiry or investigation by governmental
or professional authorities, within the preceding five years, and any
steps taken to deal with such issues;
(h) review and evaluate the external auditors, including the lead partner of
the external auditor team;
(i) ensure the rotation of the lead (or coordinating) audit partner having
primary responsibility for the audit and the audit partner responsible
for reviewing the audit as required by law.
21. OVERSIGHT IN RESPECT OF AUDIT AND NON-AUDIT SERVICES
(a) pre-approve all audit services (which may entail providing comfort
letters in connection with securities underwritings) and all permitted
non-audit services, other than non-audit services where:
(i) the aggregate amount of all such non-audit services provided to the
Company constitutes not more than 5% of the total fees paid by the
Company and its subsidiaries to the external auditor during the
fiscal year in which the non-audit services are provided;
(ii) such services were not recognized by the Company at the time of the
engagement to be non-audit services; and
(iii) such services are promptly brought to the attention of the
Committee and approved prior to the completion of the audit by the
Committee or by one or more members of the Committee to whom
authority to grant such approvals has been delegated by the
Committee;
(b) approval by the Committee of a non-audit service to be performed by the
external auditor shall be disclosed as required under securities laws and
regulations;
(c) the Committee may delegate to one or more designated members of the
Committee the authority to grant pre-approvals required by this
subsection. The decisions of any member to whom authority is delegated to
pre-approve an activity shall be presented to the Committee at its first
scheduled meeting following such pre-approval;
(d) if the Committee approves an audit service within the scope of the
engagement of the external auditor, such audit service shall be deemed to
have been pre-approved for purposes of this subsection.
22. OVERSIGHT IN RESPECT OF CERTAIN POLICIES
(a) review and recommend to the Board for approval policy changes and
program initiatives deemed advisable by management or the Committee with
respect to the Company's codes of business conduct and ethics;
48 TRANSCANADA PIPELINES LIMITED
(b) obtain reports from management, the Company's senior internal auditing
executive and the external auditors and report to the Board on the status
and adequacy of the Company's efforts to ensure its businesses are
conducted and its facilities are operated in an ethical, legally
compliant and socially responsible manner, in accordance with the
Company's codes of business conduct and ethics;
(c) establish a non-traceable, confidential and anonymous system by which
callers may ask for advice or report any ethical or financial concern,
ensure that procedures for the receipt, retention and treatment of
complaints in respect of accounting, internal controls and auditing
matters are in place, and receive reports on such matters as necessary;
(d) annually review and assess the adequacy of the Company's public
disclosure policy.
23. OVERSIGHT IN RESPECT OF PENSION MATTERS
(a) consider and in accordance with regulatory requirements approve any
changes in the Company's pension plans having to do with financial
matters after consultation with the Human Resources Committee in respect
of any effect such a change may have on pension benefits;
(b) review and consider financial and investment reports relating to the
Company's pension plans;
(c) appoint and terminate the engagement of investment managers with respect
to the Company's pension plans;
(d) receive, review and report to the Board on the actuarial valuation and
funding requirements for the Company's pension plans.
24. OVERSIGHT IN RESPECT OF INTERNAL ADMINISTRATION
(a) review annually the reports of the Company's representatives on certain
audit committees of subsidiaries and affiliates of the Company and any
significant issues and auditor recommendations concerning such
subsidiaries and affiliates;
(b) review the succession plans in respect of the Chief Financial Officer,
the Vice President, Risk Management and the Director, Internal Audit;
(c) review and approve guidelines for the Company's hiring of employees or
former employees of the external auditors who were engaged on the
Company's account.
25. OVERSIGHT FUNCTION
While the Committee has the responsibilities and powers set forth in this
Charter, it is not the duty of the Committee to plan or conduct audits or to
determine that the Company's financial statements and disclosures are
complete and accurate or are in accordance with generally accepted
accounting principles and applicable rules and regulations. These are the
responsibilities of management and the external auditors. The Committee, its
Chair and any of its members who have accounting or related financial
management experience or expertise, are members of the Board, appointed to
the Committee to provide broad oversight of the financial disclosure,
financial risk and control related activities of the Company, and are
specifically not accountable nor responsible for the day to day operation of
such activities. Although designation of a member or members as an "audit
committee financial expert" is based on that individual's education and
experience, which that individual will bring to bear in carrying out his or
her duties on the Committee, designation as an "audit committee financial
expert" does not impose on such person any duties, obligations or liability
that are greater than the duties, obligations and liability imposed on such
person as a member of the Committee and Board in the absence of such
designation. Rather, the role of any audit committee financial expert, like
the role of all Committee members, is to oversee the process and not to
certify or guarantee the internal or external audit of the Company's
financial information or public disclosure.
TRANSCANADA PIPELINES LIMITED 49
SCHEDULE "G"
CHARTER OF THE GOVERNANCE COMMITTEE
PART I
ESTABLISHMENT OF COMMITTEE AND PROCEDURES
1. COMMITTEE
A Committee of the Directors to be known as the "Governance Committee" is
established.
2. COMPOSITION OF COMMITTEE
The Committee shall consist of not less than three and not more than seven
Directors, a majority of whom are resident Canadians (as defined in the
Canada Business Corporations Act) and all of whom shall be unrelated and
independent as determined by the Board.
3. APPOINTMENT OF COMMITTEE MEMBERS
Members of the Committee shall be appointed at the meeting of the Directors
immediately following the annual meeting of Shareholders, and shall hold
office until the next annual meeting, or until their successors are
appointed, or until they cease to be Directors of the Company. It is
desirable that membership on the Committee be rotated such that as many
different Directors as possible have an opportunity at some time to serve on
the Committee.
4. VACANCIES
Where a vacancy occurs at any time in the membership of the Committee, it
may be filled by the Board and shall be filled by the Board if the
membership of the Committee is less than three Directors.
5. COMMITTEE CHAIR
The Board shall appoint a Chair for the Committee.
6. ABSENCE OF COMMITTEE CHAIR
If the Chair of the Committee is not present at any meeting of the
Committee, one of the other members of the Committee present at the meeting
shall be chosen by the Committee to preside at the meeting.
7. SECRETARY OF COMMITTEE
The Committee shall appoint a Secretary who need not be a director of The
Company.
8. MEETINGS
The Chair or any two members of the Committee may call a meeting of the
Committee. The Committee shall meet at least semi-annually. Although the
Chair of the Board and the Company's President and Chief Executive Officer
may attend all meetings of the Committee, the Committee will also meet in
separate executive sessions.
9. QUORUM
A majority of the members of the Committee, present in person or by
telephone or other telecommunication device that permits all persons
participating in the meeting to speak to each other, shall constitute a
quorum.
50 TRANSCANADA PIPELINES LIMITED
10. NOTICE OF MEETINGS
Notice of the time and place of every meeting shall be given in writing or
facsimile communication to each member of the Committee at least 24 hours
prior to the time fixed for such meeting, provided, however, that a member
may in any manner waive a notice of a meeting; and attendance of a member at
a meeting is a waiver of notice of the meeting, except where a member
attends a meeting for the express purpose of objecting to the transaction of
any business on the grounds that the meeting is not lawfully called.
11. ATTENDANCE OF OFFICERS OR EMPLOYEES OF THE COMPANY AT MEETING
At the invitation of the Chair of the Committee, one or more officers or
employees of the Company may attend any meeting of the Committee.
12. PROCEDURE, RECORDS AND REPORTING
The Committee shall fix its own procedure at meetings, keep records of its
proceedings and report to the Board but not later than the next meeting of
the Board.
13. REVIEW OF TERMS OF REFERENCE
The Committee shall evaluate on an annual basis its performance and review
its Charter and shall as it deems appropriate propose any changes to the
Board for approval.
PART II
MANDATE OF COMMITTEE
14. GENERAL MANDATE
The Committee's mandate is to enhance the Company's corporate governance
through a continuing assessment of The Company's approach to corporate
governance and to make policy recommendations with respect thereto.
In addition, the Committee is mandated with identifying qualified
individuals to become board members and to recommend to the Board the
director nominees for appointment at the next annual meeting.
15. SPECIFIC MANDATES
I. The Committee shall:
(a) review from time to time the size, composition and profile of the
Board of Directors including a review of the criteria for selecting
new directors;
(b) review and report to the Board annually on its assessment of the
performance of the Board and the Committees of the Board, and the
basis of that evaluation;
(c) review annually the performance and contribution of individual Board
members, including an evaluation of the competencies and skills the
Board as a whole should possess;
(d) identify individuals qualified to become members of the Board and to
recommend to the Board for selection the director nominees for
election at the annual meeting of shareholders, or to be appointed to
fill any vacancies;
(e) be authorized when deemed necessary or desirable to engage and
compensate any outside advisor as it determines necessary to permit
it to carry out its duties;
(f) review from time to time the retirement age of the Directors;
(g) review and recommend to the Board of Directors candidates for the
office of Chairman of the Board;
TRANSCANADA PIPELINES LIMITED 51
(h) conduct an annual review of Directors' compensation for Board and
Committee service taking into account such criteria as time
commitment, compensation provided by comparative companies,
responsibilities, and recommend any change for Board approval; and
(i) make recommendations relative to the composition of the various
Committees of the Board.
II. The Committee shall develop the policies and procedures of the Board of
Directors regarding corporate governance issues, including:
(a) on an annual basis, recommend and bring forward to the Board a
general list of corporate governance issues for review, discussion or
action by the Board or a Committee thereof;
(b) review the Company's structures and procedures to ensure that the
Board of Directors is able to and in fact is, functioning
independently of management;
(c) assess the effectiveness of the Board as a whole and recommend steps
which may be taken to improve effectiveness;
(d) assess the availability, relevance and timeliness of information
required by the Board;
(e) monitor the quality of the relationship between management and the
Board and recommend improvements as deemed necessary or desirable;
(f) ensure that any issues of corporate governance identified by any
directors are raised to management;
(g) review any surveys completed by directors dealing with the
effectiveness of the operation of the Board; and
(h) undertake such other initiatives as are needed to help deliver
preeminent corporate governance.
52 TRANSCANADA PIPELINES LIMITED
SCHEDULE "H"
CHARTER OF THE HEALTH, SAFETY AND ENVIRONMENT COMMITTEE
PART I
ESTABLISHMENT OF COMMITTEE AND PROCEDURES
1. COMMITTEE
A Committee of the Directors to be known as the "Health, Safety and
Environment Committee" is hereby established.
2. COMPOSITION OF COMMITTEE
The Committee shall consist of not less than five and not more than eight
Directors, a majority of whom are resident Canadians (as defined in the
Canada Business Corporations Act), none of whom is either an officer or
employee of the Company or any of its subsidiaries and a majority of whom
are persons not affiliated with the Company.
3. APPOINTMENT OF COMMITTEE MEMBERS
Members of the Committee shall be appointed at the meeting of the Directors
immediately following the annual meeting of Shareholders, and shall hold
office until the next annual meeting, or until their successors are
appointed, or until they cease to be Directors of the Company. It is
desirable that membership on the Committee be rotated such that as many
different Directors as possible have an opportunity at some time to serve on
the Committee.
4. VACANCIES
Where a vacancy occurs at any time in the membership of the Committee, it
may be filled by the Board and shall be filled by the Board if the
membership of the Committee is less than five Directors.
5. COMMITTEE CHAIR
The Board shall appoint a Chair for the Committee.
6. ABSENCE OF COMMITTEE CHAIR
If the Chair of the Committee is not present at any meeting of the
Committee, one of the other members of the Committee present at the meeting
shall be chosen by the Committee to preside at the meeting.
7. SECRETARY OF COMMITTEE
The Committee shall appoint a Secretary who need not be a director of the
Company.
8. MEETINGS
The Chair or any two members of the Committee or the external auditors may
call a meeting of the Committee. The Committee shall meet at least three
times per year.
9. QUORUM
Three members of the Committee, present in person or by telephone or other
telecommunication device that permit all persons participating in the
meeting to speak to each other, shall constitute a quorum.
10. NOTICE OF MEETINGS
Notice of the time and place of every meeting shall be given in writing or
facsimile communication to each member of the Committee at least 24 hours
prior to the time fixed for such meeting, provided, however,
TRANSCANADA PIPELINES LIMITED 53
that a member may in any manner waive a notice of a meeting; and attendance
of a member at a meeting is a waiver of notice of the meeting, except where
a member attends a meeting for the express purpose of objecting to the
transaction of any business on the grounds that the meeting is not lawfully
called.
11. ATTENDANCE OF OFFICERS OF THE COMPANY AT MEETING
At the invitation of the Chair of the Committee, one or more officers of the
Company may attend any meeting of the Committee.
12. PROCEDURE, RECORDS AND REPORTING
The Committee shall fix its own procedure at meetings, keep records of its
proceedings and report to the Board when the Committee may deem appropriate
(but not later than the next meeting of the Board).
13. REVIEW OF TERMS OF REFERENCE
The Committee shall review its terms of reference annually or otherwise as
it deems appropriate and propose recommended changes to the Governance
Committee and to the Board.
PART II
MANDATE OF COMMITTEE
14. SPECIFIC MANDATES
I. The Committee shall:
(a) monitor on a regular basis the existing health, safety and
environmental practices and procedures of the Company and its
controlled subsidiaries for compliance with applicable legislation,
conformity with industry standards and prevention or mitigation of
losses;
(b) consider whether the Company's policies relating to health, safety
and environmental matters are being effectively implemented;
(c) review and consider reports and recommendations issued by the Company
or by an external party relating to health, safety or environmental
issues, together with management's response thereto;
(d) advise and make recommendations to the Board of Directors as
appropriate on matters relating to health, safety and the
environment;
(e) review and report, as appropriate, to the Board of Directors on the
Company's policies and procedures relating to health, safety and the
environment and, if appropriate, make recommendations to the Board of
Directors;
(f) ensure the internal auditor has access to the Chairmen of the
Committee and the Board and to the Chief Executive Officer; and
(g) meet separately with the Vice-President, Health, Safety and
Environment and report to the Board on such meetings.
54 TRANSCANADA PIPELINES LIMITED
SCHEDULE "I"
CHARTER OF THE HUMAN RESOURCES COMMITTEE
PART I
ESTABLISHMENT OF COMMITTEE AND PROCEDURES
1. COMMITTEE
A Committee of the Directors to be known as the "Human Resources Committee"
is hereby established.
2. COMPOSITION OF COMMITTEE
The Committee shall consist of not less than four and not more than seven
Directors, at least twenty-five percent of whom must be resident Canadians
and all of whom must be outside, non-management and unrelated directors.
3. APPOINTMENT OF COMMITTEE MEMBERS
Members of the Committee shall be appointed at the meeting of the Directors
immediately following the annual meeting of Shareholders, and shall hold
office until the next annual meeting, or until their successors are
appointed, or until they cease to be Directors of the Company unless
otherwise removed by a majority vote of the Board of Directors (Board).
4. VACANCIES
Where a vacancy occurs at any time in the membership of the Committee, it
may be filled by the Board and shall be filled by the Board if the
membership of the Committee is less than four Directors.
5. COMMITTEE CHAIR
The Board shall appoint a Chair for the Committee.
6. ABSENCE OF COMMITTEE CHAIR
If the Chair of the Committee is not present at any meeting of the
Committee, one of the other members of the Committee present at the meeting
shall be chosen by the Committee to preside at the meeting.
7. SECRETARY OF COMMITTEE
The Committee shall appoint a Secretary who need not be a director of the
Company.
8. MEETINGS
The Chair or any two members of the Committee may call a meeting of the
Committee. The Committee shall meet at least semi-annually.
9. QUORUM
A majority of the Committee, present in person or by telephone or other
telecommunication device that permit all persons participating in the
meeting to speak to each other, shall constitute a quorum.
10. NOTICE OF MEETINGS
Notice of the time and place of every meeting shall be given in writing or
facsimile communication to each member of the Committee at least 24 hours
prior to the time fixed for such meeting, provided, however, that a member
may in any manner waive a notice of a meeting; and attendance of a member at
a meeting is
TRANSCANADA PIPELINES LIMITED 55
a waiver of notice of the meeting, except where a member attends a meeting
for the express purpose of objecting to the transaction of any business on
the grounds that the meeting is not lawfully called.
11. ATTENDANCE OF OFFICERS OF THE COMPANY AT MEETING
At the invitation of the Chair of the Committee, one or more officers or
employees of the Company may attend any meeting of the Committee.
12. PROCEDURE, RECORDS AND REPORTING
The Committee shall fix its own procedure at meetings, keep records of its
proceedings and report to the Board when the Committee may deem appropriate,
but in any event not later than the next meeting of the Board.
13. REVIEW OF TERMS OF REFERENCE AND EVALUATION OF COMMITTEE
The Committee shall conduct an annual review of its performance and shall in
line with this review, review its terms of reference and recommend, if
required, any changes for implementation to the Governance Committee and to
the Board.
14. OUTSIDE EXPERTS
The Committee Chair, on behalf of the Committee, is authorized when deemed
necessary or desirable to retain outside experts, at the Company's expense
to advise the Committee independently on any matter.
PART II
SPECIFIC MANDATES OF COMMITTEE
15. The Committee shall:
(a) review with the President and Chief Executive Officer existing
management resources and plans, including recruitment and training
programs, for ensuring that qualified personnel will be available for
succession to executive officer positions in the Company and key officer
positions in its major subsidiaries, and report on this matter to the
Board at least once each year.
(b) review and recommend to the Board goals and objectives relevant to the
President and Chief Executive Officer's compensation and will conduct an
annual review and assessment of the performance against these objectives
of the President and Chief Executive Officer, and review annually the
performance of the senior executive officers of the Company and key
officers in its major subsidiaries.
(c) consider, with the President and Chief Executive Officer, proposed
changes in organization or personnel affecting the officers' group and
recommend for approval any change requiring Board action.
(d) approve and review with the President and Chief Executive Officer the
Company's overall compensation philosophy and plans in relation to the
Company's business strategy.
(e) consider and approve the salary and other remuneration, including
termination packages, to be awarded to each senior executive officer of
the Company and key officers of its major subsidiaries and report to the
Board on the remuneration package for the Chairman, the President and
Chief Executive Officer, and the executive officers.
(f) consider and approve changes in the Company's compensation and benefit
plans involving an annual change in cost to the Company in excess of
$3 million.
(g) consider and approve any changes in the Company's pension plans having
to do with benefits after consultation with the Audit and Risk Management
Committee in respect of any effect such a change may have on pension
financial matters; appoint members to the Company's Pension Committee,
and report thereon to the Board.
56 TRANSCANADA PIPELINES LIMITED
(h) administer the Stock Option Plan and the Performance Unit Plan (PUP)
(collectively referred to as the "Plans") including the following:
(i) consider and approve the designation of employees who are to
participate in the Plans and consider and approve the granting of
options and Units related thereto under the Plans to the
participating employees;
(ii) consider and approve the price at which options may be granted
under the Stock Option Plan to the participating employees;
(iii) consider and recommend to the Board any requirement for shares to
be set aside under the Stock Option Plan from the authorized and
unissued shares of the Company;
(iv) subject to the provisions of the Plans, consider and approve any
amendments to the Plans as may be deemed necessary or advisable for
the granting of options related thereto under the Stock Option Plan
or the issue of units under PUP, and for the proper administration
and operation of the Plans;
(v) consider and recommend to the Board any amendments to the Plans or
discontinuance or substitution thereof; and
(vi) consider and approve any amendments to any agreements under the
Plans for any participating employees.
(i) administer the Restricted Share Unit Plan (RSU) and the Executive Share
Unit Plan (ESU) (collectively referred to as the "Unit Plans") including,
as legally necessary, the following:
(i) determine the performance hurdles to be achieved under the Unit
Plans and where applicable to amend such performance hurdles;
(ii) consider and approve the designation of employees who are to
participate in each of the Unit Plans and consider and approve the
granting of Units related thereto under the Unit Plans to the
respective participating employees;
(iii) consider and approve the value of the shares with respect to which
units may be granted under the Unit Plans to the respective
participating employees;
(iv) to take whatever steps are necessary to ensure the proper
administration and operation of the Unit Plans including but not
limited to the application of discretion where required;
(v) review performance against the performance hurdles for the Unit
Plans, and determine and provide direction for pay out of units
granted under the Unit Plans;
(vi) subject to the provisions of the Unit Plans, consider and approve
any significant amendments to the Unit Plans as may be deemed
necessary or advisable for the granting of units related thereto
under the Unit Plans, and for the proper administration and
operation of the Unit Plans;
(vii) consider and recommend to the Board any significant amendments to
the Unit Plans or discontinuance or substitution thereof; and
(viii) consider and approve any significant amendments to any agreements
under the Unit Plans for any participating employees.
(j) review and approve the annual report on executive compensation for
inclusion in the Company's public disclosure documents; and
(k) discharge any other responsibilities allocated to the Committee by the
Board.
TRANSCANADA PIPELINES LIMITED 57
THE MANAGEMENT'S DISCUSSION AND ANALYSIS DATED FEBRUARY 24, 2004 SHOULD BE READ
IN CONJUNCTION WITH THE AUDITED CONSOLIDATED FINANCIAL STATEMENTS OF TRANSCANADA
PIPELINES LIMITED (TCPL OR THE COMPANY) AND THE NOTES THERETO FOR THE YEAR ENDED
DECEMBER 31, 2003.
CONSOLIDATED FINANCIAL REVIEW
HIGHLIGHTS
EARNINGS INCREASE TCPL's net income applicable to common shares from continuing
operations (net earnings) increased $54 million or seven per cent to $801
million in 2003 compared to $747 million in 2002.
BALANCE SHEET STRENGTHENED In 2003, TCPL's balance sheet continued to strengthen
as shareholders' equity increased by $295 million.
GROWTH IN CORE BUSINESSES In 2003, TCPL invested more than $1.2 billion,
including the assumption of debt, in the Gas Transmission and Power businesses.
CONSOLIDATED RESULTS-AT-A-GLANCE
YEAR ENDED DECEMBER 31 (millions of dollars except per share amounts)
2003 2002 2001
----------------------------------------
NET INCOME/(LOSS) APPLICABLE TO COMMON SHARES
Continuing operations 801 747 686
Discontinued operations 50 - (67)
----------------------------------------
851 747 619
----------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------
Net income applicable to common shares for the year ended December 31, 2003 of
$851 million included net income from discontinued operations of $50 million,
which reflected the income recognition of $50 million of the initially deferred
gain of approximately $100 million after tax relating to the 2001 disposition of
the company's Gas Marketing business. This compares to net income applicable to
common shares in 2002 of $747 million, and net income applicable to common
shares in 2001 of $619 million, which included a net loss from discontinued
operations of $67 million.
SEGMENT RESULTS-AT-A-GLANCE
YEAR ENDED DECEMBER 31 (millions of dollars)
2003 2002 2001
----------------------------------------
Gas Transmission 622 653 585
Power 220 146 168
Corporate (41) (52) (67)
----------------------------------------
Continuing operations 801 747 686
Discontinued operations 50 - (67)
----------------------------------------
NET INCOME APPLICABLE TO COMMON SHARES 851 747 619
----------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------
TCPL's net earnings for the year ended December 31, 2003 were $801 million
compared to $747 million in 2002 and $686 million in 2001. The increase of $54
million in 2003 compared to 2002 was due to higher net earnings from the Power
business and reduced net expenses in the Corporate segment, partially offset by
lower net earnings from the Gas Transmission business.
The increase in 2002 net earnings compared to 2001 was due to higher earnings
from the Gas Transmission business and reduced expenses in the Corporate
segment, partially offset by lower earnings from the Power segment. The Power
segment earnings in 2001 reflected the company's ability to capture significant
market opportunities created by high market prices and power price volatility.
M-1
Net earnings from the Power business for the year ended December 31, 2003
included $73 million after tax from TCPL's investment in Bruce Power L.P. (Bruce
Power) which was acquired in February 2003 and a $19 million positive after-tax
earnings impact of a June 2003 settlement with a former counterparty which
defaulted in 2001 under power forward contracts. These increases were partially
offset by reduced operating and other income from the Power segment's Eastern
Operations, combined with higher general, administrative and support costs.
The decrease in net expenses of $11 million in the Corporate segment in 2003 was
primarily due to the positive impacts of a weaker U.S. dollar in 2003 compared
to 2002.
The reduction in net earnings of $31 million in the Gas Transmission business
for the year ended December 31, 2003 compared to 2002 was primarily due to the
decline in the Alberta System's 2003 net earnings, reflecting the one-year fixed
revenue requirement settlement reached between TCPL and its customers in
February 2003. Also, in June 2002, TCPL received the National Energy Board (NEB)
decision on its Fair Return application (Fair Return decision) to determine the
cost of capital to be included in the calculation of 2001 and 2002 tolls on the
Canadian Mainline. The results for the year ended December 31, 2002 included
after-tax income of $16 million, which represents the impact of the Fair Return
decision for 2001. The 2003 results for the Gas Transmission segment included
TCPL's $11 million share of a future income tax benefit adjustment recognized by
TransGas de Occidente S.A. (TransGas), while the 2002 results included TCPL's $7
million share of a favourable ruling for Great Lakes Gas Transmission Limited
Partnership (Great Lakes) related to Minnesota use tax paid in prior years.
Pursuant to a plan of arrangement, effective May 15, 2003, common shares of TCPL
were exchanged on a one-to-one basis for common shares of TransCanada
Corporation (TransCanada). As a result, TCPL became a wholly-owned subsidiary of
TransCanada. The Consolidated Financial Statements for the year ended December
31, 2003 include the accounts of TCPL, the consolidated accounts of all
subsidiaries, and TCPL's proportionate share of the accounts of the company's
joint venture investments.
TCPL OVERVIEW
TCPL is a leading North American energy company focused on natural gas
transmission and power generation. At December 31, 2003, the Gas Transmission
business accounted for approximately 86 per cent and Power approximately 14 per
cent of total operating assets of $19.7 billion. In 2003, the Gas Transmission
and Power businesses delivered net earnings of $622 million and $220 million,
respectively.
The Gas Transmission and Power businesses have similar characteristics and
business drivers. Infrastructure such as natural gas pipelines and power
generation are both driven by similar supply and demand fundamentals and these
markets are highly interdependent. Both businesses are capital intensive, employ
many similar technologies and operating practices, and require financial
strength and stability to support the capital required.
GAS TRANSMISSION The Gas Transmission segment includes the operation of four
wholly-owned regulated natural gas pipelines: the Canadian Mainline, the Alberta
System, the Foothills System and the BC System. TCPL's investments in Other Gas
Transmission principally include the partial ownership of one Canadian pipeline,
five United States pipelines and a 33.4 per cent interest in TC PipeLines, LP, a
publicly held U.S. limited partnership of which TCPL is the general partner. In
2003, the Gas Transmission business transported 66 per cent of the natural gas
produced in the Western Canada Sedimentary Basin (WCSB), 65 per cent of which
was exported to the U.S.
POWER TCPL's Power segment is primarily focused on power generation and includes
the construction, ownership, operation and management of electrical power
generation plants, with a total of 4,667 megawatts (MW) of generating capacity.
To generate electricity, the company uses various fuel sources such as natural
gas, waste heat, wood waste, coal, nuclear and hydro. TCPL also markets
electricity in order to optimize the asset value of the company's power
generation portfolio. Power's portfolio includes eight wholly-owned plants in
operation, a 31.6 per cent equity interest in the Bruce Power nuclear facility
and the power production from two power facilities in Alberta through power
M-2
purchase arrangements (PPAs). In addition, there is one plant in the permitting
phase and another under construction. TCPL also holds a 35.6 per cent interest
in, and is the general partner of, TransCanada Power, L.P. (Power LP), a
publicly traded limited partnership that owns seven power plants.
TCPL'S STRATEGY
TCPL's goal is to be the most profitable, competitive and reliable provider of
natural gas transportation and power services in North America.
TCPL has five key strategies for achieving its goal:
o Sustain, grow and optimize the natural gas transmission business by
connecting new WCSB supply, Northern gas and liquefied natural gas
(LNG) to growing markets.
o Continue to work with regulators and customers to evolve the regulated
business model to allow TCPL to earn competitive returns and compete
in a North American market.
o Grow and optimize the power business.
o Continue to pursue an operationally excellent business model to ensure
better, faster and cost effective delivery of natural gas and
generation of power to customers.
o Maintain and effectively utilize the company's strong financial
position to capitalize on growth opportunities when they arise.
GAS TRANSMISSION
OPPORTUNITIES North American natural gas demand is expected to grow to 85
billion cubic feet per day (Bcf/d) by 2015 from 70 Bcf/d in 2002, an increase of
21 per cent over this time period. While higher natural gas prices may result in
some demand destruction or fuel switching, TCPL expects that in the long term,
demand for natural gas will increase substantially. Flat to slightly increasing
production is expected in existing natural gas production basins as a result of
higher natural gas prices leading to increased drilling, offset by higher
decline rates and lower initial well production rates. Overall, supply from
traditional North American basins is expected to grow by 1 Bcf/d by 2015. These
expectations indicate that North America will require substantial incremental
volumes of natural gas from non-traditional sources to meet the increased
demand. This incremental natural gas supply is expected to come from frontier
regions such as Alaska and Canada's Mackenzie Delta, as well as from new LNG
opportunities. TCPL will continue to pursue growth of the current infrastructure
and develop new infrastructure linking new supply to growing markets.
Today, TCPL owns the largest pipeline network that links the WCSB with
significant growing markets in North America. In 2003, the Alberta System
gathered approximately 11 Bcf/d, representing 66 per cent of the natural gas
produced in the WCSB and 16 per cent of North American natural gas production.
Within Alberta, the company delivered approximately 1.6 Bcf/d. The Alberta
System connects to the Canadian Mainline, the BC System, the Foothills System
and other pipelines which collectively deliver natural gas to eastern Canada and
export natural gas to the U.S. Pacific Northwest, Midwest and Northeast.
STRATEGY One of TCPL's strategies is to sustain, grow and optimize its natural
gas transmission business by connecting new WCSB supply, Northern gas and LNG to
growing markets. The natural gas demand growth expected over the next several
years suggests that there will be ample opportunity to pursue this strategy. In
the short to medium term, growth is expected to come from debottlenecking
existing systems, increased ownership of partially-owned pipelines, acquisitions
of other pipeline systems and connecting new WCSB supply to market. In the long
term, TCPL is laying the groundwork for developing, building and operating new
infrastructure to bring Northern gas and LNG to growing markets.
TCPL's pursuit of a role in bringing Northern gas to market is also driven by
the fact that there is excess capacity on the company's main pipelines, the
Alberta System and the Canadian Mainline. If pipelines are built to deliver
natural gas from Prudhoe Bay and the Mackenzie Delta, and they connect to
existing pipeline systems, the economic viability of TCPL's pipelines will be
enhanced thereby benefiting TCPL's customers and shareholders.
M-3
2003 BUSINESS DEVELOPMENTS In 2003, TCPL continued to deliver on its strategy of
sustaining, growing and optimizing its Gas Transmission business and took
several steps forward in working towards the goal of bringing Northern gas and
LNG to market.
In August 2003, the company acquired the remaining interests in Foothills Pipe
Lines Ltd. and its subsidiaries (Foothills) previously not held by TCPL. The
Foothills System, which extends more than 1,000 kilometres and carries over 30
per cent of Canadian natural gas exports to the U.S., complements TCPL's current
western Canadian facilities. The company also increased its ownership interest
in Portland Natural Gas Transmission System Partnership (Portland) in the
Northeast U.S. to 61.7 per cent from 33.3 per cent.
The Foothills acquisition has strengthened TCPL's position in the potential
Alaska Highway Pipeline Project. TCPL, through Foothills, holds certificates for
both the Alaskan and Canadian segments of the Alaska Highway Pipeline Project
and also holds significant right-of-way assets for the project in both Canada
and Alaska.
In June 2003, TCPL, the Mackenzie Delta gas producers and the Aboriginal
Pipeline Group (APG) reached a funding and participation agreement with respect
to the Mackenzie Gas Pipeline Project. TCPL has agreed to finance the APG for
its one-third share of project definition costs in exchange for several options,
including an ownership interest in the project, certain rights of first refusal
and the right to have the Mackenzie Delta gas flow into the Alberta System.
In September 2003, on the LNG front, TCPL and ConocoPhillips Company
(ConocoPhillips) announced the Fairwinds partnership to jointly evaluate a
liquefied natural gas regasification facility in Harpswell, Maine. If all
approvals are received, construction of this facility could begin in 2006 and be
in operation in 2009. TCPL also continues to pursue other LNG projects.
CHALLENGES While several positive developments occurred in 2003, there are
challenges to the company's ability to sustain, grow and optimize the Gas
Transmission business. The nature of the Gas Transmission segment's business
risks has changed over the past several years. Two major developments in the
pipeline sector in Canada have driven these risks: an increase in competition
and essentially flat supply of natural gas from the WCSB. TCPL faces competition
at both the supply end and the market end of the company's pipeline systems. On
the supply end, other pipelines are accessing an increasingly mature basin. On
the market end, there are other pipelines able to deliver natural gas to markets
that were historically served by TCPL.
TCPL's ability to grow through the acquisition of other pipeline systems is
dependent on the availability of quality pipeline assets for sale, the strength
of competitor bids and the company's ability to successfully execute its
acquisition strategy.
In the long term, TCPL's ability to play a significant role in delivering
Northern gas to market is dependent on gas producers' willingness and ability to
commit their resources to these projects. There are several factors impacting
the decision to proceed with these projects, including natural gas prices,
capital cost of the pipeline, regulatory approvals, and construction,
operational and financial risk.
With increased competition and essentially flat WCSB supply, TCPL expects there
will be little organic growth in its Canadian regulated pipelines, prior to
connecting Northern gas supplies. Since a key determinant of earnings is the
average investment base, the company also expects that in the absence of
increases in return on equity and deemed equity thickness, earnings from these
assets will decline. However, despite the potential for declining earnings, cash
flow generated from these mature assets is expected to remain strong.
CANADIAN REGULATORY DEVELOPMENTS While natural gas supply and demand
fundamentals support TCPL's strategy for growing and optimizing the Gas
Transmission business, its Canadian regulated pipelines continue to face the
challenges of competition, a maturing WCSB and overall low returns. These
challenges drive TCPL's perseverance to earn higher returns and compete in the
North American market.
M-4
TCPL's Canadian regulated assets are approximately $14 billion representing 68
per cent of the company's total asset base at December 31, 2003. In the short to
medium term, the company's earnings from its wholly-owned regulated pipelines is
dependent not on the amount of natural gas that flows through the pipelines but
rather on the amount of capital that is invested in the pipelines, the allowed
rate of return and the deemed equity thickness. In the long term however, as
WCSB production declines and transportation tolls are impacted, shippers are
likely to be less willing to contract for natural gas transmission services.
The NEB regulates the Canadian Mainline, the Foothills System, the BC System as
well as the Trans Quebec & Maritimes System (TQM), in which the company holds a
50 per cent ownership interest. Earnings from these pipelines are based on the
average investment base and a rate of return on a deemed common equity ratio
that is determined by the regulator. In 2003, the Canadian Mainline average
investment base was $8.6 billion and earned the NEB formula of 9.79 per cent on
a deemed common equity ratio of 33 per cent. The NEB formula that determines the
rate of return is directly linked to the long-term Canada Bond yield. This leads
to a direct correlation between earnings on the Canadian Mainline and the level
of long-term interest rates in Canada and has resulted in the rate of return
declining substantially over the past decade.
The Alberta System is regulated by the Alberta Energy and Utilities Board (EUB).
In 2003, revenue for the Alberta System was based on a negotiated settlement
with customers on the pipeline. Negotiations with shippers on the Alberta System
were significantly influenced by the 2002 NEB decision on the Canadian
Mainline's return in 2001 and 2002. As a consequence, the earnings in the
Alberta System's revenue requirement were originally anticipated to be $40
million lower than in 2002. However, incentive earnings of approximately $16
million partially offset this decrease, resulting in a $24 million decline in
earnings in 2003 from 2002 for the Alberta System. In 2003, the EUB also
approved the Alberta System 2003 Tariff Application which introduced two new
services and certain modifications to rate design.
Over the past three years, TCPL has pursued in various regulatory proceedings
both the evolution of its regulated business model and fair returns. In 2001,
the company filed the Canadian Mainline 2001 and 2002 Fair Return Application
with the NEB. In the application, TCPL requested the NEB to adopt an after-tax
weighted average cost of capital approach to determining returns (instead of the
NEB formula tied to interest rates) and requested a higher return. In its June
2002 decision on this application, the NEB retained its formula for the return
calculation and increased the Canadian Mainline's deemed common equity ratio to
33 per cent from 30 per cent. The NEB denied TCPL's subsequent application to
review and vary the NEB's decision. TCPL then petitioned the Federal Court of
Appeal which granted leave to appeal. The appeal was heard in February 2004 and
TCPL awaits the judgment.
In July 2003, the NEB issued its decision on TCPL's 2003 Canadian Mainline Tolls
and Tariff Application. The NEB approved key components of the application
including an increase in the composite depreciation rate, introduction of a new
tolling zone, continuation of fuel incentives and an increase in the bid floor
price for interruptible service (IT). This decision addressed key issues such as
competition in the end markets of the Canadian Mainline, disincentives for
shippers to contract for firm service and the long-term supply risks faced by
the WCSB. Tolls for 2003 remain interim pending the outcome of the appeal to the
Federal Court of Appeal.
In 2003 and early 2004, the EUB held a Generic Cost of Capital (GCOC) proceeding
in Alberta. At the conclusion of this proceeding, the EUB will determine the
rate of return on equity for 2004 and the capital structure for each utility
under its jurisdiction, including the Alberta System. It also expects to adopt a
standardized approach to determining rate of return commencing in 2005.
TCPL filed Phase I of its Alberta System 2004 General Rate Application (GRA)
with the EUB in September 2003 and Phase II in November 2003. This is the first
GRA filed with the regulator since 1995. Between 1996 and 2003, the tolls and
services on the Alberta System were based on negotiated settlements with the
pipeline customers, which were approved by the EUB.
M-5
POWER
OPPORTUNITIES Power demand is expected to grow at the rate of two per cent per
year in North America. TCPL's Power segment has significant opportunities for
growth which will take place through quality acquisitions, niche development
opportunities and through the optimization of the company's power portfolio by
focusing on low-risk opportunities in known markets. Given current restrictions
on North American power transmission grids, there is also a need to build
efficient power plants that are in close proximity to demand areas.
STRATEGY Power will continue to focus on developing and acquiring low-cost, base
load generation or plants with strong contractual underpinnings in markets where
the company has or can acquire significant knowledge and experience. TCPL will
also grow the Power business by building plants that take advantage of efficient
cogeneration technology and serve niche markets.
TCPL's power plants are located in several different regulatory jurisdictions
and each one has unique rules and regulations. Power markets are regionalized
and in-depth knowledge of each market is important to the success of the
operation of these assets. TCPL has grown the Power business significantly in
Alberta, eastern Canada and the U.S. Northeast and has developed extensive
experience in these markets. TCPL will continue to capitalize on its market
knowledge and deregulation experience to optimize the asset value of its power
portfolio through marketing activities in these geographic areas. TCPL will
pursue operational excellence to be the most profitable and reliable provider of
power services in the markets the company serves.
2003 DEVELOPMENTS In 2003, TCPL acquired a 31.6 per cent interest in Bruce Power
and announced two new cogeneration plants in Canada. The Bruce Power investment
provides TCPL with low-cost, base load power generation in Ontario, one of the
largest markets in North America. Output from the new Quebec and New Brunswick
cogeneration facilities will be sold under long-term contracts to creditworthy
counterparties. These plants are examples of TCPL's ability to develop power
generation in new markets and capitalize on the company's expertise in
cogeneration technology.
CHALLENGES TCPL's main challenges in growing its Power business include the
availability of quality acquisition opportunities, and the company's ability to
capture those opportunities and find niche markets to develop new power plants.
Power generation is primarily a manufacturing business. TCPL uses various fuel
sources such as natural gas, waste heat, wood waste, coal, nuclear and hydro to
generate electricity. A key success factor in any manufacturing business is the
ability to operate at the lowest cost possible. There are several drivers of
costs in the power generation business such as construction, start-up, fuel and
operating costs which TCPL manages through its operational excellence model.
TCPL's ability to optimize its power assets is driven by factors such as
contractual profile, plant availability, reliability, fuel mix management and
portfolio/dispatch optimization.
The power markets in North America began deregulating in the mid-1990s and the
deregulation process continues to evolve in some markets. Evolving markets can
lead to short- to medium-term uncertainty around market structure, including how
power and fuel contracts are structured. This ultimately impacts earnings
volatility. TCPL has been successful in operating in both deregulated and
regulated markets.
TCPL - OUTLOOK
In 2004, TCPL will continue to execute its strategy to grow and optimize its Gas
Transmission and Power businesses by redeploying its strong discretionary cash
flow.
In the Gas Transmission business, the company will pursue growth through the
expansion of current systems to bring new supplies to market, acquisitions of
existing pipelines, increased ownership in partially-owned pipelines and
continued efforts to bring new sources of natural gas (including Northern gas
M-6
and LNG) to growing markets. In 2004, the outcome of regulatory proceedings
could have a significant impact on the earnings of the Alberta System and
Canadian Mainline.
In the Power business, TCPL will focus on markets in which the company currently
operates and has extensive market knowledge and deregulation experience. The
company will pursue growth of a balanced portfolio of gas-fired and non
gas-fired power plants by building, acquiring and investing in competitive
facilities. TCPL will focus on low-cost, base-load generation or assets with
strong contractual underpinnings and strive to be one of the lowest-cost
providers of power services in North America. Power projects undertaken will
benefit from and support TCPL's strong balance sheet. In 2004, plant
availability and fluctuating power prices, especially for Bruce Power, could
have a significant impact on the earnings of the Power segment.
Financial flexibility is one of the most important requirements for growing the
company. Net earnings and cash flow, combined with a strong balance sheet,
continue to provide the financial flexibility for TCPL to make disciplined
investments in its core businesses of Gas Transmission and Power.
ACQUISITION OF GAS TRANSMISSION NORTHWEST
On February 24, 2004, TransCanada announced an agreement to acquire Gas
Transmission Northwest Corporation (GTN) from National Energy & Gas
Transmission, Inc. (NEGT) for approximately US$1.7 billion, including US$500
million of assumed debt and subject to typical closing adjustments.
GTN is a natural gas pipeline company that owns and operates two pipeline
systems - the Gas Transmission Northwest pipeline system, formerly known as
Pacific Gas Transmission, and the North Baja Pipeline system.
The Gas Transmission Northwest pipeline system consists of more than 2,174
kilometres of pipeline extending from a point near Kingsgate, British Columbia,
on the British Columbia-Idaho border, to a point near Malin, Oregon on the
Oregon-California border. The natural gas transported on this pipeline
originates primarily from supplies in Canada for customers located in the
Pacific Northwest, Nevada and California.
The North Baja pipeline is a 128 kilometre system. It extends from a point near
Ehrenberg, Arizona to a point near Ogilby, California on the California-Baja
California, Mexico border. The natural gas transported on this system comes
primarily from supplies in the southwestern United States for markets in
Northern Baja California, Mexico. The sale of the North Baja pipeline is subject
to a right of first refusal by another company.
NEGT voluntarily filed for protection under Chapter 11 of the U.S. Bankruptcy
Code in July 2003. As a result, the sale of GTN to TransCanada will be subject
to bankruptcy court approval, and will include a court-sanctioned auction
process in accordance with customary bidding procedures approved by the
bankruptcy court. Under a court-sanctioned auction, NEGT will seek offers that
are higher or otherwise better than that which has been negotiated with
TransCanada. As part of its agreement, TransCanada is granted certain
protections, subject to court approval, most notably a break fee and expense
reimbursement if another bid is accepted. TransCanada also retains the right to
amend its offer should NEGT receive an offer which is superior to its existing
agreement with TransCanada. The agreement contemplates that final bankruptcy
court approval of the sale will be obtained within 75 days after signing of the
agreement. The agreement also contemplates bankruptcy court approval of the NEGT
Plan of Reorganization. Approval of NEGT's Plan could occur at a date later than
the receipt of court approval of the sale. The sale is also subject to
anti-trust review.
TransCanada will finance the acquisition in a manner consistent with maintaining
its solid financial position and credit ratings. This could include use of
internally generated cash flow, draws on committed credit lines, issuance of
debt and/or equity under the Canadian and U.S. shelf prospectuses and/or the
sale of certain assets within the company's existing portfolio.
M-7
GAS TRANSMISSION
HIGHLIGHTS
EARNINGS Net earnings from Gas Transmission decreased $31 million to $622
million in 2003 compared to $653 million in 2002. This decrease is a result of
reduced earnings of $38 million from Wholly-Owned Pipelines partially offset by
increased earnings of $7 million from Other Gas Transmission.
ALBERTA SYSTEM In February 2003, a one-year Alberta System Revenue Requirement
Settlement (the 2003 Settlement) was reached for 2003 with Alberta System
customers. Earnings in 2003 were initially expected to decrease by approximately
$40 million relative to 2002 earnings of $214 million. However, incentive
earnings realized primarily from lower financing and operating costs partially
offset the expected reduction in earnings.
CANADIAN MAINLINE In July 2003, the NEB issued its decision on TCPL's 2003
Canadian Mainline Tolls and Tariff Application. In its decision, the NEB
approved all of the key components of the application including an increase in
the composite depreciation rate to 3.42 per cent from 2.89 per cent,
introduction of a new tolling zone in southwestern Ontario, an increase to the
IT bid floor price and the continuation of the Fuel Gas Incentive Program.
Earnings in 2003 reflect, along with incentive earnings from approved programs,
return on equity based on the NEB formula and 33 per cent deemed common equity.
FOOTHILLS SYSTEM In August 2003, TCPL acquired the remaining interests in
Foothills previously not held by the company. This acquisition has strengthened
TCPL's position in the potential Alaska Highway Pipeline Project and increased
the likelihood that such a project would connect with TCPL's existing
infrastructure.
OTHER GAS TRANSMISSION In 2003, TCPL increased its ownership interest in
Portland to 61.7 per cent from 33.3 per cent through two separate transactions.
This increase in ownership, in conjunction with the impact of Portland's 2003
rate settlement, resulted in increased net earnings to TCPL. TCPL's investment
in TransGas also generated higher net earnings in 2003. Net earnings from Other
Gas Transmission in 2003 were negatively impacted by U.S. dollar currency
movements, as the majority of earnings in this business are denominated in U.S.
dollars. Iroquois Gas Transmission System (Iroquois) placed its Eastchester
expansion facilities into service in February 2004.
TRANSMISSION RESULTS-AT-A-GLANCE
YEAR ENDED DECEMBER 31 (millions of dollars)
2003 2002 2001
-----------------------------------------
WHOLLY-OWNED PIPELINES
Alberta System 190 214 204
Canadian Mainline 290 307 274
Foothills System(1) 20 17 20
BC System 6 6 5
-----------------------------------------
506 544 503
-----------------------------------------
-----------------------------------------
OTHER GAS TRANSMISSION
Great Lakes 52 66 56
Iroquois 18 18 16
TC PipeLines, LP 15 17 15
Portland(2) 11 2 (1)
Ventures LP 10 7 3
TQM 8 8 8
CrossAlta 6 13 8
TransGas 22 6 -
Northern Development (4) (6) (9)
General, administrative, support and other (22) (22) (14)
-----------------------------------------
116 109 82
-----------------------------------------
-----------------------------------------
Net earnings 622 653 585
-----------------------------------------------------------------------------------------------
-----------------------------------------------------------------------------------------------
M-8
(1) The remaining ownership interests in Foothills previously not held by TCPL
were acquired on August 15, 2003. Amounts in this table reflect TCPL's
proportionate interest in Foothills' earnings prior to acquisition and 100
per cent interest thereafter.
(2) TCPL 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 TCPL's proportionate earnings
from Portland including a 33.3 per cent ownership interest from June 2001
to September 2003, and a 21.4 per cent ownership interest prior to June
2001.
In 2003, net earnings from the Gas Transmission business were $622 million,
compared to $653 million and $585 million in 2002 and 2001, respectively. The
decrease in 2003 compared to 2002 was mainly due to lower net earnings from
Wholly-Owned Pipelines, partially offset by higher net earnings from Other Gas
Transmission. The 2003 decrease in Wholly-Owned Pipelines' net earnings was
primarily due to a reduction in the Alberta System's net earnings reflecting the
2003 Settlement. Further, earnings on the Canadian Mainline were lower in 2003
compared to 2002 due to recognition in June 2002 of the 2001 earnings impact
resulting from the Fair Return decision. Higher 2003 net earnings from Other Gas
Transmission were primarily due to increased earnings from TransGas and
Portland. The increase in 2002 earnings over 2001 was mainly due to the Fair
Return decision, higher incentive earnings from Wholly-Owned Pipelines and
higher earnings from TCPL's investment in Great Lakes.
WHOLLY-OWNED PIPELINES - FINANCIAL REVIEW
ALBERTA SYSTEM Net earnings of $190 million in 2003 were $24 million lower than
2002 and $14 million lower than 2001. The decrease compared to 2002 and 2001 was
primarily due to lower earnings resulting from the 2003 Settlement reached
between TCPL and its customers in February 2003. The 2003 Settlement included a
fixed revenue requirement component, before non-routine adjustments, of $1.277
billion compared to $1.347 billion in 2002 and $1.390 billion in 2001. The
company initially expected the lower negotiated 2003 revenue requirement would
reduce 2003 earnings by approximately $40 million relative to 2002. However,
higher incentive earnings were realized in 2003, primarily from lower financing
and operating costs which partially offset the expected reduction.
The Alberta System is one of the largest volume carriers of natural gas in North
America and delivered 3,883 Bcf of natural gas in 2003, compared to deliveries
of 4,146 Bcf in 2002 and 4,059 Bcf in 2001. The volumes transported by the
Alberta System in 2003 represented approximately 16 per cent of total North
American natural gas production and 66 per cent of the natural gas produced in
the WCSB.
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,
the rates, tolls and other charges, and terms and conditions of service are
subject to approval by the EUB.
CANADIAN MAINLINE The Canadian Mainline generated net earnings of $290 million
in 2003, a decrease of $17 million compared to 2002 and an increase of $16
million over 2001 earnings. The decrease in net earnings in 2003 from 2002 and
the increase in net earnings from 2001 to 2002 was primarily due to recognition
of incremental earnings for 2001 and 2002 as a result of the NEB's Fair Return
decision in June 2002. This decision included an increase in the deemed common
equity ratio to 33 per cent from 30 per cent, effective January 1, 2001, and
resulted in additional net earnings of $16 million for the year ended December
31, 2001, that the company recognized in June 2002. Net earnings in 2003 also
reflect the continued decrease in average investment base. These factors were
partially offset by an increase in the NEB-approved rate of return on common
equity to 9.79 per cent in 2003 from 9.53 per cent in 2002. The increase in 2003
earnings relative to 2001 is primarily due to the NEB's Fair Return decision
which provided for an increase in deemed common equity to 33 per cent.
Annual deliveries of natural gas on the Canadian Mainline totalled 2,628 Bcf in
2003, compared to 2,630 Bcf in 2002 and 2,450 Bcf in 2001. In 2003, deliveries
to export border points comprised 51 per cent of total deliveries compared to 53
per cent in 2002 and 50 per cent in 2001.
The Canadian Mainline is regulated by the NEB. The NEB sets tolls, which provide
TCPL the opportunity to recover projected costs of transporting natural gas and
also provide a return on the Canadian Mainline
M-9
average investment base. New facilities are approved by the NEB before
construction begins. Changes in investment base, the rate of return on common
equity, the level of deemed common equity and the potential for incentive
earnings affect the net earnings of the Canadian Mainline.
WHOLLY-OWNED PIPELINES - DEVELOPMENTS
REGULATORY In 2003, TCPL focused much of its efforts on the evolution of its
regulated business model. This evolution includes proposed changes to TCPL's
Canadian regulated pipeline business that would provide the company an
opportunity to earn a competitive return and enhance its ability to compete for
future market demand and natural gas supply while bringing benefits to
customers. This regulated business model is intended to advance TCPL's rate and
service offerings on all four of the company's wholly-owned pipelines.
In 2003, TCPL's activities included its appeal of the NEB's Fair Return Review
and Variance decision, the EUB's GCOC Proceeding, preparation of the 2004
Mainline Tolls and Tariff Application, the Alberta System's 2004 GRA, the
Alberta System 2003 Tariff Application which was approved by the EUB and
continued discussion with industry stakeholders.
In February 2003, the NEB denied the request TCPL made in September 2002 for a
Review and Variance of the Fair Return decision. TCPL maintains that the Fair
Return decision issued in June 2002 does not recognize the long-term business
risks of the Canadian Mainline. The company ultimately initiated an appeal of
the NEB's decision not to review and vary the Fair Return decision, with the
Federal Court of Appeal. In May 2003, the Federal Court of Appeal granted TCPL
leave to appeal the NEB's February 2003 decision. The appeal was heard in
February 2004 and TCPL awaits the judgment.
The NEB hearing for TCPL's 2003 Canadian Mainline Tolls and Tariff Application
began in February 2003. In its July 2003 decision on the application, the NEB
approved all key components of the application including an increase in the
composite depreciation rate to 3.42 per cent from 2.89 per cent, the
introduction of a new tolling zone in southwestern Ontario, an increase to the
IT bid floor price and the continuation of the Fuel Gas Incentive Program. The
2003 tolls resulting from this decision are interim pending the disposition of
TCPL's appeal to the Federal Court of Appeal regarding the NEB's Review and
Variance decision.
In July 2003, TCPL, along with other utilities, filed evidence in the EUB's GCOC
Proceeding. In this application, TCPL requested a return of 11 per cent on a
deemed common equity of 40 per cent for the Alberta System in 2004. The EUB
expects to adopt a standardized approach to determining the rate of return and
capital structure for all utilities under its jurisdiction at the conclusion of
this proceeding. Oral testimony in the hearing concluded January 16, 2004.
Written argument and reply argument are to follow with an EUB decision expected
in third quarter 2004.
In September 2003, TCPL filed with the EUB Phase I of the Alberta System's 2004
GRA, consisting of evidence in support of the applied-for rate base and revenue
requirement. The company applied for a composite depreciation rate of 4.13 per
cent compared to the current depreciation rate of 4.00 per cent. In November
2003, the company filed Phase II of the application, which primarily deals with
rate design and services. EUB hearings to consider the 2004 GRA Phase I and
Phase II applications are scheduled to commence, in Calgary, on April 1, 2004
and June 1, 2004, respectively.
The Canadian Mainline 2004 Tolls and Tariff Application was filed with the NEB
on January 26, 2004. In this application, TCPL requested a Fuel Gas Incentive
Program, establishment of a new non-renewable firm transportation (FT) service,
modifications to the existing short-term FT service and recovery of costs of
service including an 11 per cent return on deemed common equity of 40 per cent.
M-10
OPERATIONAL EXCELLENCE TCPL continued its commitment to operational excellence
in 2003 by advancing initiatives that will improve the company's ability to
provide low-cost, reliable and responsive service to customers. TCPL continues
to pursue this strategy in order to become the preferred company that customers
choose to connect new gas supplies and markets.
In 2003, TCPL exceeded its performance targets of reducing operating and
maintenance costs by rationalizing maintenance and streamlining the delivery of
services. The company met ongoing goals in the management of greenhouse gases.
TCPL also achieved exceptional plant operating performance, as measured by the
number of operational perfect days on both the Alberta System and the Canadian
Mainline. Also in 2003, TCPL improved customer satisfaction with implementation
of new systems to consolidate and enhance management of customer transactions.
Customer feedback indicates this system improvement was very well received.
In 2004, TCPL will continue to focus efforts on cost reduction, operational
reliability, and environmental and safety performance. The company has
established 2004 operating and maintenance budgets with an expectation of
further productivity gains, while operating reliability targets have increased
and greenhouse gas emissions management programs continue to receive focused
attention. Additional effort will be undertaken in 2004 with respect to
improving contractor safety performance.
SUPPLY In 2003, TCPL continued to connect incremental natural gas supply in
the WCSB, in Alberta and from B.C. Additional production from the Sierra area
of B.C. is expected to commence delivery to Alberta in early 2004.
The timely connection of these volumes has allowed TCPL's customers to take
advantage of premium gas price environments. TCPL will continue to grow by
seeking new opportunities to connect additional gas supplies.
MARKETS TCPL continues to pursue growth opportunities within existing and new
natural gas markets. In 2003, TCPL took steps to expand its pipeline system in
western Canada through the pending acquisition of the Simmons Pipeline System,
via the execution of a long-term transportation service arrangement with
TransCanada Pipeline Ventures Limited Partnership (Ventures LP) and through
expansion of the Alberta System. These arrangements, upon regulatory approval
expected in 2004, will allow TCPL to increase the company's delivery capacity
into the rapidly expanding area of Fort McMurray, Alberta to approximately 700
million cubic feet per day (MMcf/d).
TCPL also continues to pursue increased deliveries in response to market
growth in both Canada and the U.S. While customers have been repositioning
their pipeline contracts away from long haul arrangements originating in
Alberta to short haul contracts originating at local market hubs, the
underlying markets continue to grow.
FOOTHILLS ACQUISITION In August 2003, TCPL acquired the remaining interests in
Foothills previously not held by the company for $259 million, including
assumption of $154 million of Foothills' debt. As a result, TCPL now owns 100
per cent of Foothills. Foothills and its subsidiaries hold the certificates to
build the Canadian portion of the Alaska Highway Pipeline Project which would
bring Prudhoe Bay natural gas from Alaska to markets in Canada and the U.S. The
"prebuild" portion of this project has been operating for more than 20 years,
moving Alberta natural gas to U.S. markets in advance of flows from Alaska.
Subsidiaries of Foothills and TCPL also hold certificates to build the Alaskan
section of this project.
WHOLLY-OWNED PIPELINES - OUTLOOK
TCPL'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, the
Wholly-Owned Pipelines have focused on providing market-responsive products and
services, competitive cost-effective structures, and the highest levels of
reliability to customers.
M-11
In 2004, the Wholly-Owned Pipelines 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. TCPL
will also continue to work collaboratively with all stakeholders in resolving
jurisdictional issues, advancing changes to the regulated business model and
addressing fair return challenges.
Looking forward, as the supply/demand balance tightens, producers will continue
to explore and develop new fields, as well as unconventional supply such as gas
production from coal bed methane reserves. In addition, stakeholder support is
expected to grow for proposals to access Northern gas from the Mackenzie Delta
and Alaska North Slope. TCPL will seek to connect these additional natural gas
supplies to the Alberta System.
TCPL's earnings from its Wholly-Owned Pipelines are primarily determined by the
average investment base, return on common equity, deemed common equity and
opportunity for incentive earnings. In the short to medium term, the company
expects modest growth from these mature assets and therefore anticipates
continued decline in the average investment base. Accordingly, without an
increase to return on equity, 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
Wholly-Owned Pipelines are not affected by short-term fluctuations in the
commodity price of natural gas, changes in throughput volumes or changes in FT
contract levels.
EARNINGS In 2004, net earnings from Wholly-Owned Pipelines will depend in large
part on the outcome of the appeal of the NEB's Fair Return Review and Variance
decision, the EUB's GCOC hearing, the 2004 Mainline Tolls and Tariff Application
and the Alberta System's 2004 GRA. In the absence of favorable rulings in these
applications, the company expects 2004 earnings to be lower compared to 2003
earnings, primarily due to the combined effect of a decrease in rate of return
on common equity in 2004 (Canadian Mainline 2003 - 9.79 per cent versus 2004 -
9.56 per cent based on the NEB formula) and lower average investment bases.
Although 2004 earnings may be lower than 2003 earnings, Wholly-Owned Pipelines
will continue to generate strong cash flow.
CAPITAL EXPENDITURES Total capital spending for the Alberta System, Canadian
Mainline and BC System during 2003 was approximately $100 million. Capital
spending in 2004, including the Foothills System, is expected to approximately
double the expenditures in 2003, primarily due to higher capacity capital
spending.
WHOLLY-OWNED PIPELINES - BUSINESS RISKS
COMPETITION TCPL 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. The construction of the Alliance Pipeline, a natural
gas pipeline from northeast B.C. to the Chicago area, and the continued
expiration of transportation contracts have resulted in significant reductions
in firm contracted capacity on both the Alberta System and the Canadian
Mainline. The Canadian Mainline absorbs the bulk of any volume swings in the
WCSB.
As of December 2002, the WCSB had estimated remaining discovered natural gas
reserves of 57 trillion cubic feet and a reserves-to-production ratio of
approximately nine years at current levels of production. Additional reserves
are continually being 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, the WCSB
supply is expected to remain essentially flat.
TCPL's Alberta System provides the major natural gas gathering and export
transportation capacity for the WCSB. It does so by connecting to most of the
gas processing plants in Alberta and then transporting natural gas for domestic
and export deliveries. The Alberta System faces competition primarily from the
M-12
Alliance Pipeline. In addition, the Alberta System has faced, and will continue
to face, increasing competition from other pipelines.
The Canadian Mainline is TCPL's cross-continent natural gas pipeline serving
mid-western and eastern markets in Canada and the U.S. TCPL continues to face
competition for transportation services to eastern Canadian markets and U.S.
export points. The demand for natural gas in TCPL'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, TCPL 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 have historically
received Canadian supplies only from TCPL are capable of receiving supplies from
new pipelines into the region that can source both western Canadian and U.S.
supplies.
The Canadian Mainline has experienced reductions in long haul FT contracts for
deliveries originating at the Alberta border and in Saskatchewan of
approximately 2.5 Bcf/d, or approximately 36 per cent of its capacity since the
1998/1999 contract year. 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 utilization of the Canadian Mainline is not expected to
increase in the short to medium term as any additional supply from the WCSB is
expected to be absorbed by demand growth within western Canada and by higher
flows on other pipeline systems.
TCPL will continue to work with stakeholders in 2004 to advance various aspects
of the company's regulated business model for the Alberta System, Canadian
Mainline, Foothills System and the BC System.
FINANCIAL RISK The company remains concerned about the long-term implications of
a financial return that discourages additional investment in existing Canadian
natural gas transmission systems. TCPL has applied for a return of 11 per cent
on 40 per cent deemed common equity, both to the NEB in the 2004 Mainline Tolls
and Tariff Application and to the EUB in the Alberta System's application in the
GCOC Proceeding. The outcome of the Federal Court of Appeal hearing regarding
the NEB's Review and Variance decision as well as the GCOC proceeding, could
have a significant impact on the financial returns for, and future investment
in, TCPL's Canadian pipelines.
The company is cognizant 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.
SAFETY TCPL worked closely with regulators, customers and communities during
2003 to ensure the continued safety of employees and the public. In 2003, two
line breaks occurred in a remote area of Alberta resulting in a short-term
reduction in natural gas shipments. Neither incident resulted in injuries or
damage to public property. Under the current regulatory models, expenditures on
pipeline integrity have no negative impact on earnings. The company expects to
spend approximately $76 million in 2004 on pipeline integrity compared to $73
million in 2003. TCPL 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 2003, TCPL continued to conduct activities to increase
environmental protection through proactive sampling, remediation and monitoring
programs. Compressor stations on the Canadian Mainline have been assessed
through the company's Site Assessment, Remediation & Monitoring (SARM) program.
In 2003, approximately $5 million was invested in improved environmental
protection measures at identified TCPL locations. 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
four Alberta sites was undertaken in 2003, effectively remediating each site.
M-13
For information on management of risks with respect to the Gas Transmission
business, please see the Risk Management section beginning on page M-35.
OTHER GAS TRANSMISSION - FINANCIAL REVIEW
Other Gas Transmission is comprised of TCPL's direct and indirect investment in
various natural gas pipelines and gas transmission related businesses. It also
includes project development activities related to TCPL's pursuit of new natural
gas pipeline and gas transmission related opportunities throughout North
America, including the North and LNG.
TCPL's net earnings from Other Gas Transmission in 2003 were $116 million
compared to $109 million and $82 million in 2002 and 2001, respectively. The
increased net earnings of $7 million in 2003 compared to 2002 were due to higher
earnings from TransGas as a result of recognition of an adjustment for future
income tax benefits of $11 million and higher contractual tolls in 2003. In
addition, earnings from Portland were higher compared to 2002 due to the impacts
of a rate settlement in early 2003 and TCPL increasing its ownership interest in
2003. Earnings from Ventures LP was also higher due to higher contracted
transportation volumes. These increases were partially offset by the impact of a
substantially weaker U.S. dollar, higher project development costs and lower
earnings from CrossAlta Gas Storage & Services Ltd. (CrossAlta) due to lower
storage margins as a result of unfavourable market conditions. In addition, 2002
earnings included TCPL's $7 million share of a favourable ruling for Great Lakes
related to Minnesota use tax paid in prior years.
Other Gas Transmission net earnings of $109 million in 2002 increased by $27
million compared to 2001. This increase resulted from higher earnings from U.S.
investments which included TCPL's $7 million share of the favourable ruling for
Great Lakes related to Minnesota use tax paid in prior years, increased
ownership interests in Iroquois and Portland acquired in mid-2001, higher
transportation margins and favourable movements in exchange rates. Earnings from
CrossAlta were also higher due to higher storage margins, increased storage
capacity and reduced operating expenses. In addition, there was reduced spending
on Northern Development in 2002 and increased earnings from Ventures LP.
OTHER GAS TRANSMISSION - DEVELOPMENTS
In 2003, TCPL increased its ownership interest in Portland, secured a
position in the Mackenzie Gas Pipeline Project and pursued LNG projects by
conducting preliminary assessments of LNG facilities in the Northeast U.S.
and eastern Canada.
TC PIPELINES, LP TCPL holds a 33.4 per cent interest in TC PipeLines, LP that in
turn holds a 30 per cent interest in Northern Border Pipeline Company (Northern
Border) and a 49 per cent interest in Tuscarora Gas Transmission Company
(Tuscarora). In July 2003, TC PipeLines, LP increased its quarterly distribution
to US$0.55 per unit from US$0.525 per unit. This represents the fourth increase
in the partnership's quarterly cash distribution since the commencement of
operations in May 1999.
In December 2003, Tuscarora received management approval for an expansion
project which will provide for approximately 57 MMcf/d incremental capacity on
its system. Total capital cost is estimated to be approximately US$16.6 million,
and the expansion is scheduled to commence service in November 2005.
IROQUOIS The Eastchester expansion project experienced several delays throughout
2003 primarily due to construction complications. However, by the end of 2003,
Iroquois had successfully resolved the majority of these construction issues and
placed the expansion facilities into service in February 2004. The expansion is
the first major natural gas transmission pipeline to be built into New York City
in approximately 40 years.
In October 2003, the Federal Energy Regulatory Commission (FERC) approved
Iroquois' mainline rate settlement, which was filed in August 2003. The
settlement is effective from January 1, 2004 through December 2007, during which
period Iroquois will reduce rates by approximately 13 per cent. The settlement
does not establish rates, terms or conditions for the Eastchester expansion,
which was covered
M-14
by a separate rate application filed with the FERC in January 2004. The FERC has
issued an order that accepts Iroquois' application effective July 1, 2004
subject to refund and conditions, and establishing hearing procedures.
PORTLAND In September 2003, the company purchased an additional 10.1 per cent
ownership interest in Portland for approximately US$47 million, including
assumed debt of approximately US$28 million. In December 2003, the company
purchased a further 18.3 per cent interest for approximately US$82 million,
including assumed debt of approximately US$50 million, thus increasing its total
ownership interest in Portland to 61.7 per cent. Subsequent to this acquisition,
Portland was fully consolidated in the company's financial statements, with 38.3
per cent reflected in non-controlling interests.
Portland and customer representatives reached an agreement on new tolls and FERC
approved it in its entirety in January 2003. The agreement is effective from
April 1, 2002 through April 1, 2008. Lower depreciation rates and revised tolls
provided for in the agreement have had a positive impact on Portland's earnings
in 2003.
TQM In January 2003, TCPL began performing the majority of operational and
administrative activities for TQM to allow TQM to benefit from best practices
employed in the industry at the lowest possible cost. As a result of this
reorganization, TQM has realized cost savings, which, in accordance with its
incentive agreement, will be shared among its customers and owners.
NORTHERN DEVELOPMENT In 2003, TCPL continued to pursue pipeline opportunities to
move both Mackenzie Delta and Alaska North Slope natural gas to markets
throughout North America. TCPL worked with key stakeholders with the objective
of participating in any potential pipeline project.
TCPL, the Mackenzie Delta gas producers and the APG reached funding and
participation agreements in June 2003 that enable the APG to become a full
participant in the proposed Mackenzie Gas Pipeline Project. This project would
result in a natural gas pipeline being constructed from Inuvik, Northwest
Territories to the northern border of Alberta, where it would then connect with
the Alberta System. TCPL has agreed to finance the APG for its one-third share
of project definition costs. This share is currently expected to be
approximately $90 million over three years. This loan will be repaid from the
APG's share of future pipeline revenues. In the year ended December 31, 2003,
TCPL funded $34 million of this loan. Under the terms of the agreement, TCPL
gains an immediate opportunity to acquire up to five per cent equity ownership
of the pipeline at the time of construction. In addition, TCPL 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.
TCPL continued to work with the Alaska Highway Pipeline stakeholders in 2003 to
advance that project. Resolution of Foothills' Special Charge was reached with
Foothills shippers and the Canadian Association of Petroleum Producers, and
subsequently approved by the NEB, in March 2003. The resolution waives
Foothills' obligation to repay all past and future Special Charge collections
when Alaskan gas starts flowing on the Foothills System. In October 2003, the
Government of Canada, once again, reaffirmed its preference to utilize the
framework provided in the Northern Pipeline Act which granted Foothills the
certificates to transport Alaskan gas across Canada. In January 2004, Foothills
and the Kaska First Nation signed an Agreement-in-Principle that provides the
framework for a future participation agreement. The Agreement-in-Principle marks
the completion of the second stage of negotiations that is expected to lead to a
participation agreement for the Alaska Highway Pipeline Project.
LIQUEFIED NATURAL GAS In September 2003, TCPL and ConocoPhillips announced the
Fairwinds partnership to jointly evaluate a site in Harpswell, Maine for the
development of an LNG regasification facility. The residents of the Town of
Harpswell are expected to vote on leasing a town-owned site for the facility. If
leasing of the site is approved and necessary regulatory approvals are
subsequently received, construction of the LNG facility could begin in 2006 with
the facility becoming operational in 2009. Natural gas from the LNG facility
would be delivered by pipeline to markets in the northeast U.S.
M-15
OTHER GAS TRANSMISSION - STRATEGY AND OUTLOOK
TCPL continues to actively pursue natural gas pipeline and gas transmission
related development and acquisition opportunities in North America, where these
opportunities are driven by strong customer demand and sound economics. With
TCPL's strong financial position, the company is poised to capitalize on future
acquisition and development opportunities. 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
TCPL, with the company expanding existing facilities across North America and
being involved in the development of alternative natural gas transportation
solutions as producers access natural gas reserves in the North and Atlantic
Canada.
TCPL is committed to play a key role in Northern gas development. While there
are many issues to be resolved before this moves forward, TCPL has competitive
advantages including expertise in the design, construction and operation of
large diameter pipelines in cold weather conditions. TCPL 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.
Excluding the impact of the recognition of the $11 million TransGas future tax
benefits in 2003, the net earnings outlook for Other Gas Transmission in 2004 is
expected to be similar to 2003. Net earnings will be affected by factors such as
the performance of the Canadian dollar relative to the U.S. dollar and the level
of project development costs.
OTHER GAS TRANSMISSION - BUSINESS RISKS
FOREIGN EXCHANGE A significant amount of the earnings in Other Gas Transmission
is generated from U.S. pipeline affiliates. The performance of the Canadian
dollar relative to the U.S. dollar would either positively or negatively impact
this business segment's results.
THROUGHPUT RISK Iroquois, Portland and Tuscarora all have long-term demand
charge contracts in place with customers and as such, are virtually unaffected
by changes in throughput. As transportation contracts expire on Great Lakes and
Northern Border, these entities 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.
INSURANCE, EMPLOYEE BENEFITS AND INTEREST RATES Insurance costs continue to rise
with the increasing risk of terrorism and sabotage in recent years. The costs of
employee benefits, particularly in the U.S., also continue to increase. At the
same time, interest rates remain near historical lows. If these insurance and
employee benefits costs continue to rise and the economic recovery results in
increased interest rates, earnings of Other Gas Transmission could be negatively
impacted.
REGULATION The U.S. partially-owned pipelines are regulated by the FERC while
the Canadian partially-owned pipeline is regulated by the NEB. These regulators
play a significant role in approving the pipelines' respective returns on
equity, capital structures, tolls and system expansions.
M-16
NATURAL GAS THROUGHPUT VOLUMES
(Bcf)
2003 2002 2001
-------------------------------------
Alberta System(1) 3,883 4,146 4,059
Canadian Mainline(2) 2,628 2,630 2,450
Foothills System 1,110 1,098 1,117
BC System 325 371 395
Great Lakes 856 863 804
Northern Border 850 839 821
Iroquois 341 340 314
Portland 53 52 44
Tuscarora 22 20 23
TQM 164 175 161
Ventures LP 111 85 60
TransGas 16 16 14
-----------------------------------------------------------------------------
-----------------------------------------------------------------------------
(1) Field receipt volumes for the Alberta System for the year ended December
31, 2003 were 3,892 Bcf (2002 - 4,101 Bcf; 2001 - 4,170 Bcf).
(2) Canadian Mainline deliveries originating at the Alberta border and in
Saskatchewan for the year ended December 31, 2003 were 2,055 Bcf (2002 -
2,221 Bcf; 2001 - 2,098 Bcf).
DESCRIPTION OF TCPL'S SIGNIFICANT GAS TRANSMISSION OPERATIONS
ALBERTA SYSTEM
TCPL'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, Foothills System
and other pipelines. The 22,700 kilometre system is one of the largest carriers
of natural gas in North America.
CANADIAN MAINLINE
TCPL's 100 per cent owned natural gas transmission system in Canada extends
14,900 kilometres from the Alberta/Saskatchewan border east to Quebec/Vermont
and connects with other natural gas pipelines in Canada and the U.S.
FOOTHILLS SYSTEM
TCPL's 100 per cent owned 1,040 kilometre 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
TCPL's 100 per cent owned natural gas transmission system extends 200 kilometres
from Alberta's western border through B.C. to the U.S. border, serving markets
in B.C. as well as the Pacific Northwest, California and Nevada.
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. TCPL has a 50 per
cent ownership interest in this 3,387 kilometre pipeline system.
NORTHERN BORDER
Northern Border is a 2,010 kilometre natural gas pipeline system which serves
the U.S. Midwest from a connection with the Foothills System. TCPL indirectly
owns approximately 10 per cent of Northern Border through its 33.4 per cent
ownership interest in TC PipeLines, LP.
IROQUOIS
Iroquois connects with the Canadian Mainline near Waddington, New York and
delivers natural gas to customers in the northeastern U.S. TCPL has a 41 per
cent ownership interest in this 663 kilometre pipeline system.
M-17
PORTLAND
Portland operates a 471 kilometre pipeline that connects with TQM near East
Hereford, Quebec and delivers natural gas to customers in the northeastern U.S.
As at December 31, 2003, TCPL had a 61.7 per cent ownership interest in
Portland.
TQM
TQM is a 572 kilometre natural gas pipeline system which connects with the
Canadian Mainline and transports natural gas from Montreal to Quebec City and to
the Portland system. TCPL holds a 50 per cent ownership interest in TQM.
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
MMcf/d. TCPL holds a 60 per cent ownership interest in CrossAlta.
TUSCARORA
Tuscarora operates a 386 kilometre pipeline system transporting natural gas from
Malin, Oregon to Wadsworth, Nevada with delivery points in northeastern
California. TCPL owns an aggregate 17.4 per cent interest in Tuscarora, of which
16.4 per cent is held through TCPL's interest in TC PipeLines, LP.
VENTURES LP
Ventures LP, 100 per cent owned by TCPL, owns a 121 kilometre pipeline and
related facilities which supply natural gas to the oil sands region of northern
Alberta, and a 27 kilometre pipeline which supplies natural gas to a
petrochemical complex at Joffre, Alberta.
TRANSGAS
TransGas is a 344 kilometre natural gas pipeline system which runs from
Mariquita in the central region of Colombia to Cali in the southwest of
Colombia. TCPL holds a 46.5 per cent interest in this pipeline.
POWER
HIGHLIGHTS
EARNINGS The Power segment made a significant contribution to TCPL's earnings in
2003. Net earnings increased 51 per cent from 2002 due in part to the
acquisition of Bruce Power and increased earnings from Western Operations.
BRUCE POWER TCPL completed the acquisition of a 31.6 per cent equity interest in
Bruce Power, the operator and lessee of the Bruce nuclear power facility in
Ontario. This acquisition indirectly increased TCPL's nominal generating
capacity by 1,000 MW in February 2003. The return to service of Bruce Power A
Unit 4 in fourth quarter 2003 and Bruce Power A Unit 3 in first quarter 2004
increased TCPL's 31.6 per cent share of the nominal generating capacity of Bruce
Power to 1,474 MW.
EXPANDING ASSET BASE In June 2003, TCPL announced its plans to develop the 550
MW Becancour natural gas-fired cogeneration power plant in Quebec. The project
which is estimated to cost approximately $550 million, including capitalized
interest, is expected to be placed in-service in late 2006. In October 2003,
TCPL and Grandview Cogeneration Corporation, an affiliate of Irving Oil Limited
(Irving), announced an agreement to construct a 90 MW natural gas-fired
cogeneration power plant on the site of the Irving Oil Refinery in Saint John,
New Brunswick. The plant is expected to be placed in-service by the end of 2004
at a total estimated cost of approximately $90 million. The company placed the
Bear Creek plant in Alberta in-service in first quarter 2003 and expects the
MacKay River plant to be commercially in-service in first quarter 2004.
M-18
OPERATIONAL EXCELLENCE Average plant availability, excluding Bruce Power, was 94
per cent in 2003 compared to 96 per cent in 2002. This slight decrease resulted
primarily from scheduled maintenance at some of the plants in Western
Operations. Including Bruce Power, average plant availability decreased to 90
per cent for 2003 as a result of scheduled maintenance on two Bruce Power B
units.
POWER RESULTS-AT-A-GLANCE
YEAR ENDED DECEMBER 31 (millions of dollars)
2003 2002 2001
-------------------------------------
Western operations 160 131 149
Eastern operations 127 149 159
Bruce Power investment 99 - -
Power LP investment 35 36 39
General, administrative and support costs (86) (73) (49)
-------------------------------------
Operating and other income 335 243 298
Financial charges (12) (13) (24)
Income taxes (103) (84) (106)
-------------------------------------
Net earnings 220 146 168
----------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------
TCPL's Power business contributed $220 million of net earnings in 2003, an
increase of $74 million or 51 per cent compared to earnings of $146 million in
2002. This increase is primarily attributable to TCPL's acquisition in February
2003 of a 31.6 per cent interest in Bruce Power and higher contributions from
Western Operations. Partially offsetting the increase were lower earnings from
Eastern Operations and higher general, administrative and support costs.
The increase in general, administrative and support costs in 2003 compared to
the two prior years reflects higher support costs associated with the company's
focus on growth in Power.
Power's net earnings of $146 million in 2002 decreased $22 million compared to
2001. This decrease primarily reflected TCPL's ability to capitalize on market
opportunities in both Western and Eastern Operations in 2001 which did not exist
in 2002.
M-19
NOMINAL GENERATING CAPACITY AND FUEL TYPE OF POWER PLANTS
-------------------------------------------------------------------------------------------
MW FUEL TYPE
------------- -------------------------------
WESTERN OPERATIONS
Sundance A(1) 560 Coal
Sundance B(1) 353 Coal
ManChief 300 Natural gas
MacKay River 165 Natural gas
Carseland 80 Natural gas
Bear Creek 80 Natural gas
Redwater 40 Natural gas
Cancarb 27 Natural gas
----------------
1,605
----------------
----------------
EASTERN OPERATIONS
Ocean State 560 Natural gas
Curtis Palmer 60 Hydro
Becancour(2) 550 Natural gas
Grandview(3) 90 Natural gas
----------------
1,260
----------------
----------------
BRUCE POWER L.P. INVESTMENT(4)
Bruce B(5) 1,000 Nuclear
Bruce A(6) 474 Nuclear
----------------
1,474
----------------
----------------
POWER LP INVESTMENT(7)
Williams Lake 66 Wood waste
Castleton 64 Natural gas
Tunis 43 Natural gas/waste heat
Nipigon 40 Natural gas/waste heat
Kapuskasing 40 Natural gas/waste heat
North Bay 40 Natural gas/waste heat
Calstock 35 Wood waste/waste heat
----------------
328
----------------
----------------
4,667
-------------------------------------------------------------------------------------------
-------------------------------------------------------------------------------------------
(1) TCPL directly or indirectly acquires 560 MW from Sundance A and 353 MW from
Sundance B through long-term PPAs, which represents 100 per cent of the
Sundance A and 50 per cent of the Sundance B power plant output,
respectively.
(2) Currently in the permitting phase.
(3) Currently under construction.
(4) Represents TCPL's 31.6 per cent equity interest in Bruce Power.
(5) Bruce B consists of four reactors, which are currently in operation, with a
capacity of approximately 3,160 MW. The generating capacity of
approximately 1,000 MW includes two MW from TCPL's 17 per cent indirect
share in Huron Wind L.P. which owns a nine MW wind farm.
(6) Bruce A consists of four 750 MW reactors. Bruce A Unit 4 was returned to
service in the fourth quarter of 2003. Bruce A Unit 3 was returned to
service in first quarter 2004. Bruce A Units 1 and 2 remain out of service.
(7) At December 31, 2003, TCPL operated and managed Power LP and held a 35.6
per cent ownership interest in Power LP. The volumes in the table represent
100 per cent of plant capacity.
POWER - DEVELOPMENTS
TCPL's Power segment had another strong year in 2003. The Power segment
continued to grow, completing the acquisition of a 31.6 per cent interest in
Bruce Power in February 2003, placing the Bear Creek plant in-service in 2003,
and completing construction of the MacKay River facility at the end of 2003.
TCPL also increased its presence in eastern Canada, announcing plans to
construct two power plants, Becancour in Quebec and Grandview in New Brunswick.
TCPL continues to utilize its competitive strengths to seek quality
acquisitions, greenfield development opportunities and expansion of the
company's existing businesses to complement the current portfolio of power
generation assets. TCPL is generally able to expand the company's portfolio of
power plants while mitigating excessive price risk through the long-term sale of
electricity and steam/heat to the adjacent
M-20
industrial customers for a portion of the plant output while, at the same time,
retaining a certain amount of merchant power capacity to be sold to other
customers.
WESTERN OPERATIONS
The focus of Western Operations is to optimize and expand the existing asset
base and maximize asset value through a combination of long- and short-term
sales contracts and low-cost generation and supply.
Western Operations has two main components - Western Marketing and Plant
Operations. Western Marketing consists of the power marketing operations
originating out of the Calgary office, including marketing of uncommitted
generation from the Alberta plants and the purchase and resale of electricity
related to the Sundance PPAs. Western Marketing also participates in marketing
electricity in western Canada and throughout the U.S. from Washington state to
Wisconsin. Plant Operations consists of contributions from the Alberta power
plants, the ManChief plant in Colorado, and fees earned to manage and operate
Power LP's seven plants.
WESTERN MARKETING While a significant portion of Western Plant Operations'
generation is sold under long-term contracts to mitigate price risk, some power
is intentionally not sold under long-term contracts. The Western Marketing
group's primary function is to manage these open positions to maximize the value
of Power's assets through marketing and trading activities as well as through
operational optimization. In order to mitigate market price risk, Western
Operations has sold approximately 84 per cent of the total generation for 2004
and 70 per cent of the expected, average combined total power supply for the
next three years. Western Operations' largest power supply is its Sundance PPAs.
TCPL has sold essentially all of the Sundance PPA power supply in 2004 and 69
per cent and 49 per cent of the expected combined power supply for 2005 and
2006, respectively. Western Marketing continues to secure additional long-term
sales contracts for the remaining power supply.
PLANT OPERATIONS Plant Operations is another area of success and growth for
TCPL. The expansion of this area is consistent with TCPL's focus on capitalizing
on the company's expertise in developing new projects and maintaining its
position as a prominent player in the Alberta market. The Bear Creek plant began
commercial operations in March 2003. This 80 MW cogeneration facility near
Grande Prairie, Alberta sells the majority of its power to Weyerhaeuser's Grande
Prairie Pulp Mill, as well as Weyerhaeuser's other Alberta facilities.
Construction of the MacKay River plant was completed in fourth quarter 2003 and
the plant is expected to be in-service in first quarter 2004. The 165 MW
cogeneration facility near Fort McMurray, Alberta, will provide electricity and
steam to Petro-Canada's adjacent in-situ oil sands operations. The MacKay River
plant increases TCPL's directly controlled supply in Alberta to more than 1,300
MW.
Plant Operations is committed to an operational excellence model that provides
low-cost, reliable operating performance at each of its plants. The Redwater and
Carseland plants, both completing their second year of operation, operated very
well in 2003. Bear Creek is still in its first year of operations and is in the
process of ongoing operational optimization. ManChief, which was acquired in
November 2002, is another solid performing asset in TCPL's power generation
portfolio. The entire capacity is sold under long-term tolling contracts that
expire in 2012.
Operating and other income from Western Operations increased by 22 per cent to
$160 million in 2003 from $131 million in 2002 due primarily to a positive $31
million pre-tax ($19 million after tax) settlement in June 2003 with a former
counterparty that defaulted in 2001 under power forward contracts. A full year
of earnings from the ManChief plant, which was acquired in late 2002, higher
contributions from the Sundance PPAs reflecting lower transmission costs, and
higher earnings from the Alberta plants also contributed to higher operating
income. Offsetting these increases were the effects in 2003 of lower prices
achieved on the overall sale of power and the higher cost of natural gas fuel at
the carbon black facility.
While the average Alberta Pool Price for 2003 was $63/megawatt hour (MWh)
compared to $44/MWh in 2002, margins were lower in 2003 due to lower realized
prices and reduced market liquidity.
M-21
Operating income from Western Operations decreased $18 million to $131 million
in 2002 when compared to 2001. Market opportunities that existed in 2001
resulting from high power prices (average Alberta Pool Price of $71/ MWh in
2001) and price volatility in western Canada and the Pacific Northwest regions
did not carry over into 2002. However, this was partially offset by income from
the acquisition of the Sundance B PPA, ManChief, and the placing in-service of
the Redwater and Carseland plants.
EASTERN OPERATIONS
Power's Eastern Operations is focused on the New England and New York
deregulated power markets and consists of Power Marketing and Power Generation
operations, both of which operate as one integrated business. Eastern Operations
also include the company's development opportunities in Ontario and other
provinces in eastern Canada.
Over the past five years, TransCanada Power Marketing Limited (TCPM), an
affiliate located in Westborough, Massachusetts, has successfully navigated
through New England's deregulation process and firmly established itself as a
leading power generator and energy provider in the New England power market.
TCPL continues to seek out opportunities to add generation capacity to the
existing asset base and leverage off this experience in expanding its presence
in the Ontario market.
POWER MARKETING TCPL's continued success and growth in the northeast U.S. is the
direct result of an efficient marketing operation which is conducted through
TCPM. TCPM is focused on selling power under contract to wholesale, commercial
and industrial customers while managing a portfolio of power supplies sourced
from both its own generation assets and wholesale power purchases. TCPM is a
full service provider offering different products and services to assist
customers in managing their power supply and power prices in deregulated power
markets. Through active portfolio management, TCPM has positioned itself to
capture market opportunities as they arise, while reducing downside exposure.
Included in the additional power supply is TCPM's purchase of 100 per cent of
the output of the 64 MW natural gas-fired combined-cycle plant located in
Castleton-on-Hudson, New York (Castleton), which is owned by Power LP.
POWER GENERATION Eastern U.S. power generation assets include Ocean State Power
(OSP), a 560 MW natural gas-fired plant located in Rhode Island, and the 60 MW
Curtis and Palmer hydroelectric facilities (Curtis Palmer) near Corinth, New
York. Of the total OSP output, 76.5 per cent is sold under long-term purchase
arrangements to TCPM with the remainder sold to Boston Edison Company. Output
from Curtis Palmer is sold into the New York market under a fixed-price,
long-term power purchase agreement with Niagara Mohawk Power Corporation for an
expected term of more than 25 years. Curtis Palmer has a high capacity factor
due to its strategic location just downstream of certain water storage
facilities on the Hudson River, but earnings are subject to seasonal and annual
variations in water levels.
Operating income for 2003 from Eastern Operations was $127 million compared to
$149 million in 2002. The $22 million decrease was primarily due to the impact
of higher natural gas fuel costs at OSP resulting from an arbitration process
and the unfavourable impact of a weaker U.S. dollar. Partially offsetting these
decreases were incremental earnings from the growth in volumes and margins in
the eastern U.S. retail business which is focused on sales to large commercial
and industrial customers. In addition, 2003 had higher earnings from Curtis
Palmer as a result of above average water flows and revenue earned from a
temporary generation facility built and operated in Cobourg, Ontario during the
summer of 2003.
Operating income of $149 million in 2002 was slightly lower than the
unprecedented $159 million of earnings in 2001. The decrease year over year was
primarily due to the ability throughout 2001 to capitalize on price volatility
that was less prevalent in 2002, partially offset by a full year of earnings
from the Curtis Palmer hydroelectric facilities purchased in July 2001.
The long-term natural gas supply for OSP is subject to a yearly price
renegotiation. If OSP and the suppliers are unable to reach an agreement on
price in a given year, the matter is settled by arbitration.
M-22
OSP is currently in its third such arbitration with its natural gas fuel
suppliers. The first two arbitration decisions substantially increased OSP's
natural gas fuel costs.
DEVELOPMENT OPPORTUNITIES IN EASTERN CANADA In October 2003, TCPL and an
affiliate of Irving announced an agreement to build a 90 MW natural gas-fired
cogeneration power plant in Saint John, New Brunswick to be developed and owned
by TCPL. Under a 20 year tolling arrangement, Irving will provide fuel for the
plant and contract for 100 per cent of the plant's heat and electricity output.
Construction of the facility began in December 2003 and is expected to be
in-service by the end of 2004.
In June 2003, TCPL announced its plans to develop a 550 MW natural gas-fired
cogeneration power plant in Quebec. The power plant will be located in the
Becancour Industrial Park, near Trois-Rivieres and will supply its entire power
output to Hydro-Quebec Distribution under a 20 year power purchase contract. The
plant will also supply steam to certain major businesses located within the
industrial park. Construction of the facility is likely to begin in 2004,
pending receipt of regulatory approvals, and is expected to be in-service in
late 2006.
Power continues to assess the viability of developing a natural gas-fuelled
energy centre to meet electricity needs in downtown Toronto through its
partnership with Ontario Power Generation (OPG) in the Portlands Energy Centre
L.P. Situating generation in downtown Toronto, close to the end user, would help
alleviate current and future transmission issues in the downtown core.
BRUCE POWER INVESTMENT
On February 14, 2003, the company completed the acquisitions of a 31.6 per cent
interest in Bruce Power and a 33.3 per cent interest in Bruce Power Inc., the
general partner of Bruce Power, for $409 million. TCPL also funded a one-third
share ($75 million) of a $225 million accelerated deferred rent payment made by
Bruce Power to OPG.
TCPL acquired the interests as part of a consortium (the Consortium) that
includes Cameco Corporation (Cameco) and BPC Generation Infrastructure Trust, a
trust established by the Ontario Municipal Employees Retirement System. Under
the agreement, the Consortium acquired British Energy (Canada) Ltd., which owned
a 79.8 per cent interest in Bruce Power as well as a 50 per cent interest in the
nine MW Huron Wind L.P. power facility.
Located in Ontario, the Bruce Power facility is made up of two nuclear plants -
Bruce B and Bruce A. Bruce B consists of four reactors, which are currently in
operation, with a capacity of approximately 3,160 MW. Bruce A consists of four
reactors, which up until 2003, were not operating. In 2003, Bruce Power
completed efforts to restart Bruce A Unit 4, followed on January 8, 2004 with
the restart of Bruce A Unit 3. Both units were laid-up in 1998. These two Bruce
A units add 1,500 MW of capacity, bringing Bruce Power's total capacity to 4,660
MW.
Bruce Power is the tenant under a lease with OPG on the Bruce nuclear power
facility. The initial term of the lease expires in 2018 with an option to extend
the lease by up to 25 years. The Bruce nuclear power facility continues to be
managed and operated by the management and staff of Bruce Power. Spent fuel and
decommissioning liabilities remain the responsibility of OPG and, as determined
at the inception of the lease, are covered by the existing lease payments. The
lease agreement with OPG provides for limited adjustments to the base rent every
five years during the initial term of the lease.
TCPL's share of power output during the period of ownership in 2003 was 6,655
gigawatt hours (GWh). This includes power output from Bruce A Unit 4 for
November and December 2003. Bruce A Unit 4 began producing electricity to the
Ontario electricity grid on October 7, 2003 and was considered commercially
in-service on November 1, 2003. Bruce A Unit 3 reconnected to the Ontario
electricity grid on January 8, 2004. Similar to the Bruce A Unit 4 startup
process, after performing and evaluating tests of the shutdown system, Bruce A
Unit 3 was reconnected to the grid and is expected to ramp up to full power in
first quarter 2004. As of December 31, 2003, Bruce Power's cumulative restart
costs for the two Bruce A units were approximately $720 million. Bruce Power
incurred approximately $300 million on the two
M-23
unit restart program for the period February 14, 2003 to December 31, 2003. TCPL
did not provide any funding to Bruce Power subsequent to the acquisition of the
company's ownership interest in February 2003.
Bruce Power spent approximately $147 million on capital expenditures at Bruce B
for the period February 14, 2003 to December 31, 2003, the majority of which was
for safety systems and power uprate programs.
Equity income from Bruce Power is directly impacted by fluctuations in wholesale
spot market prices for electricity as well as overall plant availability, which
in turn, is impacted by scheduled and unscheduled maintenance. To reduce its
exposure to spot market prices, Bruce Power has entered into fixed price sales
contracts for approximately 1,560 MW of output for 2004. The average
availability in 2004 for the six Bruce units is expected to be approximately 80
per cent compared to 85 per cent for the year ended December 31, 2003. This
decrease reflects planned maintenance outages and a test of the Bruce B vacuum
building expected in the fall, which will require all four Bruce B units to be
taken offline for approximately one month. Capital expenditures by Bruce Power
in 2004 are expected to total about $400 million, including approximately $120
million for sustaining capital. TCPL does not expect to provide any funding to
Bruce Power in 2004.
Bruce Power contributed $99 million of pre-tax equity income in 2003. TCPL's
interest in Bruce Power's pre-tax income for 2003 was $65 million. The
additional $34 million of income consisted primarily of the amortization of
purchase price allocations as explained in Note 6 to the December 31, 2003
Consolidated Financial Statements as well as $12 million of capitalized
interest. Bruce Power's average realized price in 2003 from a combination of
contract and spot sales was approximately $48/MWh. Approximately 65 per cent of
Bruce Power's output was sold under longer term contracts in 2003 with the
remainder being sold into Ontario's wholesale spot market.
BRUCE POWER RESULTS-AT-A-GLANCE
YEAR ENDED DECEMBER 31 (millions of dollars)
BRUCE POWER (100 per cent basis) 2003
------------
Revenues 1,208
Operating expenses (853)
------------
Operating income 355
Financial charges (69)
------------
Income before income taxes 286
------------
------------
TCPL's interest in Bruce Power income
before income taxes(1) 65
Adjustments(2) 34
------------
TCPL's income from Bruce Power
before income taxes 99
--------------------------------------------------------
--------------------------------------------------------
(1) TCPL acquired its interest in Bruce Power on February 14, 2003. Bruce
Power's 100 per cent income before income taxes from February 14 to
December 31, 2003 was $205 million.
(2) See Note 6 to the December 31, 2003 Consolidated Financial Statements for
an explanation of the purchase price amortizations.
POWER LP INVESTMENT
Power LP investment includes the earnings generated from TCPL's 35.6 per cent
investment in TCPL Power, L.P., Canada's largest publicly-held, power-based
income fund. Power LP owns six power plants in Canada and one in the U.S. that
are fuelled by natural gas, waste heat, waste wood or a combination of these.
TCPL acts as manager for Power LP. In this capacity, TCPL manages the operations
and maintenance requirements of Power LP, the fuel supply and associated price
exposure and, when market conditions warrant, TCPL enhances the overall
operating profits of Power LP (i.e. by curtailing certain plants during off-peak
hours and selling the displaced natural gas at attractive market prices),
resulting in increased overall net earnings for Power LP and TCPL.
M-24
Operating and other income in 2003 from TCPL's investment in Power LP remained
consistent with 2002. At December 31, 2003, Power LP units closed at $36.30 on
the Toronto Stock Exchange and TCPL owned approximately 14.0 million units.
POWER VOLUMES AND AVAILABILITY
Volumes have increased 39 per cent to 28,010 GWh in 2003 compared to 20,111 GWh
in 2002 primarily due to the acquisitions of the interest in Bruce Power and
ManChief. Volumes for Eastern Operations increased as a result of growth in the
retail business which is focused on sales to large commercial and industrial
customers. Volumes for Power LP decreased due to curtailments of off-peak
production as a result of higher market prices for natural gas. This curtailment
activity has resulted in lower power output from the Ontario plants compared to
last year; however, overall financial contribution from these plants was higher.
Average plant availability, excluding Bruce Power, was 94 per cent in 2003
compared to 96 per cent in 2002. This slight decrease resulted primarily from
scheduled maintenance at some of the plants in Western Operations. Including
Bruce Power, average plant availability decreased to 90 per cent for 2003 as a
result of scheduled maintenance on two Bruce Power B units.
POWER SALES VOLUMES (GWh)
2003 2002 2001
---------------------------------------------
Western operations(1) 12,296 12,065 8,415
Eastern operations 6,906 5,630 4,216
Bruce Power investment(2) 6,655 n/a n/a
Power LP investment 2,153 2,416 2,358
---------------------------------------------
Total 28,010 20,111 14,989
-----------------------------------------------------------------------------------
-----------------------------------------------------------------------------------
(1) Sales volumes include TCPL's share of the Sundance B PPA (50 per cent).
(2) Sales volumes reflect TCPL's 31.6 per cent share of Bruce Power output for
the period February 14, 2003 to December 31, 2003.
WEIGHTED AVERAGE PLANT AVAILABILITY(1)
2003 2002 2001
---------------------------------------------
Western operations 93% 99% 96%
Eastern operations 94% 95% 96%
Bruce Power investment(2) 83% n/a n/a
Power LP investment 96% 94% 97%
All plants 90% 96% 96%
-----------------------------------------------------------------------------------
-----------------------------------------------------------------------------------
(1) Plant availability represents the percentage of time in the year that the
plant is available to generate power, whether actually running or not and
is reduced by planned and unplanned outages.
(2) TCPL's availability reflects the period February 14, 2003 to December 31,
2003.
POWER - STRATEGY AND OUTLOOK
STRATEGY TCPL is committed to growing the Power segment through the pursuit of
quality acquisitions, greenfield development projects and expansion of existing
businesses. Power's growth strategy is to:
o focus on low-cost base load generation and/or assets underpinned by strong
contractual arrangements;
o focus on markets where it has a competitive advantage;
o use marketing and trading activities to create stable and predictable cash
flows and optimize asset value; and
o apply business models that benefit from and support TCPL's strong balance
sheet.
M-25
OUTLOOK TCPL's Power segment has significant opportunities for growth. Growth
will take place through quality acquisitions, niche development opportunities
and optimization of the company's power portfolio by focusing on low-risk
opportunities in known markets.
Excluding the impact of the settlement with a former counterparty in 2003 and
potential variability in Bruce Power's earnings caused by changes in prices
realized and plant availability, the net earnings outlook for the Power business
in 2004 is expected to be similar to 2003. Earnings opportunities elsewhere in
the business may be affected by factors such as fluctuating market prices for
power and gas, regulatory changes, currency movements, weather, plant
availability and overall stability of the power industry. Please see the
following section "Power - Business Risks" for a complete discussion of these
factors.
TCPL's Power segment is in a strong position to capitalize on opportunities
resulting from industry changes because of its technical expertise and business
models that have proven successful to date. TCPL's growth will continue to focus
on diversifying the asset portfolio by adding plants of varying fuel sources
which are on the low end of the regional dispatch cost curve and/or are
underpinned with strong contractual arrangements.
POWER - BUSINESS RISKS
PLANT AVAILABILITY Maintaining plant availability is critical to the continued
success of the Power business and this risk is mitigated through a commitment to
an operational excellence model that provides low-cost, reliable operating
performance at each of the company's operated power plants. This same commitment
to operational excellence will be applied in 2004 and future years. However,
unexpected plant outages or the duration of outages may require purchases at
market prices to enable TCPL to meet the company's contractual power supply
obligations and/or increase maintenance costs.
FLUCTUATING MARKET PRICES TCPL generally operates in highly competitive,
deregulated markets. Volatility in electricity prices is caused by market
factors such as power plant fuel costs, fluctuating supply and market demand
which are greatly affected by weather, power consumption and plant availability.
TCPL manages these inherent market risks through:
o long-term purchase and sales contracts for both electricity and plant
fuels;
o control of generation output;
o matching physical plant contracts or PPA supply with customer demand;
o fee-for-service managed accounts rather than direct commodity exposure; and
o the company's overall risk management program with respect to general
market and counterparty risks.
The company's risk management practices are described further in the section on
Risk Management (page M-35). TCPL's largest exposure to sales price fluctuations
is on Bruce Power's uncontracted volumes. See the section "Power - Business
Risks Uncontracted Volumes".
REGULATORY As electricity markets evolve across North America, there is the
potential for regulatory bodies to implement new rules that could negatively
impact TCPL as a generator, marketer and builder of power plants. These may be
in the form of price caps, unfair cost allocations to generators or attempts to
control the wholesale market by encouraging new plant construction. TCPL
continues to monitor regulatory issues and reform as well as participate in and
lead discussions around these topics. TCPL operates in both regulated and
non-regulated power markets.
WEATHER Temperature and weather events may impact power and gas demand and
create price volatility, and may also impact the ability to transmit power to
markets. Seasonal changes in temperature also affect the efficiency and output
capability of natural gas-fired power plants. In addition, the total amount and
seasonality of water flows impacts the output and related earnings from
hydroelectric facilities.
UNCONTRACTED VOLUMES Although TCPL seeks to secure sales under medium- to
long-term contracts, TCPL retains an amount of unsold generation in the short
term in order to provide flexibility in managing the company's portfolio of
owned assets. Bruce Power has a significant amount of its uncontracted
volumes sold into the Ontario wholesale spot market. The sale of this power
in the open market is subject to market
M-26
price volatility which directly impacts income. Bruce Power has sold
approximately 1,560 MW of the expected power output for 2004. Of the remaining
Power segment's portfolio, through the use of PPAs and other marketing
arrangements, TCPL has sold approximately 90 per cent of the expected power
output in 2004 and 70 to 80 per cent for the years 2005 to 2007.
DESCRIPTION OF TCPL'S SIGNIFICANT POWER OPERATIONS
SUNDANCE A&B
The Sundance power plant in Alberta is the largest coal-fired electrical
generating facility in western Canada. Through the Alberta PPA auction in August
2000, TCPL acquired the Sundance A PPA, which increased the company's power
supply by 560 MW for a 17 year period commencing January 2001. In December 2001,
TCPL acquired 50 per cent of the 706 MW Sundance B PPA through a partnership
arrangement, which increased the company's power supply by 353 MW for
approximately 19 years commencing January 2002.
MANCHIEF
In November 2002, TCPL acquired the 300 MW simple-cycle ManChief facility near
Brush, Colorado. The entire capacity of the natural gas-fired ManChief plant is
sold under long-term tolling contracts that expire in 2012.
MACKAY RIVER
This 165 MW facility near Fort McMurray, Alberta was completed in fourth quarter
2003.
CARSELAND
Commercial operation of this 80 MW natural gas-fired cogeneration plant near
Carseland, Alberta commenced in January 2002.
BEAR CREEK
Commercial operation of this 80 MW natural gas-fired cogeneration plant near
Grande Prairie, Alberta commenced in March 2003.
REDWATER
Commercial operation of this 40 MW natural gas-fired cogeneration plant near
Redwater, Alberta commenced in January 2002.
CANCARB
The 27 MW Cancarb facility at Medicine Hat, Alberta is fuelled by waste heat
from TCPL's adjacent thermal carbon black facility.
OCEAN STATE
The OSP plant is a 560 MW natural gas-fired, combined-cycle facility in Rhode
Island.
CURTIS PALMER
The 60 MW Curtis Palmer facility near Corinth, New York is the company's only
hydroelectric facility. All output from this facility is sold through a
fixed-priced, long-term agreement.
BECANCOUR
The 550 MW Becancour natural gas-fired cogeneration power plant located near
Trois-Rivieres, Quebec is in the permitting phase and is expected to be
in-service in late 2006. The entire output will be supplied to Hydro-Quebec
Distribution under a 20-year power purchase contract. Steam will also be
supplied to businesses located nearby.
GRANDVIEW
The 90 MW Grandview natural gas-fired cogeneration power plant located in Saint
John, New Brunswick is under construction and is expected to be in-service in
late 2004. Under a 20-year tolling arrangement, 100 per cent of the plant's heat
and electricity output will be sold to Irving.
M-27
BRUCE POWER
In February 2003, TCPL acquired a 31.6 per cent equity interest in Bruce Power,
the operator and lessee of the Bruce nuclear power facility located near Lake
Huron, Ontario. This investment indirectly increased TCPL's nominal generating
capacity by 1,000 MW, with an additional 474 MW restarted in late 2003 and early
2004.
WILLIAMS LAKE
Power LP owns a 66 MW wood waste-fired power plant at Williams Lake, B.C.
CASTLETON
Castleton is a 64 MW combined-cycle plant located at Castleton-on-Hudson, New
York and is owned by Power LP.
NIPIGON, KAPUSKASING, TUNIS AND NORTH BAY
These efficient, enhanced combined-cycle facilities are fuelled by a combination
of natural gas and waste heat exhaust from adjacent compressor stations on the
Canadian Mainline and are owned by Power LP.
CALSTOCK
Calstock, a 35 MW plant, is fuelled by a combination of wood waste and waste
heat exhaust from the adjacent Canadian Mainline compressor station and is owned
by Power LP.
CORPORATE
HIGHLIGHTS
LOWER NET EXPENSES Net expenses in 2003 decreased $11 million or 21 per cent
from 2002.
CORPORATE RESULTS-AT-A-GLANCE
YEAR ENDED DECEMBER 31 (millions of dollars)
2003 2002 2001
--------------------------------------
Indirect financial and preferred equity charges 64 64 62
Interest income and other (23) (12) 5
--------------------------------------
Net expenses, after tax 41 52 67
-----------------------------------------------------------------------------------------------
-----------------------------------------------------------------------------------------------
The Corporate segment reflects net expenses not allocated to specific business
segments, including:
o INDIRECT FINANCIAL AND PREFERRED EQUITY CHARGES Direct financial charges
are reported in their respective business segments; these charges are
primarily associated with the debt and preferred securities related to the
company's Wholly-Owned Pipelines. Indirect financial charges primarily
reside in the Corporate segment. These costs are directly impacted by the
amount of debt TCPL maintains and the degree to which TCPL is impacted by
fluctuations in interest rates.
o INTEREST INCOME AND OTHER Interest income is earned on invested cash
balances. Gains and losses on foreign exchange are included in interest
income and other.
Net expenses, after tax, in the Corporate segment were $41 million in 2003
compared to $52 million in 2002 and $67 million in 2001. The decrease in 2003
from 2002 is primarily due to the positive impacts of a weaker U.S. dollar
compared to the prior year. These positive impacts substantially offset the
negative impacts of a weaker U.S. dollar reflected in other segments. The
decrease in net expenses in 2002 from 2001 is primarily due to an increase in
interest income and other and the positive impact of lower interest rates offset
by increased Corporate financial charges resulting from the Fair Return
decision.
M-28
The performance of the Canadian dollar relative to the U.S. dollar would either
positively or negatively impact the Corporate segment's results. In 2004, the
performance of the Canadian dollar is not expected to have a significant impact
on TCPL's consolidated financial results since the impact in the Corporate
segment is anticipated to largely offset impacts in the other business segments.
LIQUIDITY AND CAPITAL RESOURCES
HIGHLIGHTS
SUSTAINED GROWTH Total capital expenditures, including acquisitions and assumed
debt, have exceeded $3 billion over the past three years.
DEBT REDUCTION TCPL's repayment of long-term debt, net of new debt issued, and
redemption of debentures and preferred securities has exceeded $1.6 billion over
the past three years.
FUNDS GENERATED FROM OPERATIONS Funds generated from continuing operations were
$1.8 billion for the year ended December 31, 2003 compared to $1.8 billion and
$1.6 billion for 2002 and 2001, respectively. The Gas Transmission business was
the primary source of funds generated from operations for each of the three
years. As a result of rapid growth in the Power business in the last few years,
the Power segment's funds generated from operations increased in 2003 compared
to the two prior years.
The company also reduced long-term debt, junior subordinated debentures and
preferred securities in each of the past three years. TCPL's ability to generate
adequate amounts of cash in the short term and the long term when needed, and to
maintain financial capacity and flexibility to provide for planned growth,
remained as strong at December 31, 2003 as compared to the past few years.
INVESTING ACTIVITIES Capital expenditures, excluding acquisitions and assumed
debt, totalled $391 million in 2003 compared to $599 million and $492 million in
2002 and 2001, respectively. Expenditures in all three years related primarily
to maintenance and capacity capital in TCPL's Gas Transmission business and
construction of new power plants in Canada.
During 2003, TCPL acquired a 31.6 per cent interest in Bruce Power for $409
million, the remaining interests in Foothills previously not held by the company
for $105 million, excluding assumed debt of $154 million, and increased its
interest in Portland, by way of two separate acquisitions, to 61.7 per cent from
33.3 per cent for US$51 million, excluding assumed debt of US$78 million.
During 2002, TCPL acquired the ManChief power plant for $209 million and a
general partnership interest in Northern Border Partners, L.P. $19 million.
During 2001, TCPL acquired the Curtis Palmer Hydroelectric Company L.P. for $438
million and, through a partnership, acquired 50 per cent of the rights and
obligations of the 706 MW Sundance B PPA for $110 million.
TCPL's 2001 investing activities also include proceeds of $1.2 billion from the
sale of non-core assets under the company's divestiture plan.
FINANCING ACTIVITIES In 2003, TCPL used a portion of its cash resources to repay
long-term debt of $744 million, reduce notes payable by $62 million and redeem
all of its outstanding US$160 million, 8.75 per cent Junior Subordinated
Debentures.
In 2003, the company issued $450 million of ten year notes bearing interest at
5.65 per cent and US$350 million of ten year notes bearing interest at 4.00 per
cent. The company repaid debt maturities of $486 million and reduced notes
payable by $46 million in 2002 and repaid debt maturities of $793 million and
redeemed preferred securities of $318 million in 2001. In 2001, TCPL increased
notes payable by $186 million.
Dividends and preferred securities charges amounting to $588 million were paid
in 2003 compared to $546 million and $517 million in 2002 and 2001,
respectively.
M-29
In January 2004, TCPL's Board of Directors declared a dividend for the quarter
ending March 31, 2004 in an aggregate amount equal to the aggregate quarterly
dividend to be paid on April 30, 2004 by TransCanada Corporation on the issued
and outstanding common shares as at the close of business on March 31, 2004.
Net cash used in financing activities includes TCPL's proportionate share of the
net reduction in non-recourse debt of joint ventures amounting to $11 million in
2003 compared to $36 million and $109 million in 2002 and 2001, respectively.
CREDIT ACTIVITIES In 2002, TCPL filed shelf prospectuses, subsequently amended,
that qualify for issuance $2 billion of common shares, preferred shares and/or
debt securities including medium-term notes in Canada and US$1 billion of debt
securities in the U.S., respectively. During 2003, $450 million of medium-term
notes and US$350 million of senior unsecured notes were issued under these
programs.
At December 31, 2003, total credit facilities of $2.2 billion were available to
support the company's commercial paper program and for general corporate
purposes. Of this total, $1.9 billion represents committed credit facilities of
which $1.5 billion represents a syndicated facility established in December
2002. This facility is comprised of a $1.0 billion tranche with a three year
term and a $500 million tranche with a 364 day term with a two year term out
option. Both tranches are extendible on an annual basis and are revolving unless
during a term out period. Both tranches were extended in December 2003, the $1.0
billion tranche to December 2006 and the $500 million tranche to December 2004.
The remaining committed facilities are non-extendible, of which $60 million
expires in June 2004 and $320 million expires in June 2005.
At December 31, 2003, TCPL had used approximately $217 million of its total
lines of credit for letters of credit and to support ongoing commercial
arrangements. If drawn, interest on the lines of credit would be charged at
prime rates of Canadian chartered and U.S. banks or at other negotiated
financial bases.
Credit ratings on TCPL'S senior unsecured debt assigned by Dominion Bond Rating
Service Limited (DBRS), Moody's Investors Service (Moody's) and Standard &
Poor's are currently A, A2 and A-, respectively. DBRS and Moody's both maintain
a `stable' outlook on their ratings and Standard & Poor's maintains a `negative'
outlook on its rating.
CONTRACTUAL OBLIGATIONS
OBLIGATIONS AND COMMITMENTS Total long-term debt at December 31, 2003 was $10.0
billion compared to $9.3 billion at December 31, 2002. TCPL's share of total
non-recourse debt of joint ventures at December 31, 2003 was $0.8 billion
compared to $1.3 billion at the prior year-end. Total notes payable, including
those of joint ventures, at December 31, 2003 were $367 million compared to $297
million at December 31, 2002. The debt and notes payable of joint ventures are
non-recourse to TCPL. The security provided by each joint venture is limited to
the rights and assets of that joint venture and does not extend to the rights
and assets of TCPL, except to the extent of TCPL's investment.
M-30
At December 31, 2003, principal repayments related to long-term debt and the
company's proportionate share of the non-recourse debt of joint ventures are as
follows.
PRINCIPAL REPAYMENTS
YEAR ENDED DECEMBER 31 (millions of dollars)
2004 2005 2006 2007 2008 2009+
-----------------------------------------------------------
Long-term debt 550 702 399 611 542 7,211
Non-recourse debt of joint ventures 19 69 55 19 19 599
-----------------------------------------------------------
Total principal repayments 569 771 454 630 561 7,810
-----------------------------------------------------------------------------------------------------------
-----------------------------------------------------------------------------------------------------------
At December 31, 2003, future annual payments, net of sub-lease receipts, under
operating leases for various premises are approximately as follows.
OPERATING LEASE PAYMENTS
YEAR ENDED DECEMBER 31 (millions of dollars)
2004 2005 2006 2007 2008 2009+
----------------------------------------------------------
Minimum lease payments 25 25 25 24 24 48
Amounts recoverable under sub-leases (7) (7) (7) (7) (7) (18)
----------------------------------------------------------
Net payments 18 18 18 17 17 30
---------------------------------------------------------------------------------------------------------
---------------------------------------------------------------------------------------------------------
At December 31, 2003, the company's future purchase obligations are
approximately as follows.
PURCHASE OBLIGATIONS(1)
YEAR ENDED DECEMBER 31 (millions of dollars)
2004 2005 2006 2007 2008 2009+
-----------------------------------------------------------
GAS TRANSMISSION
Transportation by others(2) 167 153 84 82 74 46
Other 19 15 15 12 9 2
POWER
Commodity purchases(3) 465 280 255 260 267 2,937
Capital expenditures(4) 274 241 96 - - -
Other(5) 99 103 107 95 90 327
CORPORATE
Information technology and other 12 - - - - -
-----------------------------------------------------------
Total purchase obligations 1,036 792 557 449 440 3,312
-----------------------------------------------------------------------------------------------------------
-----------------------------------------------------------------------------------------------------------
(1) The amounts in this table exclude funding contributions to the company's
pension plans and TCPL's one-third share of project definition phase costs
in the Mackenzie Gas Pipeline Project.
(2) Rates are based on known 2004 levels. Beyond 2004, demand rates are subject
to change. The contractual obligations in the table are based on demand
volumes only and exclude commodity charges incurred when volumes flow.
(3) Commodity purchases include fixed and variable components. The variable
components are estimates and are subject to variability in plant
production, market prices and regulatory tariffs.
(4) Amounts are estimates and are subject to variability based on timing of
construction and project enhancements.
(5) Includes estimates of certain amounts which are subject to change depending
on plant-fired hours, the consumer price index, actual plant maintenance
costs, plant salaries as well as changes in regulated rates for
transportation.
TCPL expects to make funding contributions to the company's pension plans in the
amount of approximately $80 million during 2004. The expected decrease in
funding in 2004 from the $110 million in 2003 is due to one-time plan design
changes and investment performance above long-term expectations in 2003
partially offset by continued reductions in discount rates used to calculate
plan liabilities.
At December 31, 2003, TCPL held a 35.6 per cent interest in Power LP which is a
publicly-held limited partnership. On June 30, 2017, the partnership will redeem
all units outstanding, not held directly or indirectly by TCPL, at their then
fair market value, being the average of the fair market values assigned thereto
by independent valuators, plus all declared and unpaid distributions of
distributable cash thereon
M-31
(the Redemption Price). TCPL is required to fund the Redemption Price in
accordance with the terms of the Power LP Partnership Agreement.
TCPL has established a $50 million operating line of credit to Power LP,
available on a revolving basis. As at December 31, 2003, the amount borrowed
against this line of credit was $26 million compared to $37 million at December
31, 2002.
At December 31, 2003, TCPL held a 33.4 per cent interest in TC PipeLines, LP
which is a publicly-held limited partnership. On May 28, 2003, TC PipeLines, LP
renewed its US$40 million unsecured two-year revolving credit facility (TCPL
Credit Facility) with a subsidiary of TCPL. At December 31, 2003 and 2002, the
partnership had no amount outstanding under the TCPL Credit Facility.
On June 18, 2003, the Mackenzie Delta gas producers, the APG and TCPL reached an
agreement which governs TCPL's role in the Mackenzie Gas Pipeline Project. The
Project would result in a natural gas pipeline being constructed from Inuvik,
Northwest Territories to the northern border of Alberta, where it would then
connect with the Alberta System. Under the agreement, TCPL has agreed to finance
the APG for its one-third share of project definition phase costs. This share is
estimated to be approximately $90 million over three years. In the year ended
December 31, 2003, TCPL funded $34 million of this loan. The ability to recover
this investment is contingent upon the outcome of the project.
TCPL and its affiliates have long-term natural gas transportation and natural
gas purchase arrangements as well as other purchase obligations, all of which
are or were transacted at market prices and in the normal course of business.
GUARANTEES TCPL had no outstanding guarantees related to the long-term debt of
unrelated third parties at December 31, 2003.
Upon acquisition of Bruce Power, the company, together with Cameco and BPC
Generation Infrastructure Trust, guaranteed on a several pro-rata basis certain
contingent financial obligations of Bruce Power related to operator licenses,
the lease agreement, power sales agreements and contractor services. TCPL's
share of the net exposure under these guarantees at December 31, 2003 was
estimated to be approximately $215 million. The terms of the guarantees range
from 2004 to 2018. The current carrying amount of the liability related to these
guarantees is nil and the fair value is approximately $4 million.
TCPL has guaranteed the equity undertaking of a subsidiary which supports the
payment, under certain conditions, of principal and interest on the US$195
million public debt obligations of TransGas. The company has a 46.5 per cent
interest in TransGas. Under the terms of the agreement, the company severally
with another major multinational company may be required to fund more than their
proportionate share of debt obligations of TransGas in the event that the
minority shareholders fail to contribute. Any payments made by TCPL under this
agreement convert into share capital of TransGas. The potential exposure is
contingent on the impact of any change of law on TransGas' ability to service
the debt. From the issuance of the debt in 1995 to date, there has been no
change in applicable law and thus no exposure to TCPL. The debt matures in 2010.
The company has made no provision related to this guarantee.
CONTINGENCIES The Canadian Alliance of Pipeline Landowners' Associations and two
individual landowners commenced an action under Ontario's Class Proceedings Act,
1992, against TCPL and Enbridge Inc. for damages alleged in 2002 to arise from
the creation of a control zone within 30 metres of the pipeline pursuant to
Section 112 of the NEB Act. The company believes the claim is without merit and
will vigorously defend the action. The company has made no provision for any
potential liability. A liability, if any, would be dealt with through the
regulatory process.
The company and its subsidiaries are subject to various other legal proceedings
and actions arising in the normal course of business. While the final outcome of
such legal proceedings and actions cannot be predicted with certainty, it is the
opinion of management that the resolution of such proceedings and actions will
not have a material impact on the company's consolidated financial position or
results of operations.
M-32
FINANCIAL AND OTHER INSTRUMENTS
The company issues short-term and long-term debt including amounts in foreign
currencies, purchases and sells energy commodities and invests in foreign
operations. These activities result in exposures to interest rates, energy
commodity prices and foreign currency exchange rates. The company utilizes
derivative and other financial instruments to manage its exposure to the risks
that result from these activities. A derivative must be designated and effective
to be accounted for as a hedge. Gains or losses relating to derivatives that are
hedges are deferred and recognized in the same period and in the same financial
statement category as the gains or losses on the corresponding hedged
transactions. The recognition of gains and losses on derivatives used as hedges
for the Alberta System, Canadian Mainline and the Foothills System exposures is
determined through the regulatory process.
The carrying amounts of derivatives, which hedge the price risk of foreign
currency denominated assets and liabilities of self-sustaining foreign
operations are recorded on the balance sheet at their fair value. Gains and
losses on the derivatives, realized and unrealized, are included in the foreign
exchange adjustment account in Shareholders' Equity as a reduction of the
corresponding gains and losses on the translation of the assets and liabilities
of the foreign subsidiaries. Carrying amounts for interest rate swaps represent
the net accrued interest from the last payment date to the reporting date.
Foreign currency transactions hedged by foreign exchange contracts are recorded
at the contract rate. Power, natural gas and heat rate derivatives are recorded
on the balance sheet at their fair value.
The fair values of foreign exchange and interest rate derivatives have been
estimated using year-end market rates. These fair values approximate the amount
that the company would receive or pay if the instruments were closed out at
these dates. The fair values of power, natural gas and heat rate derivatives
have been calculated at year-end using estimated forward prices for the relevant
period.
Notional principal amounts are not recorded in the financial statements because
these amounts are not exchanged by the company and its counterparties and are
not a measure of the company's exposure. Notional amounts are used only as the
basis for calculating payments for certain derivatives.
FOREIGN INVESTMENTS
At December 31, 2003 and 2002, the company had foreign currency denominated
assets and liabilities which created an exposure to changes in exchange rates.
The company uses foreign currency derivatives to hedge this net exposure on an
after-tax basis. The foreign currency derivatives have a floating interest rate
exposure which the company partially hedges by entering into interest rate swaps
and forward rate agreements. The fair values shown in the table below for
foreign exchange risk are offset by translation gains or losses on the net
assets and are recorded in the foreign exchange adjustment account in
Shareholders' Equity.
ASSET/(LIABILITY) AT DECEMBER 31 (MILLIONS OF DOLLARS) 2003 2002
---------------------------------------------------------------------------------------------------------
CARRYING FAIR Carrying Fair
AMOUNT VALUE Amount Value
-----------------------------------------------
FOREIGN EXCHANGE
Cross-currency swaps
U.S. dollars 65 65 (8) (8)
Forward foreign exchange contracts
U.S. dollars 2 3 (4) (4)
At December 31, 2003, the notional principal amounts of cross-currency swaps
were US$250 million (2002 - US$350 million), principal amounts of forward
foreign exchange contracts were US$125 million (2002 - US$225 million). In
addition, the company has associated interest rate swaps with notional principal
amounts of $311 million (2002 - $309 million) and US$200 million (2002 - US$350
million). The fair value of these interest rate swaps was $1 million (2002 -
$(4) million).
M-33
RECONCILIATION OF FOREIGN EXCHANGE ADJUSTMENT
DECEMBER 31 (MILLIONS OF DOLLARS) 2003 2002
---------------------------------------------------------------------------------------------------
Balance at beginning of year 14 13
Translation (losses)/gains on foreign currency denominated net assets (136) 3
Foreign exchange gains/(losses) on derivatives, and other 82 (2)
-------------------
(40) 14
---------------------------------------------------------------------------------------------------
---------------------------------------------------------------------------------------------------
FOREIGN EXCHANGE AND INTEREST RATE MANAGEMENT ACTIVITY
The company manages the foreign exchange risk of U.S. dollar debt, U.S. dollar
expenses and the interest rate exposures of the Alberta System, the Canadian
Mainline and the Foothills System through the use of foreign currency and
interest rate derivatives. Certain of the realized gains and losses on these
derivatives are shared with shippers on predetermined terms.
ASSET/(LIABILITY) AT DECEMBER 31 (MILLIONS OF DOLLARS) 2003 2002
--------------------------------------------------------------------------------- -----------------------
CARRYING FAIR Carrying Fair
AMOUNT VALUE Amount Value
-----------------------------------------------
FOREIGN EXCHANGE
Cross-currency swaps (26) (26) 56 56
INTEREST RATE
Interest rate swaps
Canadian dollars 2 15 4 56
U.S. dollars - 8 (1) 4
At December 31, 2003, the notional principal amounts of cross-currency swaps
were US$282 million (2002 - US$282 million) and the notional principal amounts
for interest rate swaps were $964 million (2002 - $874 million) and US$100
million (2002 - US$175 million).
The company manages the foreign exchange risk and interest rate exposure of its
other U.S. dollar debt through the use of foreign currency and interest rate
derivatives. The fair values of the interest rate derivatives are shown in the
table below.
ASSET/(LIABILITY) AT DECEMBER 31 (MILLIONS OF DOLLARS) 2003 2002
---------------------------------------------------------------------------------------------------------
CARRYING FAIR Carrying Fair
AMOUNT VALUE Amount Value
----------------------------------------------
INTEREST RATE
Interest rate swaps
U.S. dollars 2 37 2 55
At December 31, 2003, the notional principal amount for interest rate swaps was
US$500 million (2002 - US$400 million).
ENERGY PRICE RISK MANAGEMENT
The company executes power, natural gas and heat rate derivatives for overall
management of its asset portfolio. The company's portfolio of power, natural gas
and heat rate derivatives is primarily comprised of swap, option and forward
contracts, with fixed and floating price commitments. Heat rate contracts are
contracts for the sale or purchase of power that are priced based on a natural
gas index. The fair values and notional volumes of the swap, option, forward and
heat rate contracts are shown in the tables below.
M-34
ASSET/(LIABILITY) AT DECEMBER 31 (MILLIONS OF DOLLARS) 2003 2002
---------------------------------------------------------------------------------------------------------
CARRYING FAIR Carrying Fair
AMOUNT VALUE Amount Value
----------------------------------------------
Power - swaps (5) (5) (36) (36)
Gas - swaps, forwards and options (35) (35) (28) (28)
Heat rate contracts 61 61 74 74
NOTIONAL VOLUMES AT DECEMBER 31, 2003 POWER (GWH)(1) GAS (BCF)(1)
---------------------------------------------------------------------------------------------------------
PURCHASES SALES PURCHASES SALES
------------------------------------------------------
Power - swaps 1,390 4,864 - -
Gas - swaps, forwards and options - - 86.1 88.2
Heat rate contracts 2,331 735 1.0 20.3
NOTIONAL VOLUMES AT DECEMBER 31, 2002 Power (GWh) Gas (Bcf)
---------------------------------------------------------------------------------------------------------
Purchases Sales Purchases Sales
------------------------------------------------------
Power - swaps 467 5,138 - -
Gas - swaps, forwards and options - - 86.3 88.6
Heat rate contracts 2,848 - - 24.8
(1) Gigawatt hours (GWh); billion cubic feet (Bcf).
RISK MANAGEMENT
RISK MANAGEMENT OVERVIEW TCPL and its subsidiaries are exposed to market,
financial and counterparty risks in the normal course of their business
activities. The risk management function assists in managing these various
business activities and the risks associated with these activities. A strong
commitment to a risk management culture by management supports this function.
TCPL's primary risk management objective is to protect earnings and cash flow
and ultimately, shareholder value.
The risk management function is guided by the following principles that are
applied to all businesses and risk types:
o BOARD OVERSIGHT Risk strategies, policies and limits are subject to review
and approval by TCPL's Board of Directors.
o INDEPENDENT REVIEW Risk-taking activities are subject to independent
review, separate from the business lines that initiate the activity.
o ASSESSMENT Processes are in place to ensure that risks are properly
assessed at the transaction and counterparty levels.
o REVIEW AND REPORTING Market positions and exposures, and the
creditworthiness of counterparties are subject to ongoing review and
reporting to executive management.
o ACCOUNTABILITY Business lines are accountable for all risks and the related
returns for their particular businesses.
o AUDIT REVIEW Individual risks are subject to internal audit review, with
independent reporting to the Audit Committee of TCPL's Board of Directors.
The processes within TCPL's risk management function are designed to ensure that
risks are properly identified, quantified, reported and managed. Risk management
strategies, policies and limits are designed to ensure TCPL's risk taking is
consistent with the company's business objectives and risk tolerance. Risks are
managed within limits ultimately established by the company's Board of Directors
and implemented by senior management, monitored by risk management personnel and
audited by internal audit personnel.
M-35
TCPL manages market risk exposures in accordance with the company's corporate
market risk policy and position limits. The company's primary market risks
result from volatility in commodity prices, interest rates and foreign currency
exchange rates.
Senior management reviews these exposures and reports to the Audit Committee of
TCPL's Board of Directors regularly.
MARKET RISK MANAGEMENT In order to manage market risk exposures created by fixed
and variable pricing arrangements at different pricing indices and delivery
points, the company enters into offsetting physical positions and derivative
financial instruments. Market risks are quantified using value-at-risk
methodology and are reviewed weekly by senior management.
FINANCIAL RISK MANAGEMENT TCPL monitors the financial market risk exposures
relating to the company's investments in foreign currency denominated net
assets, regulated and non-regulated long-term debt portfolios and foreign
currency exposure on transactions. The market risk exposures created by these
business activities are managed by establishing offsetting positions or through
the use of derivative financial instruments.
COUNTERPARTY RISK MANAGEMENT Counterparty risk is the financial loss that the
company would experience if the counterparty failed to meet its obligations in
accordance with the terms and conditions of its contracts with the company.
Counterparty risk is mitigated by conducting financial and other assessments to
establish a counterparty's creditworthiness, setting exposure limits and
monitoring exposures against these limits, and, where warranted, obtaining
financial assurances.
The company's counterparty risk management practices and positions are further
described under Credit Risk in Note 12 to the Consolidated Financial Statements.
RISKS AND RISK MANAGEMENT RELATED TO THE KYOTO PROTOCOL The Canadian government
continues to develop climate change policy that will help it meet its commitment
under the Kyoto Protocol. While broad policy mechanisms such as the Domestic
Emissions Trading Program for Large Final Emitters have been identified, program
details are still undefined. Once these details are finalized, TCPL will be
better able to assess the implications on the company.
Over the past several years, TCPL's focus has been, and continues to be, on
developing practical options for reducing greenhouse gas (GHG) emissions from
the company's facilities. This is being achieved through technical and
operational improvements, driven in large part by increased fuel and system
efficiencies and the elimination of methane emissions. TCPL's current position
is that operating initiatives that reduce GHG at the source are more appropriate
than other mechanisms.
DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROLS Pursuant to the
Sarbanes-Oxley Act as adopted by the U.S. Securities and Exchange Commission,
TCPL's management evaluates the effectiveness of the design and operation of the
company's disclosure controls and procedures (disclosure controls). This
evaluation is done under the supervision of, and with the participation of, the
President and Chief Executive Officer and the Chief Financial Officer.
As of the end of the period covered by the annual report on TCPL's Form 40-F,
TCPL's management evaluated the effectiveness of its disclosure controls. Based
on that evaluation, the President and Chief Executive Officer and the Chief
Financial Officer have concluded that TCPL's disclosure controls are effective
in ensuring that material information relating to TCPL is made known to
management on a timely basis, and is included in the annual report on TCPL's
Form 40-F.
To the best of these officers' knowledge and belief, there have been no
significant changes in internal controls or in other factors that could
significantly affect internal controls subsequent to the date on which such
evaluation was completed in connection with the annual report on TCPL's Form
40-F.
M-36
CRITICAL ACCOUNTING POLICY
The company accounts for the impacts of rate regulation in accordance with
generally accepted accounting principles (GAAP) as outlined in Note 1 to the
Consolidated Financial Statements. Three criteria must be met to use these
accounting principles: the rates for regulated services or activities must be
subject to approval by a regulator; the regulated rates must be designed to
recover the cost of providing the services or products; and it must be
reasonable to assume that rates set at levels to recover the cost can be charged
to and will be collected from customers in view of the demand for services or
products and the level of direct and indirect competition. The company's
management believes that all three of these criteria have been met. The most
significant impact from the use of these accounting principles is that in order
to achieve a proper matching of revenues and expenses, the timing of recognition
of certain expenses and revenues may differ from that otherwise expected under
GAAP. The two most significant examples of this relate to the recording of
income taxes on the taxes payable basis and the deferral of foreign exchange
losses as outlined in the Consolidated Financial Statements' Note 13 and Note 7,
respectively.
CRITICAL ACCOUNTING ESTIMATES
Since a determination of many assets, liabilities, revenues and expenses is
dependent upon future events, the preparation of the company's Consolidated
Financial Statements requires the use of estimates and assumptions which have
been made using careful judgment. TCPL's critical accounting estimates are:
DEFERRED AFTER-TAX GAINS AND REMAINING OBLIGATIONS RELATED TO THE GAS MARKETING
BUSINESS TCPL mitigated certain of its remaining exposures associated with the
contingent liabilities related to the divested Gas Marketing operations by
acquiring from a subsidiary of Mirant Corporation (Mirant) certain contracts
under which it still had exposure in 2003, and simultaneously hedging the market
price exposures of these contracts. To determine the exposure to these
contracts, the company uses estimates, including future market prices,
transportation volumes, transportation charges and income taxes. The company
remains contingently liable for certain residual obligations. This obligation is
further described in Discontinued Operations on page M-38.
DEPRECIATION EXPENSE TCPL's plant, property and equipment are depreciated on a
straight-line basis over their estimated useful lives. Depreciation expense for
the year ended December 31, 2003 was $914 million. Depreciation expense impacts
the Gas Transmission and Power segments of the company. In the Gas Transmission
business, depreciation rates are approved by the regulators and recoverable
based on the cost of providing the services or products. A change in the
estimation of the useful lives of the plant, property and equipment in the Gas
Transmission segment would therefore have no material impact on TCPL's net
income but would directly impact funds generated from operations.
ACCOUNTING CHANGES
HEDGING RELATIONSHIPS In November 2001, the Accounting Standards Board (AcSB) of
the Canadian Institute of Chartered Accountants (CICA) issued an Accounting
Guideline "Hedging Relationships" that specifies the circumstances in which
hedge accounting is appropriate, including the identification, documentation,
designation and effectiveness of hedges, and the discontinuance of hedge
accounting. The AcSB amended this guideline in June 2003 to clarify some aspects
and to add an appendix of implementation guidance. The rules under this
guideline are substantially similar to the corresponding requirements under
Statement of Financial Accounting Standards (SFAS) No. 133 which was adopted by
the company for U.S. GAAP purposes, effective January 1, 2001. This accounting
guideline will be effective for the company as of January 1, 2004 on a
prospective basis. TCPL does not expect the new Canadian requirement to have a
significant impact on the company's Consolidated Financial Statements.
DISPOSAL OF LONG-LIVED ASSETS AND DISCONTINUED OPERATIONS In November 2002, the
CICA issued a new Handbook Section "Disposal of Long-Lived Assets and
Discontinued Operations". This section establishes new standards for the
recognition, measurement, presentation and disclosure of the disposal of
long-lived assets. It also establishes standards for the presentation and
disclosure of discontinued operations, whether
M-37
or not they include long-lived assets. This section was effective for the
company on a prospective basis after May 1, 2003 and did not result in
restatement of income for prior periods.
IMPAIRMENT OF LONG-LIVED ASSETS In November 2002, the CICA issued a new Handbook
Section "Impairment of Long-Lived Assets". This section establishes new
standards for the recognition, measurement and disclosure of the impairment of
long-lived assets and establishes new write-down provisions. This section will
be effective for the company as of January 1, 2004 and is not expected to have a
significant impact on the company's Consolidated Financial Statements.
ASSET RETIREMENT OBLIGATIONS In January 2003, the CICA issued a new Handbook
Section "Asset Retirement Obligations". The new section focuses on the
recognition and measurement of liabilities for obligations associated with the
retirement of property, plant and equipment when those obligations result from
the acquisition, construction, development or normal operation of the assets.
The section requires that the fair value of a liability for an asset retirement
obligation be recognized in the period in which it is incurred if a reasonable
estimate of fair value can be made. The fair value is added to the carrying
amount of the associated asset. The liability is accreted at the end of each
period through charges to operating expenses. This standard is substantially
similar to the corresponding requirements under SFAS No. 143 which was adopted
by the company for U.S. GAAP purposes, effective January 1, 2003. This section
will be effective for TCPL as of January 1, 2004. The impact of this standard
has been outlined in Note 19 of the Consolidated Financial Statements.
CONSOLIDATION OF VARIABLE INTEREST ENTITIES In June 2003, the AcSB of the CICA
issued a new Accounting Guideline "Consolidation of Variable Interest Entities"
which requires enterprises to identify variable interest entities in which they
have an interest, determine whether they are the primary beneficiary of such
entities and, if so, to consolidate them. For TCPL, the guideline's disclosure
requirements are effective as of January 1, 2004 and the consolidation
requirements are effective as of January 1, 2005. Adopting the provisions of
this guideline is not expected to impact the company's Consolidated Financial
Statements.
GENERALLY ACCEPTED ACCOUNTING PRINCIPLES In July 2003, the CICA issued a new
Handbook Section "Generally Accepted Accounting Principles" which establishes
standards for financial reporting in accordance with GAAP. It defines primary
sources of GAAP and requires that an entity apply every relevant primary source.
This section will be effective for the company as of January 1, 2004 and will
require the recognition of additional regulated assets and liabilities but is
not expected to have a significant impact on the company's net income.
GENERAL STANDARDS OF FINANCIAL STATEMENT PRESENTATION In July 2003, the CICA
issued a new Handbook Section "General Standards of Financial Statement
Presentation" which clarifies what constitutes "fair presentation in accordance
with GAAP". This section will be effective for the company as of January 1, 2004
and is not expected to have an impact on the company's Consolidated Financial
Statements.
OTHER INFORMATION
Additional information relating to TCPL, including the company's Annual
Information Form, is posted on SEDAR at www.sedar.com under TransCanada
PipeLines Limited.
DISCONTINUED OPERATIONS
FINANCIAL REVIEW
TCPL's Board of Directors approved a plan to dispose of the company's
International, Canadian Midstream, and certain other businesses (December Plan)
and the disposal of the Gas Marketing business in December 1999 and July 2001,
respectively. The company's disposals under both plans were substantially
completed at December 31, 2001.
The company's investments in Gasoducto del Pacifico, INNERGY Holdings S.A. and
P.T. Paiton Energy Company approved for disposal under the December Plan will be
accounted for as part of continuing operations as of December 31, 2003 due to
the length of time it has taken the company to dispose of these assets. It is
the intention of the company to continue with its plan to dispose of these
investments.
M-38
In 2003, the company reviewed the provision for loss on discontinued operations
and the deferred gain, taking into consideration the impacts of Mirant filing
for bankruptcy protection and the mitigation of certain contingent liabilities
referred to below. As a result of this review, TCPL recognized in income in 2003
$50 million of the original approximately $100 million after-tax deferred gain.
Any further adjustments to the estimate of the net loss on disposal and the
deferred gain will be recognized as a gain or loss from discontinued operations
in the period that such changes are determined.
The company's net income/(loss) from discontinued operations in 2002 was nil as
the existing provision for loss on discontinued operations was reviewed by the
company's management and determined to be appropriate. The company recorded a
net loss from discontinued operations in 2001 of $67 million. This amount
includes a net loss of $90 million based on management's estimates of proceeds
and disposal costs and net earnings of $3 million prior to plan approval,
related to the Gas Marketing business. Also included in 2001 is a positive $20
million after-tax adjustment to the December Plan.
TCPL remains contingently liable pursuant to guarantees and obligations under
certain contracts that relate to the divested Gas Marketing business. In
accordance with the terms of these contracts and in the normal course of
business, the company expects the underlying volumes related to the contracts to
decrease over time. The contingent liability under these obligations is
contingent on certain future events, the occurrence and the amount of which is
not determinable. The purchasers of the Gas Marketing business have agreed to
indemnify TCPL in the event the company is called upon to perform under the
obligations.
M-39
SELECTED THREE YEAR CONSOLIDATED FINANCIAL DATA(1)
(MILLIONS OF DOLLARS EXCEPT PER SHARE AMOUNTS) 2003 2002 2001
---------------------------------------------------------------------------------------------------------
INCOME STATEMENT
Revenues 5,357 5,214 5,275
Net income from continuing operations 859 805 753
Net income 909 805 686
Results by segment
Gas Transmission 622 653 585
Power 220 146 168
Corporate (41) (52) (67)
Continuing operations 801 747 686
Discontinued operations 50 - (67)
Net income applicable to common shares 851 747 619
CASH FLOW STATEMENT
Funds generated from continuing operations 1,810 1,827 1,624
Capital expenditures and acquisitions
Continuing operations 961 814 1,025
Discontinued operations - 13 52
Total 961 827 1,077
Dividends and preferred securities charges 588 546 517
BALANCE SHEET
ASSETS
Plant, property and equipment
Gas Transmission 16,098 16,098 16,509
Power 1,303 1,334 1,110
Corporate 50 64 66
Total assets
Continuing operations 20,530 19,827 19,629
Discontinued operations 11 139 276
CAPITALIZATION
Long-term debt 9,465 8,815 9,347
Non-recourse debt of joint ventures 761 1,222 1,295
Preferred securities (liability component) 22 238 237
Preferred securities (equity component) 672 674 675
Preferred shares 389 389 389
Common shareholders' equity 6,044 5,747 5,426
U.S. GAAP INFORMATION
Net income/(loss)
Continuing operations 810 774 715
Discontinued operations 50 - (67)
Net income 860 774 648
Net income/(loss) per share
Continuing operations $1.68 $1.57 $1.46
Discontinued operations $0.11 - $(0.14)
Net income applicable to common shares per share - Basic $1.79 $1.57 $1.32
Net income applicable to common shares per share - Diluted $1.79 $1.56 $1.32
Common shareholders' equity 5,932 5,642 5,360
-----------------------------------------------------------------------------------------------------------
-----------------------------------------------------------------------------------------------------------
(1) The selected quarterly financial data has been prepared in accordance with
Canadian GAAP. Certain comparative figures have been reclassified to
conform with the current year's presentation. For a discussion on the
factors affecting the comparability of the financial data, including
discontinued operations, refer to Note 1 and Note 18 of TCPL's 2003 Audited
Consolidated Financial Statements.
M-40
2003 2002 2001
------------------------------------------------------------------------------- -------------------------
PER COMMON SHARE DATA (dollars)
Net Income - Basic
Continuing operations $1.66 $1.56 $1.44
Discontinued operations 0.11 - (0.14)
-------------------------------------
$1.77 $1.56 $1.30
-------------------------------------
Net income - Diluted $1.77 $1.55 $1.30
-------------------------------------
Dividends declared $1.08 $1.00 $0.90
-------------------------------------
PER PREFERRED SHARE DATA (DOLLARS)
Series U Cumulative First Preferred Shares $2.80 $2.80 $2.80
Series Y Cumulative First Preferred Shares $2.80 $2.80 $2.80
FINANCIAL RATIOS
Earnings to fixed charges(1) 2.4 2.4 2.2
Earnings to fixed charges (per U.S.GAAP)(2) 2.1 2.2 2.0
-----------------------------------------------------------------------------------------------------------
-----------------------------------------------------------------------------------------------------------
(1) The ratio of earnings to fixed charges is determined by dividing the
financial charges incurred by the company (including capitalized interest)
into its income from continuing operations before financial charges and
income taxes, excluding undistributed income from equity investees.
(2) The ratio is determined in the manner described in (1) above, but utilizing
similar information determined in accordance with U.S. GAAP. Differences
are described in Note 19 "Significant Differences Between Canadian and U.S.
GAAP", to the Consolidated Financial Statements.
SELECTED QUARTERLY CONSOLIDATED FINANCIAL DATA(1)
(unaudited - millions of dollars except per share amounts) FIRST SECOND THIRD FOURTH
----------------------------------------------------------------------------------- ---------------------
2003
Revenues 1,336 1,311 1,391 1,319
Net income applicable to common shares
Continuing operations 208 202 198 193
Discontinued operations - - 50 -
------------------------------------------
208 202 248 193
------------------------------------------
------------------------------------------
SHARE STATISTICS
Net income per share - Basic and Diluted
Continuing operations 0.43 0.42 0.41 0.40
Discontinued operations - - 0.11 -
------------------------------------------
0.43 0.42 0.52 0.40
------------------------------------------
------------------------------------------
2002
OPERATING RESULTS
Revenues 1,246 1,345 1,285 1,338
Net income applicable to common shares
Continuing operations 187 205 175 180
Discontinued operations - - - -
------------------------------------------
187 205 175 180
------------------------------------------
------------------------------------------
SHARE STATISTICS
Net income per share - Basic
Continuing operations $0.39 $0.43 $0.37 $0.37
Discontinued operations - - - -
------------------------------------------
$0.39 $0.43 $0.37 $0.37
------------------------------------------
------------------------------------------
Net income per share - Diluted $0.39 $0.43 $0.36 $0.37
---------------------------------------------------------------------------------------------------------
---------------------------------------------------------------------------------------------------------
(1) The selected annual financial data has been prepared in accordance with
Canadian GAAP. Certain comparative figures have been reclassified to
conform with the current year's presentation. For a discussion on the
factors affecting the comparability of the financial data, including
discontinued operations, refer to Note 1 and Note 18 of TCPL's 2003 Audited
Consolidated Financial Statements.
M-41
FORWARD-LOOKING INFORMATION
Certain information in this Management's Discussion and Analysis 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 TCPL to
successfully implement its strategic initiatives and whether such strategic
initiatives will yield the expected benefits, 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 TCPL with Canadian securities regulators and with the U.S. Securities
and Exchange Commission. TCPL disclaims any intention or obligation to update or
revise any forward-looking statements, whether as a result of new information,
future events or otherwise.
M-42
TransCanada PipeLines Limited
Consolidated Financial Statements
December 31, 2003
F-1
REPORT OF MANAGEMENT
The consolidated financial statements included in this Annual Report are the
responsibility of Management and have been approved by the Board of Directors of
the Company. These consolidated financial statements have been prepared by
Management in accordance with generally accepted accounting principles (GAAP) in
Canada and include amounts that are based on estimates and judgments. Financial
information contained elsewhere in this Annual Report is consistent with the
consolidated financial statements.
Management has prepared Management's Discussion and Analysis (MD&A) which is
based on the Company's financial results prepared in accordance with Canadian
GAAP. It compares the Company's financial performance in 2003 to 2002 and should
be read in conjunction with the consolidated financial statements and
accompanying notes. In addition, significant changes between 2002 and 2001 are
highlighted. Note 19 to the consolidated financial statements describes the
impact on the consolidated financial statements of significant differences
between Canadian and United States GAAP.
Management has developed and maintains a system of internal accounting controls,
including a program of internal audits. Management believes that these controls
provide reasonable assurance that financial records are reliable and form a
proper basis for preparation of financial statements. The internal accounting
control process includes Management's communication to employees of policies
which govern ethical business conduct.
The Board of Directors has appointed an Audit Committee consisting of unrelated,
non-management directors which meets at least five times during the year with
Management and independently with each of the internal and external auditors and
as a group to review any significant accounting, internal control and auditing
matters. The Audit Committee reviews the consolidated financial statements with
Management and the external auditors before the consolidated financial
statements are submitted to the Board of Directors for approval. The internal
and external auditors have free access to the Audit Committee without obtaining
prior Management approval.
With respect to the external auditors, KPMG LLP, the Audit Committee approves
the terms of engagement and reviews the annual audit plan, the Auditors' Report
and results of the audit. It also recommends to the Board of Directors the firm
of external auditors to be appointed by the shareholder.
The independent external auditors, KPMG LLP, have been appointed by the
shareholder to express an opinion as to whether the consolidated financial
statements present fairly, in all material respects, the Company's financial
position, results of operations and cash flows in accordance with Canadian
generally accepted accounting principles. The report of KPMG LLP on page 7
outlines the scope of their examination and their opinion on the consolidated
financial statements.
/s/ Harold N. Kvisle /s/ Russell K. Girling
----------------------------- -----------------------------------------
Harold N. Kvisle Russell K. Girling
President and Executive Vice-President, Corporate
Chief Executive Officer Development and Chief Financial Officer
February 23, 2004
F-2
TRANSCANADA PIPELINES LIMITED
CONSOLIDATED INCOME
YEAR ENDED DECEMBER 31 (MILLIONS OF DOLLARS EXCEPT PER SHARE AMOUNTS) 2003 2002 2001
--------------------------------------------------------------------------------------------------------------------------
REVENUES 5,357 5,214 5,275
OPERATING EXPENSES
Cost of sales 692 627 712
Other costs and expenses 1,682 1,546 1,618
Depreciation 914 848 793
------------------------------------------
3,288 3,021 3,123
------------------------------------------
OPERATING INCOME 2,069 2,193 2,152
OTHER EXPENSES/(INCOME)
Financial charges (NOTE 7) 821 867 889
Financial charges of joint ventures 77 90 107
Equity income (NOTE 6) (165) (33) (24)
Interest and other income (60) (53) (53)
------------------------------------------
673 871 919
------------------------------------------
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
AND NON-CONTROLLING INTERESTS 1,396 1,322 1,233
INCOME TAXES (NOTE 13) 535 517 480
NON-CONTROLLING INTERESTS 2 - -
------------------------------------------
NET INCOME FROM CONTINUING OPERATIONS 859 805 753
NET INCOME/(LOSS) FROM DISCONTINUED OPERATIONS (NOTE 18) 50 - (67)
------------------------------------------
NET INCOME 909 805 686
PREFERRED SECURITIES CHARGES 36 36 45
PREFERRED SHARE DIVIDENDS 22 22 22
------------------------------------------
NET INCOME APPLICABLE TO COMMON SHARES 851 747 619
------------------------------------------
------------------------------------------
NET INCOME/(LOSS) APPLICABLE TO COMMON SHARES
Continuing operations 801 747 686
Discontinued operations 50 - (67)
------------------------------------------
851 747 619
------------------------------------------
------------------------------------------
The accompanying notes to the consolidated financial statements are an integral
part of these statements.
F-3
TRANSCANADA PIPELINES LIMITED
CONSOLIDATED CASH FLOWS
YEAR ENDED DECEMBER 31 (MILLIONS OF DOLLARS) 2003 2002 2001
-------------------------------------------------------------------------------------------------------------------------
CASH GENERATED FROM OPERATIONS
Net income from continuing operations 859 805 753
Depreciation 914 848 793
Future income taxes 230 247 127
Equity income in excess of distributions received (128) (6) -
Other (65) (67) (49)
------------------------------------------
Funds generated from continuing operations 1,810 1,827 1,624
Decrease in operating working capital (NOTE 16) 112 33 170
------------------------------------------
Net cash provided by continuing operations 1,922 1,860 1,794
Net cash (used in)/provided by discontinued operations (17) 59 (659)
------------------------------------------
1,905 1,919 1,135
------------------------------------------
INVESTING ACTIVITIES
Capital expenditures (391) (599) (492)
Acquisitions, net of cash acquired (570) (228) (585)
Disposition of assets - - 1,170
Deferred amounts and other (190) (115) 30
------------------------------------------
Net cash (used in)/provided by investing activities (1,151) (942) 123
------------------------------------------
FINANCING ACTIVITIES
Dividends and preferred securities charges (588) (546) (517)
Advances from parent 46 - -
Notes payable(repaid)/issued, net (62) (46) 186
Long-term debt issued 930 - -
Reduction of long-term debt (744) (486) (793)
Non-recourse debt of joint ventures issued 60 44 23
Reduction of non-recourse debt of joint ventures (71) (80) (132)
Redemption of junior subordinated debentures (218) - -
Common shares issued 18 50 24
Partnership units of joint ventures issued - - 59
Preferred securities redeemed - - (318)
------------------------------------------
Net cash used in financing activities (629) (1,064) (1,468)
------------------------------------------
INCREASE/(DECREASE) IN CASH AND SHORT-TERM INVESTMENTS 125 (87) (210)
CASH AND SHORT-TERM INVESTMENTS
Beginning of year 212 299 509
------------------------------------------
CASH AND SHORT-TERM INVESTMENTS
End of year 337 212 299
------------------------------------------
------------------------------------------
The accompanying notes to the consolidated financial statements are an integral
part of these statements.
F-4
TRANSCANADA PIPELINES LIMITED
CONSOLIDATED BALANCE SHEET
DECEMBER 31 (MILLIONS OF DOLLARS) 2003 2002
--------------------------------------------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS
Cash and short-term investments 337 212
Accounts receivable 603 691
Inventories 165 178
Other 88 107
------------------------------------------
1,193 1,188
LONG-TERM INVESTMENTS (NOTE 6) 733 345
PLANT, PROPERTY AND EQUIPMENT (NOTES 3, 7 AND 8) 17,451 17,496
OTHER ASSETS (NOTE 4) 1,164 937
------------------------------------------
20,541 19,966
------------------------------------------
------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Notes payable (NOTE 14) 367 297
Accounts payable 1,069 990
Accrued interest 208 227
Current portion of long-term debt (NOTE 7) 550 517
Current portion of non-recourse debt of joint ventures (NOTE 8) 19 75
------------------------------------------
2,213 2,106
DEFERRED AMOUNTS 466 549
LONG-TERM DEBT (NOTE 7) 9,465 8,815
FUTURE INCOME TAXES (NOTE 13) 427 226
NON-RECOURSE DEBT OF JOINT VENTURES (NOTE 8) 761 1,222
PREFERRED SECURITIES (NOTE 9) 22 238
------------------------------------------
13,354 13,156
------------------------------------------
NON-CONTROLLING INTERESTS 82 -
SHAREHOLDERS' EQUITY
Preferred securities (NOTE 9) 672 674
Preferred shares (NOTE 10) 389 389
Common shares (NOTE 11) 4,632 4,614
Contributed surplus 267 265
Retained earnings 1,185 854
Foreign exchange adjustment (NOTE 12) (40) 14
------------------------------------------
7,105 6,810
------------------------------------------
COMMITMENTS, CONTINGENCIES AND GUARANTEES (NOTE 17)
20,541 19,966
------------------------------------------
------------------------------------------
The accompanying notes to the consolidated financial statements are an integral
part of these statements.
On behalf of the Board:
Harold N. Kvisle Harry G. Schaefer
Director Director
F-5
TRANSCANADA PIPELINES LIMITED
CONSOLIDATED RETAINED EARNINGS
YEAR ENDED DECEMBER 31 (MILLIONS OF DOLLARS) 2003 2002 2001
-------------------------------------------------------------------------------------------------------------------------
Balance at beginning of year 854 586 395
Net income 909 805 686
Preferred securities charges (36) (36) (45)
Preferred share dividends (22) (22) (22)
Common share dividends (520) (479) (428)
---------------------------------------
1,185 854 586
---------------------------------------
---------------------------------------
The accompanying notes to the consolidated financial statements are an integral
part of these statements.
F-6
AUDITORS' REPORT
TO THE SHAREHOLDER OF TRANSCANADA PIPELINES LIMITED
We have audited the consolidated balance sheets of TransCanada PipeLines Limited
as at December 31, 2003 and 2002 and the consolidated statements of income,
retained earnings and cash flows for each of the years in the three-year period
ended December 31, 2003. These financial statements are the responsibility of
the Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with Canadian generally accepted auditing
standards. Those standards require that we plan and perform an audit to obtain
reasonable assurance whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
In our opinion, these consolidated financial statements present fairly, in all
material respects, the financial position of the Company as at December 31, 2003
and 2002 and the results of its operations and its cash flows for each of the
years in the three-year period ended December 31, 2003 in accordance with
Canadian generally accepted accounting principles.
CHARTERED ACCOUNTANTS
Calgary, Canada
February 23, 2004
F-7
TRANSCANADA PIPELINES LIMITED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
TransCanada PipeLines Limited (the Company or TCPL) is a leading North American
energy company. TCPL operates in two business segments, Gas Transmission and
Power, each of which offers different products and services.
GAS TRANSMISSION
The Gas Transmission segment owns and operates a natural gas transmission system
in Alberta (the Alberta System), a natural gas transmission system extending
from the Alberta border east into Quebec (the Canadian Mainline), a natural gas
transmission system extending from the Alberta border west into southeastern
British Columbia (the BC System), and a natural gas transmission system
extending from central Alberta to the British Columbia, Saskatchewan and the
United States borders (the Foothills System). Gas Transmission also holds the
Company's investments in other natural gas pipelines in Canada and the U.S. In
addition, Gas Transmission investigates and develops new natural gas
transmission, storage and liquefied natural gas regasification facilities in
Canada and the U.S.
POWER
The Power segment builds, owns and operates electrical power generation plants,
and markets electricity. Power also holds the Company's investments in other
electrical power generation plants. This business operates in Canada and the
U.S.
NOTE 1 ACCOUNTING POLICIES
The consolidated financial statements of the Company have been prepared by
Management in accordance with Canadian generally accepted accounting principles
(Canadian GAAP). These accounting principles are different in some respects from
United States generally accepted accounting principles (U.S. GAAP) and the
significant differences are described in Note 19. Amounts are stated in Canadian
dollars unless otherwise indicated. Certain comparative figures have been
reclassified to conform with the current year's presentation.
Since a determination of many assets, liabilities, revenues and expenses is
dependent upon future events, the preparation of these consolidated financial
statements requires the use of estimates and assumptions which have been made
using careful judgment. In the opinion of Management, these consolidated
financial statements have been properly prepared within reasonable limits of
materiality and within the framework of the significant accounting policies
summarized below.
BASIS OF PRESENTATION
Pursuant to a plan of arrangement, effective May 15, 2003, common shares of TCPL
were exchanged on a one-to-one basis for common shares of TransCanada
Corporation (TransCanada). As a result, TCPL became a wholly-owned subsidiary of
TransCanada. The consolidated financial statements for the year ended December
31, 2003 include the accounts of TCPL, the consolidated accounts of all
subsidiaries, and TCPL's proportionate share of the accounts of the Company's
joint venture investments.
F-8
On August 15, 2003, the Company acquired the remaining interests in Foothills
Pipe Lines Ltd. and its subsidiaries (Foothills) previously not held by TCPL,
and Foothills was consolidated subsequent to that date. On December 3, 2003,
TCPL increased its ownership interest in Portland Natural Gas Transmission
System Partnership (Portland) from 43.4 per cent to 61.7 per cent. Subsequent
to the acquisition, Portland was fully consolidated in the Company's
financial statements with 38.3 per cent reflected in non-controlling
interests.
TCPL uses the equity method of accounting for investments over which the Company
is able to exercise significant influence.
REGULATION
The Alberta System is regulated by the Alberta Energy and Utilities Board (EUB),
and the Canadian Mainline, the BC System, the Foothills System, and Trans Quebec
& Maritimes Pipeline Inc. (Trans Quebec & Maritimes) are subject to the
authority of the National Energy Board (NEB). All Canadian natural gas
transmission operations are regulated with respect to the determination of
tolls, construction and operations. In December 2002, the NEB approved TCPL's
application for the Canadian Mainline to charge interim tolls for transportation
service, effective January 1, 2003. In August 2003, subsequent to the NEB's
decision on the 2003 Tolls and Tariff Application, it approved interim tolls for
the period September 1, 2003 to December 31, 2003. The NEB determined that tolls
will remain interim pending a decision from the Federal Court of Appeal on
TransCanada's Fair Return Review and Variance Application. Any adjustments to
the interim tolls will be recorded in accordance with the final NEB decision.
The natural gas pipelines in the United States and certain power plants are also
subject to the authority of regulatory bodies. In order to achieve a proper
matching of revenues and expenses, the timing of recognition of certain revenues
and expenses in these businesses may differ from that otherwise expected under
generally accepted accounting principles.
CASH AND SHORT-TERM INVESTMENTS
The Company's short-term investments with original maturities of three months or
less are considered to be cash equivalents and are recorded at cost, which
approximates market value.
INVENTORIES
Inventories are carried at the lower of average cost or net realizable value and
primarily consist of materials and supplies including spare parts, and storage
gas.
PLANT, PROPERTY AND EQUIPMENT
GAS TRANSMISSION
Plant, property and equipment of natural gas transmission operations are carried
at cost. Depreciation is calculated on the straight-line basis. Pipeline and
compression equipment are depreciated at annual rates ranging from two to five
per cent and metering and other plant are depreciated at various rates. Removal
and site restoration costs are not determinable and will be recorded when
reasonably estimable. An allowance for funds used during construction, using the
rate of return on rate base approved by the regulators, is capitalized and
included in the cost of gas transmission plant.
F-9
POWER
Plant, property and equipment in the Power business are recorded at cost and
depreciated on the straight-line basis over estimated service lives at average
annual rates ranging from two to five per cent. Interest is capitalized on
significant capital projects.
CORPORATE
Corporate plant, property and equipment are recorded at cost and depreciated on
a straight-line basis over estimated useful lives at average annual rates
ranging from three to twenty per cent.
POWER PURCHASE ARRANGEMENTS
The initial payments for power purchase arrangements (PPAs) are deferred and are
being amortized over the terms of the contracts, from the dates of acquisition,
which range from nine to 27 years. PPAs are long-term contracts to purchase
power on a predetermined basis.
INCOME TAXES
As prescribed by the regulators, the taxes payable method of accounting for
income taxes is used for tollmaking purposes for Canadian natural gas
transmission operations. Under the taxes payable method, it is not necessary to
provide for future income taxes. This method is also used for accounting
purposes, since there is reasonable expectation that future taxes payable will
be included in future costs of service and recorded in revenues at that time.
The liability method of accounting for income taxes is used for the remainder of
the Company's operations. Under this method, future tax assets and liabilities
are recognized for the future tax consequences attributable to differences
between the financial statement carrying amounts of existing assets and
liabilities and their respective tax bases. Future income tax assets and
liabilities are measured using enacted or substantively enacted tax rates
expected to apply to taxable income in the years in which temporary differences
are expected to be recovered or settled. Changes to these balances are
recognized in income in the period in which they occur.
Canadian income taxes are not provided on the unremitted earnings of foreign
investments which are considered to be indefinitely reinvested in foreign
operations.
FOREIGN CURRENCY TRANSLATION
The Company's foreign operations are self-sustaining and are translated into
Canadian dollars using the current rate method. Translation adjustments are
reflected in the foreign exchange adjustment in Shareholders' Equity.
Exchange gains or losses on the principal amounts of foreign currency debt,
junior subordinated debentures and preferred securities related to the Alberta
System and the Canadian Mainline are deferred until they are recovered in tolls.
F-10
DERIVATIVE FINANCIAL INSTRUMENTS
The Company utilizes derivative and other financial instruments to manage its
exposure to changes in foreign currency exchange rates, interest rates and
energy commodity prices. Gains or losses relating to derivatives that are hedges
are deferred and recognized in the same period and in the same financial
statement category as the gains or losses on the corresponding hedged
transactions. The recognition of gains and losses on derivatives used as hedges
for Alberta System, Canadian Mainline and the Foothills System exposures is
determined through the regulatory process.
A derivative must be designated and effective to be accounted for as a hedge.
For cash flow hedges, effectiveness is achieved if the changes in the cash flows
of the derivative substantially offset the changes in the cash flows of the
hedged position and the timing of the cash flows is similar. Effectiveness for
fair value hedges is achieved if the fair value of the derivative substantially
offsets changes in the fair value attributable to the hedged item. In the event
that a derivative does not meet the designation or effectiveness criterion, the
gain or loss on the derivative is recognized in income. If a derivative that
qualifies as a hedge is settled early, the gain or loss at settlement is
deferred and recognized when the gain or loss on the hedged transaction is
recognized. Premiums paid or received with respect to derivatives that are
hedges are deferred and amortized to income over the term of the hedge.
EMPLOYEE BENEFIT PLANS
The Company sponsors defined benefit pension plans. The cost of defined benefit
pensions and other post-employment benefits earned by employees is actuarially
determined using the projected benefit method pro-rated on service and
Management's best estimate of expected plan investment performance, salary
escalation, retirement ages of employees and expected health care costs. Pension
plan assets are measured at fair value. The expected return on pension plan
assets is determined using market-related values. Adjustments arising from plan
amendments are amortized on a straight-line basis over the average remaining
service period of employees active at the date of amendment. The excess of the
net actuarial gain or loss over 10 per cent of the greater of the benefit
obligation and the fair value of plan assets is amortized over the average
remaining service period of the active employees. The Company previously
sponsored two additional plans, a defined contribution plan and a combination of
the defined benefit and defined contribution plans, which were effectively
terminated at December 31, 2002.
F-11
NOTE 2 SEGMENTED INFORMATION
NET INCOME/(LOSS)(1)
Gas
Transmission Power Corporate Total
----------------------------------------------------------------------------------------------------------------------
YEAR ENDED DECEMBER 31, 2003 (MILLIONS OF DOLLARS)
Revenues 3,956 1,401 - 5,357
Cost of sales(2) - (692) - (692)
Other costs and expenses (1,270) (405) (7) (1,682)
Depreciation (831) (82) (1) (914)
---------------------------------------------------------
Operating income/(loss) 1,855 222 (8) 2,069
Financial and preferred equity charges and non-controlling
interests (781) (11) (89) (881)
Financial charges of joint ventures (76) (1) - (77)
Equity income 66 99 - 165
Interest and other income 17 14 29 60
Income taxes (459) (103) 27 (535)
---------------------------------------------------------
Continuing Operations 622 220 (41) 801
------------------------------------------
------------------------------------------
Discontinued Operations 50
---------------
Net Income Applicable to Common Shares 851
---------------
---------------
YEAR ENDED DECEMBER 31, 2002 (MILLIONS OF DOLLARS)
Revenues 3,921 1,293 - 5,214
Cost of sales(2) - (627) - (627)
Other costs and expenses (1,166) (371) (9) (1,546)
Depreciation (783) (65) - (848)
---------------------------------------------------------
Operating income/(loss) 1,972 230 (9) 2,193
Financial and preferred equity charges and non-controlling
interests (821) (13) (91) (925)
Financial charges of joint ventures (90) - - (90)
Equity income 33 - - 33
Interest and other income 17 13 23 53
Income taxes (458) (84) 25 (517)
---------------------------------------------------------
Continuing Operations 653 146 (52) 747
------------------------------------------
------------------------------------------
Discontinued Operations -
---------------
Net Income Applicable to Common Shares 747
---------------
---------------
YEAR ENDED DECEMBER 31, 2001 (MILLIONS OF DOLLARS)
Revenues 3,880 1,395 - 5,275
Cost of sales(2) - (712) - (712)
Other costs and expenses (1,226) (361) (31) (1,618)
Depreciation (753) (37) (3) (793)
---------------------------------------------------------
Operating income/(loss) 1,901 285 (34) 2,152
Financial and preferred equity charges and non-controlling
interests (856) (15) (85) (956)
Financial charges of joint ventures (98) (9) - (107)
Equity income 24 - - 24
Interest and other income 6 13 34 53
Income taxes (392) (106) 18 (480)
---------------------------------------------------------
Continuing Operations 585 168 (67) 686
------------------------------------------
------------------------------------------
Discontinued Operations (67)
---------------
Net Income Applicable to Common Shares 619
---------------
---------------
(1) In determining the net income of each segment, certain expenses such as
indirect financial charges and related income taxes are not allocated to
business segments.
(2) Cost of sales is comprised of commodity purchases for resale.
F-12
TOTAL ASSETS
DECEMBER 31 (MILLIONS OF DOLLARS) 2003 2002
----------------------------------------------------------------------------------------------------------
Gas Transmission 16,972 16,979
Power 2,746 2,391
Corporate 812 457
--------------------------
Continuing Operations 20,530 19,827
Discontinued Operations 11 139
--------------------------
20,541 19,966
--------------------------
--------------------------
GEOGRAPHIC INFORMATION
YEAR ENDED DECEMBER 31 (MILLIONS OF DOLLARS) 2003 2002(4) 2001
------------------------------------------------------------------------------------------------------------------------
REVENUES(3)
Canada - domestic 3,257 2,731 3,303
Canada - export 1,293 1,641 1,329
United States 807 842 643
----------------------------------------
5,357 5,214 5,275
----------------------------------------
----------------------------------------
(3) Revenues are attributed to countries based on country of origin of product
or service.
(4) Canada - domestic revenues were reduced in 2002 as a result of
transportation service credits of $662 million. These services were
discontinued in 2003.
PLANT, PROPERTY AND EQUIPMENT
DECEMBER 31 (MILLIONS OF DOLLARS) 2003 2002
----------------------------------------------------------------------------------------------------------
Canada 15,193 15,479
United States 2,258 2,017
--------------------------
17,451 17,496
--------------------------
--------------------------
CAPITAL EXPENDITURES
YEAR ENDED DECEMBER 31 (MILLIONS OF DOLLARS) 2003 2002 2001
------------------------------------------------------------------------------------------------------------------------
Gas Transmission 256 382 285
Power 132 193 121
Corporate and Other 3 24 86
----------------------------------------
391 599 492
----------------------------------------
----------------------------------------
F-13
NOTE 3 PLANT, PROPERTY AND EQUIPMENT
December 31 2003 2002
--------------------------------------------- -------------------------------------------
(MILLIONS OF DOLLARS) ACCUMULATED NET Accumulated Net
COST DEPRECIATION BOOK VALUE Cost Depreciation Book Value
---------------------------------------------------------------------------------- ------------------------------------------
GAS TRANSMISSION
Alberta System
Pipeline 4,934 1,908 3,026 4,922 1,755 3,167
Compression 1,507 549 958 1,517 479 1,038
Metering and other 862 211 651 919 237 682
-------------------------------------------- -------------------------------------------
7,303 2,668 4,635 7,358 2,471 4,887
Under construction 13 - 13 4 - 4
-------------------------------------------- -------------------------------------------
7,316 2,668 4,648 7,362 2,471 4,891
-------------------------------------------- -------------------------------------------
Canadian Mainline
Pipeline 8,683 3,176 5,507 8,674 2,933 5,741
Compression 3,318 832 2,486 3,291 709 2,582
Metering and other 404 132 272 429 118 311
-------------------------------------------- -------------------------------------------
12,405 4,140 8,265 12,394 3,760 8,634
Under construction 12 - 12 15 - 15
-------------------------------------------- -------------------------------------------
12,417 4,140 8,277 12,409 3,760 8,649
-------------------------------------------- -------------------------------------------
Foothills(1)
Pipeline 834 286 548
Compression 378 130 248
Metering and other 185 115 70
--------------------------------------------
1,397 531 866
--------------------------------------------
Other Gas 3,359 1,052 2,307 4,191 1,633 2,558
-------------------------------------------- -------------------------------------------
24,489 8,391 16,098 23,962 7,864 16,098
-------------------------------------------- -------------------------------------------
POWER
Power generation facilities 1,439 381 1,058 1,489 398 1,091
Other 77 41 36 77 38 39
-------------------------------------------- -------------------------------------------
1,516 422 1,094 1,566 436 1,130
Under construction 209 - 209 204 - 204
-------------------------------------------- -------------------------------------------
1,725 422 1,303 1,770 436 1,334
-------------------------------------------- -------------------------------------------
CORPORATE 122 72 50 120 56 64
-------------------------------------------- -------------------------------------------
26,336 8,885 17,451 25,852 8,356 17,496
-------------------------------------------- -------------------------------------------
-------------------------------------------- -------------------------------------------
(1) On August 15, 2003, the Company acquired the remaining interests in
Foothills previously not held by TCPL, and Foothills was consolidated in
the Company's financial statements subsequent to that date.
F-14
NOTE 4 OTHER ASSETS
DECEMBER 31 (MILLIONS OF DOLLARS) 2003 2002
-----------------------------------------------------------------------------
PPAs - Canada(1) 278 297
PPAs - U.S.(1) 248 325
Hedge contracts 166 99
Loans and advances 111 -
Pension asset 143 70
Other 218 146
--------------------------
1,164 937
--------------------------
--------------------------
(1) The following amounts related to the PPAs are included in the consolidated
financial statements.
2003 2002
--------------------------------------- -------------------------------------
ACCUMULATED NET Accumulated Net
DECEMBER 31 (MILLIONS OF DOLLARS) COST AMORTIZATION BOOK VALUE Cost Amortization Book Value
-------------------------------------- --------------------------------------- -------------------------------------
PPAs - Canada 329 51 278 329 32 297
PPAs - U.S. 276 28 248 339 14 325
Amortization expense with respect to the PPAs was $37 million for the year ended
December 31, 2003 (2002 - $28 million; 2001 - $18 million). In 2002, the Company
acquired $114 million of PPAs - U.S.
NOTE 5 JOINT VENTURE INVESTMENTS
TCPL's Proportionate Share
-----------------------------------------------------
Income Before Net
Income Taxes Assets
Year ended December 31 December 31
Ownership ------------------------------ ---------------------
(MILLIONS OF DOLLARS) Interest 2003 2002 2001 2003 2002
----------------------------------------------------------------- ------------------------------ ---------------------
GAS TRANSMISSION
Great Lakes 50.0% (1) 81 102 89 419 492
Iroquois 41.0% (2) 31 30 27 169 160
TC PipeLines, LP 33.4% 21 24 23 130 158
Trans Quebec & Maritimes 50.0% 14 13 15 77 79
CrossAlta 60.0% (1) 11 21 15 41 35
Foothills (3) 19 29 26 - 204
Other Various 7 7 4 22 17
POWER
TransCanada Power, L.P. 35.6% (4) 25 26 21 234 244
ASTC Power Partnership 50.0% (5) - - - 99 105
------------------------------ ---------------------
209 252 220 1,191 1,494
------------------------------ ---------------------
------------------------------ ---------------------
(1) Great Lakes Gas Transmission Limited Partnership (Great Lakes); CrossAlta
Gas Storage & Services Ltd. (CrossAlta).
(2) In May 2001, the Company increased its interest in Iroquois Gas
Transmission System (Iroquois) from 35.0 per cent to 41.0 per cent.
(3) On August 15, 2003, the Company acquired the remaining interests in
Foothills previously not held by TCPL, and Foothills was consolidated
subsequent to that date.
(4) In October 2001, the Company's interest in TransCanada Power, L.P.
decreased from 41.6 per cent to 35.6 per cent.
(5) In December 2001, the Company purchased 50.0 per cent of ASTC Power
Partnership, which is located in Alberta and holds a power purchase
arrangement. In 2002, the underlying power volume related to the 50.0 per
cent ownership interest in the Partnership was effectively transferred to
TCPL.
Consolidated retained earnings at December 31, 2003 include undistributed
earnings from these joint ventures of $509 million (2002 - $433 million).
F-15
SUMMARIZED FINANCIAL INFORMATION OF JOINT VENTURES
YEAR ENDED DECEMBER 31 (MILLIONS OF DOLLARS) 2003 2002 2001
-------------------------------------------------------------------------------------------------------------------------------
INCOME
Revenues 623 680 592
Other costs and expenses (275) (251) (172)
Depreciation (96) (119) (119)
Financial charges and other (43) (58) (81)
----------------------------------------
Proportionate share of income before income taxes of joint ventures 209 252 220
----------------------------------------
----------------------------------------
YEAR ENDED DECEMBER 31 (MILLIONS OF DOLLARS) 2003 2002 2001
-------------------------------------------------------------------------------------------------------------------------------
CASH FLOWS
Operations 272 323 279
Investing activities (124) (125) 21
Financing activities (156) (210) (291)
----------------------------------------
Proportionate share of (decrease)/increase in cash and short-term investments of
joint ventures (8) (12) 9
----------------------------------------
----------------------------------------
DECEMBER 31 (MILLIONS OF DOLLARS) 2003 2002
-----------------------------------------------------------------------------------------------------------------
BALANCE SHEET
Cash and short-term investments 55 63
Other current assets 122 127
Long-term investments 118 148
Plant, property and equipment 1,688 2,503
Other assets and deferred amounts (net) 114 103
Current liabilities (94) (164)
Non-recourse debt (761) (1,222)
Future income taxes (51) (64)
--------------------------
Proportionate share of net assets of joint ventures 1,191 1,494
--------------------------
--------------------------
NOTE 6 LONG-TERM INVESTMENTS
TCPL's Share
-----------------------------------------------------
Income From Equity
Equity Investments Investments
Year ended December 31 December 31
Ownership -----------------------------------------------------
(MILLIONS OF DOLLARS) Interest 2003 2002 2001 2003 2002
--------------------------------------------------------------------------------------------------------------------------
EQUITY INVESTMENTS
POWER
Bruce Power L.P. 31.6% 99 - - 513 -
GAS TRANSMISSION
Northern Border 10.0% (1) 22 25 23 103 129
TransGas de Occidente S.A. 46.5% 27 5 2 80 75
Portland 61.7% (2) 14 2 (1) - 68
Other Various 3 1 - 37 73
------------------------------ ---------------------
165 33 24 733 345
------------------------------ ---------------------
------------------------------ ---------------------
(1) The Northern Border equity investment effective ownership interest of 10.0
per cent is the result of the Company holding a 33.4 per cent interest in
TC PipeLines, LP, which holds a 30.0 per cent interest in Northern Border
Pipeline Company (Northern Border).
(2) In September 2003, the Company increased its ownership interest in Portland
from 33.3 per cent to 43.4 per cent. In December 2003, the Company
increased its ownership interest to 61.7 per cent and the investment was
fully consolidated subsequent to that date.
F-16
Consolidated retained earnings at December 31, 2003 include undistributed
earnings from these equity investments of $166 million (2002 - $47 million).
INVESTMENT IN BRUCE POWER L.P.
On February 14, 2003, the Company acquired a 31.6 per cent interest in Bruce
Power L.P. (Bruce Power) for $409 million, including closing adjustments. As
part of the acquisition, the Company also funded a one-third share ($75 million)
of a $225 million accelerated deferred rent payment made by Bruce Power to
Ontario Power Generation. The resulting note receivable from Bruce Power is
recorded in Other Assets.
The purchase price of the Company's 31.6 per cent interest in Bruce Power has
been allocated as follows.
PURCHASE PRICE ALLOCATION
(MILLIONS OF DOLLARS)
-------------------------------------------------------------------------
Net book value of assets acquired 281
Capital lease 301
Power sales agreements (131)
Pension liability and other (42)
-----------
409
-----------
-----------
The amount allocated to the investment in Bruce Power includes a purchase price
allocation of $301 million to the capital lease of the Bruce Power plant which
will be amortized on a straight-line basis over the lease term which extends to
2018, resulting in an annual amortization expense of $19 million. The amount
allocated to the power sales agreements will be amortized to income over the
remaining term of the underlying sales contracts. The amortization of the fair
value allocated to these contracts is: 2003 - $38 million; 2004 - $37 million;
2005 - $25 million; 2006 - $29 million; and 2007 - $2 million. The amount
allocated to the pension liability will be amortized to income over the 11 year
expected average remaining service life of Bruce Power employees, resulting in
an annual amortization of $3 million.
F-17
NOTE 7 LONG-TERM DEBT
2003 2002
---------------------------------- --------------------------------
WEIGHTED Weighted
AVERAGE Average
Maturity OUTSTANDING INTEREST Outstanding Interest
Dates DECEMBER 31(1) RATE(2) December 31(1) Rate(2)
------------------------------------------------------------------------------------------------- --------------------------------
ALBERTA SYSTEM
Debentures and Notes
Canadian dollars 2007 to 2024 627 11.6% 798 11.0%
U.S. dollars (2003 and 2002 - US$500) 2004 to 2023 646 8.3% 790 8.3%
Medium-Term Notes
Canadian dollars 2005 to 2030 767 7.4% 767 7.4%
U.S. dollars (2003 and 2002 - US$233) 2026 to 2029 301 7.7% 368 7.7%
Unsecured Loans
U.S. dollars (2003 - nil; 2002 - US$107) 2003 - 169 2.1%
------------------- -----------------
2,341 2,892
Foreign exchange differential recoverable
through the tollmaking process (16) (271)
------------------- -----------------
2,325 2,621
------------------- -----------------
CANADIAN MAINLINE
First Mortgage Pipe Line Bonds
Pounds Sterling (2003 and 2002 -(pound)25) 2007 58 16.5% 64 16.5%
Debentures
Canadian dollars 2008 to 2020 1,354 10.9% 1,354 10.9%
U.S. dollars (2003 and 2002 - US$800) 2012 to 2023 1,034 9.2% 1,264 9.2%
Medium-Term Notes
Canadian dollars 2004 to 2031 2,312 6.9% 2,405 7.0%
U.S. dollars (2003 and 2002 - US$120) 2010 155 6.1% 190 6.1%
------------------- -----------------
4,913 5,277
Foreign exchange differential recoverable
through the tollmaking process (60) (330)
------------------- -----------------
4,853 4,947
------------------- -----------------
FOOTHILLS(3)
Senior Secured Notes 2005 80 4.3%
Senior Unsecured Notes 2005 to 2014 300 4.7%
-------------------
380
-------------------
PORTLAND(4)
Senior Secured Notes
U.S. dollars (2003 - US$271) 2018 350 5.9%
-------------------
OTHER
Medium-Term Notes
Canadian dollars 2005 to 2030 592 6.2% 342 6.6%
U.S. dollars (2003 and 2002 - US$665) 2004 to 2025 859 6.8% 1,050 6.8%
Subordinated Debentures
U.S. dollars (2003 and 2002 - US$57) 2006 74 9.1% 90 9.1%
Unsecured Loans, Debentures and Notes
Canadian dollars 2003 - 110 8.4%
U.S. dollars (2003 - US$446; 2002 -
US$109) 2006 to 2013 582 4.9% 172 8.3%
------------------- -----------------
2,107 1,764
------------------- -----------------
10,015 9,332
Less: Current Portion of Long-Term Debt 550 517
------------------- -----------------
9,465 8,815
------------------- -----------------
------------------- -----------------
F-18
(1) Amounts outstanding are stated in millions of Canadian dollars; amounts
denominated in currencies other than Canadian dollars are stated in
millions.
(2) Weighted average interest rates are stated as at the respective outstanding
dates. The effective weighted average interest rates resulting from swap
agreements are as follows: Alberta System U.S. dollar unsecured loans in
2002 - 8.3 per cent; Foothills senior unsecured notes - 5.8 per cent;
Portland senior secured notes - 6.2 per cent; Other U.S. dollar
subordinated debentures - 9.0 per cent (2002 - 9.0 per cent); and Other
U.S. dollar unsecured loans, debentures and notes - 5.2 per cent.
(3) On August 15, 2003, the Company acquired the remaining interests in
Foothills previously not held by TCPL, and Foothills was consolidated in
the Company's financial statements subsequent to that date.
(4) On December 3, 2003, TCPL increased its ownership interest in Portland
from 43.4 per cent to 61.7 per cent. The investment was fully consolidated
in the Company's financial statements subsequent to that date.
PRINCIPAL REPAYMENTS
Principal repayments on the long-term debt of the Company approximate: 2004 -
$550 million; 2005 - $702 million; 2006 - $399 million; 2007 - $611 million; and
2008 - $542 million.
UNIVERSAL SHELF PROGRAMS
At December 31, 2003, $1.6 billion of common shares, preferred shares and/or
debt securities including medium-term notes could be issued under TCPL's
universal shelf program in Canada and US$650 million of debt securities could be
issued under TCPL's universal shelf program in the U.S. During 2003, $450
million of medium-term notes and US$350 million of senior unsecured notes were
issued under these programs.
ALBERTA SYSTEM
DEBENTURES
Debentures amounting to $225 million have retraction provisions which entitle
the holders to require redemption of up to 8 per cent of the then outstanding
principal plus accrued and unpaid interest on specified repayment dates. No
redemptions have been made to December 31, 2003.
F-19
MEDIUM-TERM NOTES
Medium-term notes amounting to $50 million have a provision entitling the
holders to extend the maturity of the medium-term notes from the initial
repayment date of 2007 to 2027. If extended, the interest rate would increase
from 6.1 per cent to 7.0 per cent and the medium-term notes would become
redeemable at the option of the Company.
CANADIAN MAINLINE
FIRST MORTGAGE PIPE LINE BONDS
The Deed of Trust and Mortgage securing the Company's First Mortgage Pipe Line
Bonds limits the specific and floating charges to those assets comprising the
present and future Canadian Mainline and the Company's present and future gas
transportation contracts.
FOOTHILLS
SENIOR SECURED NOTES
Foothills has issued and pledged to the banks a demand debenture in the
principal amount of $200 million as security for funds advanced under the credit
agreement. Foothills has also granted a floating charge on its undertakings,
property and assets.
OTHER
MEDIUM-TERM NOTES
Medium-term notes amounting to US$145 million and $150 million have retraction
provisions which entitle the holders to require redemption of the principal plus
accrued and unpaid interest in 2004 and 2005, respectively. The Company also has
the option to redeem the US$145 million medium-term notes in 2004. If the U.S.
dollar medium-term notes remain outstanding, the interest rate will change in
2004 from 6.4 per cent to 6.1 per cent plus a market-based corporate credit
spread.
FINANCIAL CHARGES
YEAR ENDED DECEMBER 31 (MILLIONS OF DOLLARS) 2003 2002 2001
-------------------------------------------------------------------------------------------------------------------------------
Interest on long-term debt 801 850 890
Regulatory deferrals and amortizations (14) (17) (30)
Short-term interest and other financial charges 34 34 38
-----------------------------------------
821 867 898
Financial charges - discontinued operations - - (9)
-----------------------------------------
821 867 889
-----------------------------------------
-----------------------------------------
F-20
The Company made interest payments of $846 million for the year ended December
31, 2003 (2002 - $866 million; 2001 - $936 million). The Company capitalized $9
million of interest for the year ended December 31, 2003 (2002 and 2001 - nil).
NOTE 8 NON-RECOURSE DEBT OF JOINT VENTURES
2003 2002
-------------------------------- --------------------------------
WEIGHTED Weighted
AVERAGE Average
Maturity OUTSTANDING INTEREST Outstanding Interest
Dates DECEMBER 31(1) RATE(2) December 31(1) Rate(2)
------------------------------------------------------------------------------------------------- --------------------------------
GREAT LAKES
Senior Unsecured Notes
(2003 - US$240; 2002 - US$261) 2011 to 2030 310 7.9% 412 8.0%
IROQUOIS
Senior Unsecured Notes
(2003 and 2002 - US$151) 2010 to 2027 196 7.5% 239 7.5%
Bank Loan
(2003 - US$43; 2002 - US$16) 2008 56 2.3% 25 3.2%
FOOTHILLS(3)
Senior Unsecured Notes 325 3.3%
Senior Secured Notes 62 6.7%
TRANS QUEBEC & MARITIMES
Bonds 2005 to 2010 143 7.3% 143 7.3%
Term Loan 2006 34 3.5% 40 2.8%
TC PIPELINES, LP
Senior Unsecured Notes
(2002 - US$4) - 6 3.0%
OTHER 2004 to 2012 41 5.4% 45 5.6%
------------------ ------------------
780 1,297
Less: Current Portion of Non-Recourse Debt
of Joint Ventures 19 75
------------------ ------------------
761 1,222
------------------ ------------------
------------------ ------------------
(1) Amounts outstanding represent TCPL's proportionate share and are stated in
millions of Canadian dollars; amounts denominated in U.S. dollars are
stated in millions.
(2) Weighted average interest rates are stated as at the respective outstanding
dates. At December 31, 2003, the effective weighted average interest rate
on the bank loan of Iroquois resulting from a swap agreement is 4.5 per
cent (2002 - 4.8 per cent).
(3) On August 15, 2003, the Company acquired the remaining interests in
Foothills previously not held by TCPL, and Foothills was consolidated in
the Company's financial statements subsequent to that date.
The debt of joint ventures is non-recourse to TCPL. The security provided by
each joint venture is limited to the rights and assets of that joint venture and
does not extend to the rights and assets of TCPL, except to the extent of TCPL's
investment.
The Company's proportionate share of principal repayments resulting from
maturities and sinking fund obligations of the non-recourse joint venture debt
approximates: 2004 - $19 million; 2005 - $69 million; 2006 - $55 million; 2007 -
$19 million; and 2008 - $19 million.
The Company's proportionate share of the interest payments of joint ventures was
$67 million for the year ended December 31, 2003 (2002 - $88 million; 2001 -
$100 million).
F-21
NOTE 9 PREFERRED SECURITIES AND JUNIOR SUBORDINATED DEBENTURES
2003 2002
Maturity (millions (millions
Date of dollars) of dollars)
----------------------------------------------------------------------------------------------------------------
PREFERRED SECURITIES
8.25% Issue (2003 - US$14 million; 2002 - US$13 million) 2047 22 20
JUNIOR SUBORDINATED DEBENTURES
8.75% Issue (2003 - nil; 2002 - US$160 million) - 218
--------------------------
22 238
--------------------------
--------------------------
PREFERRED SECURITIES
The US$460 million 8.25 per cent Preferred Securities are redeemable by the
Company at par at any time. The Company may elect to defer interest payments on
the Preferred Securities and settle the deferred interest in either cash or
common shares.
Since the deferred interest may be settled through the issuance of common shares
at the option of the Company, the Preferred Securities are classified into their
respective debt and equity components. The equity component of the Preferred
Securities is $672 million at December 31, 2003 (2002 - $674 million).
JUNIOR SUBORDINATED DEBENTURES
On July 3, 2003, the Company redeemed the US$160 million, 8.75 per cent Junior
Subordinated Debentures. Holders of these debentures received US$25.0122 per
US$25.00 of the principal amount, which included accrued and unpaid interest to
the redemption date, without premium or penalty.
NOTE 10 PREFERRED SHARES
Number Dividend Redemption 2003 2002
of Shares Rate Price (millions of (millions of
DECEMBER 31 (thousands) Per Share Per Share dollars) dollars)
-----------------------------------------------------------------------------------------------------------------------------
CUMULATIVE FIRST PREFERRED SHARES
Series U 4,000 $2.80 $50.00 195 195
Series Y 4,000 $2.80 $50.00 194 194
--------------------------------
389 389
--------------------------------
--------------------------------
The authorized number of Preferred Shares issuable in series is unlimited. All
of the cumulative first preferred shares are without par value.
On or after October 15, 2013, for the Series U shares, and on or after March 5,
2014, for the Series Y shares, the Company may redeem the shares at $50 per
share.
NOTE 11 COMMON SHARES
Number
of Shares Amount
---------------------------------------------------------------------------------------
(millions of
(thousands) dollars)
Outstanding at January 1, 2001 474,913 4,540
Exercise of options 1,718 24
---------------------------------------
Outstanding at December 31, 2001 476,631 4,564
Exercise of options 2,871 50
---------------------------------------
Outstanding at December 31, 2002 479,502 4,614
Exercise of options 1,166 18
---------------------------------------
OUTSTANDING AT DECEMBER 31, 2003 480,668 4,632
---------------------------------------
---------------------------------------
COMMON SHARES ISSUED AND OUTSTANDING
The Company is authorized to issue an unlimited number of common shares of no
par value.
F-22
RESTRICTION ON DIVIDENDS
Certain terms of the Company's preferred shares, preferred securities, and debt
instruments could restrict the Company's ability to declare dividends on
preferred and common shares. At December 31, 2003, such terms did not restrict
or alter the Company's ability to declare dividends.
NOTE 12 RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
The Company issues short-term and long-term debt including amounts in foreign
currencies, purchases and sells energy commodities and invests in foreign
operations. These activities result in exposures to interest rates, energy
commodity prices and foreign currency exchange rates. The Company uses
derivatives to manage the risk that results from these activities.
CARRYING VALUES OF DERIVATIVES
The carrying amounts of derivatives, which hedge the price risk of foreign
currency denominated assets and liabilities of self-sustaining foreign
operations are recorded on the balance sheet at their fair value. Gains and
losses on the derivatives, realized and unrealized, are included in the foreign
exchange adjustment account in Shareholders' Equity as a reduction of the
corresponding gains and losses on the translation of the assets and liabilities
of the foreign subsidiaries. Carrying amounts for interest rate swaps represent
the net accrued interest from the last payment date to the reporting date.
Foreign currency transactions hedged by foreign exchange contracts are recorded
at the contract rate. Power, natural gas and heat rate derivatives are recorded
on the balance sheet at their fair value. The carrying amounts shown in the
tables that follow are recorded in the Consolidated Balance Sheet.
FAIR VALUES OF FINANCIAL INSTRUMENTS
Cash and short-term investments and notes payable are valued at their carrying
amounts due to the short period to maturity. The fair values of long-term debt,
non-recourse long-term debt of joint ventures and junior subordinated debentures
are determined using market prices for the same or similar issues.
The fair values of foreign exchange and interest rate derivatives have been
estimated using year-end market rates. These fair values approximate the amount
that the Company would receive or pay if the instruments were closed out at
these dates.
CREDIT RISK
Credit risk results from the possibility that a counterparty to a derivative in
which the Company has an unrealized gain fails to perform according to the terms
of the contract. Credit exposure is minimized through the use of established
credit management techniques, including formal assessment processes, contractual
and collateral requirements and credit exposure limits. At December 31, 2003,
for foreign currency and interest rate derivatives, total credit risk and the
largest credit exposure to a single counterparty were $127 million and $29
million, respectively. At December 31, 2003, for power, natural gas and heat
rate derivatives, total credit risk and the largest credit exposure to a single
counterparty were $67 million and $61 million, respectively.
NOTIONAL AMOUNTS
Notional principal amounts are not recorded in the financial statements because
these amounts are not exchanged by the Company and its counterparties and are
not a measure of the Company's exposure. Notional amounts are used only as the
basis for calculating payments for certain derivatives.
F-23
FOREIGN INVESTMENTS
At December 31, 2003 and 2002, the Company had foreign currency denominated
assets and liabilities which created an exposure to changes in exchange rates.
The Company uses foreign currency derivatives to hedge this net exposure on an
after-tax basis. The foreign currency derivatives have a floating interest rate
exposure which the Company partially hedges by entering into interest rate swaps
and forward rate agreements. The Company's portfolio of foreign investment
derivatives is comprised of contracts for periods up to four years. The fair
values shown in the table below for foreign exchange risk are offset by
translation gains or losses on the net assets and are recorded in the foreign
exchange adjustment account in Shareholders' Equity.
ASSET/(LIABILITY) AT DECEMBER 31 (MILLIONS OF DOLLARS) 2003 2002
--------------------------------------------------------------------------------------- ----------------------------
CARRYING FAIR Carrying Fair
AMOUNT VALUE Amount Value
--------------------------- ----------------------------
FOREIGN EXCHANGE
Cross-currency swaps
U.S. dollars 65 65 (8) (8)
Forward foreign exchange contracts
U.S. dollars 2 3 (4) (4)
At December 31, 2003, the notional principal amounts of cross-currency swaps
were US$250 million (2002 - US$350 million) and principal amounts of forward
foreign exchange contracts were US$125 million (2002 - US$225 million). In
addition, the Company has associated interest rate swaps with notional principal
amounts of $311 million (2002 - $309 million) and US$200 million (2002 - US$350
million). The fair value of these interest rate swaps was $1 million (2002 -
$(4) million).
RECONCILIATION OF FOREIGN EXCHANGE ADJUSTMENT
DECEMBER 31 (MILLIONS OF DOLLARS) 2003 2002
--------------------------------------------------------------------------------------------------------
Balance at beginning of year 14 13
Translation (losses)/gains on foreign currency denominated net assets (136) 3
Foreign exchange gains/(losses) on derivatives, and other 82 (2)
------------------------
(40) 14
------------------------
------------------------
FOREIGN EXCHANGE GAINS/(LOSSES)
Foreign exchange gains/(losses) included in Other Expenses/(Income) for the year
ended December 31, 2003 are $(2) million (2002 - $(12) million; 2001 - $1
million).
FOREIGN EXCHANGE AND INTEREST RATE MANAGEMENT ACTIVITY
The Company manages the foreign exchange risk of U.S. dollar debt, U.S. dollar
expenses and the interest rate exposures of the Alberta System, the Canadian
Mainline and the Foothills System through the use of foreign currency and
interest rate derivatives. These derivatives are comprised of contracts for
periods up to nine years. Certain of the realized gains and losses on these
derivatives are shared with shippers on predetermined terms.
F-24
ASSET/(LIABILITY) AT DECEMBER 31 (MILLIONS OF DOLLARS) 2003 2002
----------------------------------------------------------------------------------------------- -------------------------
CARRYING FAIR Carrying Fair
AMOUNT VALUE Amount Value
---------------------------- -------------------------
FOREIGN EXCHANGE
Cross-currency swaps (26) (26) 56 56
INTEREST RATE
Interest rate swaps
Canadian dollars 2 15 4 56
U.S. dollars - 8 (1) 4
At December 31, 2003, the notional principal amounts of cross-currency swaps
were US$282 million (2002 - US$282 million) and the notional principal amounts
for interest rate swaps were $964 million (2002 - $874 million) and US$100
million (2002 - US$175 million).
The Company manages the foreign exchange risk and interest rate exposure of its
Other U.S. dollar debt through the use of foreign currency and interest rate
derivatives. These derivatives are comprised of contracts for periods up to ten
years. The fair values of the interest rate derivatives are shown in the table
below.
ASSET/(LIABILITY) AT DECEMBER 31 (MILLIONS OF DOLLARS) 2003 2002
----------------------------------------------------------------- ---------------------------- -------------------------
CARRYING FAIR Carrying Fair
AMOUNT VALUE Amount Value
---------------------------- -------------------------
INTEREST RATE
Interest rate swaps
U.S. dollars 2 37 2 55
At December 31, 2003, the notional principal amount for interest rate swaps was
US$500 million (2002 - US$400 million).
ENERGY PRICE RISK MANAGEMENT
The Company executes power, natural gas and heat rate derivatives for overall
management of its asset portfolio. The Company's portfolio of power, natural gas
and heat rate derivatives is primarily comprised of swap, option and forward
contracts for periods of up to 13 years, with fixed and floating price
commitments. Heat rate contracts are contracts for the sale or purchase of power
that are priced based on a natural gas index. The fair values of power, natural
gas and heat rate derivatives have been calculated at year-end using estimated
forward prices for the relevant period. The fair values and notional volumes of
the swap, option, forward and heat rate contracts are shown in the tables below.
ASSET/(LIABILITY) AT DECEMBER 31 (MILLIONS OF DOLLARS) 2003 2002
----------------------------------------------------------------- ---------------------------- ----------------------------
CARRYING FAIR Carrying Fair
AMOUNT VALUE Amount Value
---------------------------- ----------------------------
Power - swaps (5) (5) (36) (36)
Gas - swaps, forwards and options (35) (35) (28) (28)
Heat rate contracts 61 61 74 74
NOTIONAL VOLUMES AT DECEMBER 31, 2003 POWER (GWH)(1) GAS (BCF)(1)
----------------------------------------------------------------- ---------------------------- ----------------------------
PURCHASES SALES PURCHASES SALES
---------------------------- ----------------------------
Power - swaps 1,390 4,864 - -
Gas - swaps, forwards and options - - 86.1 88.2
Heat rate contracts 2,331 735 1.0 20.3
NOTIONAL VOLUMES AT DECEMBER 31, 2002 Power (GWh) Gas (Bcf)
----------------------------------------------------------------- ---------------------------- ----------------------------
Purchases Sales Purchases Sales
---------------------------- ----------------------------
Power - swaps 467 5,138 - -
Gas - swaps, forwards and options - - 86.3 88.6
Heat rate contracts 2,848 - - 24.8
(1) Gigawatt hours (GWh); billion cubic feet (Bcf).
U.S. DOLLAR TRANSACTION HEDGES
To reduce risk and protect margins when purchase and sale contracts are
denominated in different currencies, the Company may enter into forward foreign
exchange contracts and foreign exchange options which establish the foreign
exchange rate for the cash flows from the related purchase and sale
transactions.
F-25
OTHER FAIR VALUES
DECEMBER 31 (MILLIONS OF DOLLARS) 2003 2002
----------------------------------------------------------------- ---------------------------- ----------------------------
CARRYING FAIR Carrying Fair
AMOUNT VALUE Amount Value
---------------------------- ----------------------------
LONG-TERM DEBT
Alberta System 2,341 2,893 2,892 3,420
Canadian Mainline 4,913 5,922 5,277 6,080
Foothills(1) 380 382
Portland(2) 350 348
Other 2,107 2,214 1,764 1,904
NON-RECOURSE DEBT OF JOINT VENTURES 780 889 1,297 1,427
PREFERRED SECURITIES 19 19 274 276
(1) On August 15, 2003, TCPL acquired the remaining interests in Foothills
previously not held by TCPL, and Foothills was consolidated in the
Company's financial statements subsequent to that date.
(2) On December 3, 2003, TCPL increased its ownership interest in Portland
from 43.4 per cent to 61.7 per cent. The investment was fully
consolidated in the Company's financial statements subsequent to that
date.
These fair values are provided solely for information purposes and are not
recorded in the Consolidated Balance Sheet.
NOTE 13 INCOME TAXES
PROVISION FOR INCOME TAXES
YEAR ENDED DECEMBER 31 (MILLIONS OF DOLLARS) 2003 2002 2001
---------------------------------------------------------------------------------------------------------------
CURRENT
Canada 264 229 307
Foreign 41 41 46
------------------------------------------
305 270 353
------------------------------------------
------------------------------------------
FUTURE
Canada 183 193 70
Foreign 47 54 57
------------------------------------------
230 247 127
------------------------------------------
535 517 480
------------------------------------------
------------------------------------------
GEOGRAPHIC COMPONENTS OF INCOME
YEAR ENDED DECEMBER 31 (MILLIONS OF DOLLARS) 2003 2002 2001
---------------------------------------------------------------------------------------------------------------
Canada 1,115 1,042 933
Foreign 281 280 300
------------------------------------------
Income from continuing operations before income taxes 1,396 1,322 1,233
------------------------------------------
------------------------------------------
RECONCILIATION OF INCOME TAX EXPENSE
YEAR ENDED DECEMBER 31 (MILLIONS OF DOLLARS) 2003 2002 2001
---------------------------------------------------------------------------------------------------------------
Income from continuing operations before income taxes 1,396 1,322 1,233
------------------------------------------
Federal and provincial statutory tax rate 36.7% 39.2% 42.1%
Expected income tax expense 512 518 519
Unrecorded future income taxes related to regulated operations 29 (8) (55)
Lower effective foreign tax rates (2) (13) (13)
Large corporations tax 28 30 31
Lower effective tax rate on equity in earnings of affiliates (11) (2) (1)
Other (21) (8) (1)
------------------------------------------
Actual income tax expense 535 517 480
------------------------------------------
------------------------------------------
F-26
FUTURE INCOME TAX ASSETS AND LIABILITIES
DECEMBER 31 (MILLIONS OF DOLLARS) 2003 2002
-------------------------------------------------------------------------------------------------------
Net operating and capital loss carryforwards 28 91
Deferred costs 50 49
Deferred revenue 29 55
Alternative minimum tax credits 29 31
Other 24 41
-------------------------
160 267
Less: Valuation allowance 24 33
-------------------------
Future income tax assets, net of valuation allowance 136 234
-------------------------
Difference in accounting and tax bases of plant, equipment and PPAs 396 345
Investments in subsidiaries and partnerships 108 107
Other 59 8
-------------------------
Future income tax liabilities 563 460
-------------------------
Net future income tax liabilities 427 226
-------------------------
-------------------------
The Company follows the taxes payable method of accounting for income taxes
related to the operations of the Canadian natural gas transmission operations.
If the liability method of accounting had been used, additional future income
tax liabilities in the amount of $1,758 million at December 31, 2003 (2002 -
$1,702 million) would have been recorded and would be recoverable from future
revenues.
UNREMITTED EARNINGS OF FOREIGN INVESTMENTS
Income taxes have not been provided on the unremitted earnings of foreign
investments which the Company intends to indefinitely reinvest in foreign
operations. If provision for these taxes had been made, future income tax
liabilities would increase by approximately $54 million at December 31, 2003
(2002 - $60 million).
INCOME TAX PAYMENTS
Income tax payments of $220 million were made during the year ended December 31,
2003 (2002 - $257 million; 2001 - $292 million).
NOTE 14 NOTES PAYABLE
2003 2002
------------------------------------------ ------------------------------------------
OUTSTANDING WEIGHTED AVERAGE Outstanding Weighted Average
DECEMBER 31 INTEREST RATE PER December 31 Interest Rate Per
(MILLIONS OF ANNUM AT (millions of Annum at
DOLLARS) DECEMBER 31 dollars) December 31
------------------ ---------------------- ------------------ -----------------------
COMMERCIAL PAPER
Canadian dollars 367 2.7% 258 2.9%
U.S. dollars - 39 1.4%
------------------ ------------------
367 297
------------------ ------------------
------------------ ------------------
Total credit facilities of $2.2 billion at December 31, 2003, were available to
support the Company's commercial paper progams and for general corporate
purposes. Of this total, $1.9 billion represents committed credit facilities of
which $1.5 billion represents a syndicated facility established in December
2002. This facility is comprised of a $1.0 billion tranche with a three year
term and a $500 million tranche with a 364 day term with a two year term out
option. Both tranches are extendible on an annual basis and are revolving unless
during a term out period. Both tranches were extended in December 2003, the $1.0
billion tranche to December 2006 and the $500 million tranche to December 2004.
The remaining committed facilities are non extendible, $60 million expires in
June 2004 and $320 million expires in June 2005.
At December 31, 2003, the Company had used approximately $217 million of its
total lines of credit for letters of credit and to support its ongoing
commercial arrangements. If drawn, interest on the lines of credit would be
charged at prime rates of Canadian chartered and U.S. banks and at other
negotiated financial bases. The cost to maintain the unused portion of the lines
of credit is approximately $2 million for the year ended December 31, 2003 (2002
- $1 million).
F-27
NOTE 15 EMPLOYEE FUTURE BENEFITS
The Company sponsors defined benefit pension plans (DB Plans) that cover
substantially all employees and sponsored a defined contribution pension plan
(DC Plan) which was effectively terminated at December 31, 2002. The DB Plans
are based on years of service and highest average earnings over three
consecutive years of employment. Under the DC Plan, Company contributions were
based on the participating employees' pensionable earnings. As a result of the
termination of the DC Plan, members of this plan were awarded retroactive
service credit under the DB Plans for all years of service. In exchange for past
service credit, members surrendered the accumulated assets in their DC Plan
accounts to the DB Plans as at December 31, 2002. This plan amendment resulted
in unamortized past service costs of $44 million. Past service costs are
amortized over the expected average remaining service life of employees, which
is an average of 12 years.
The Company also provides its employees with other post-employment benefits
other than pensions, including special termination benefits and defined life
insurance and medical benefits beyond those provided by government-sponsored
plans. Effective January 1, 2003, the Company combined its previously existing
other post-employment benefit plans into one plan for active employees and
provided existing retirees the option of adopting the provisions of the new
plan. This plan amendment resulted in unamortized past service costs of $7
million. Past service costs are amortized over the expected average remaining
life expectancy of former employees, which is approximately 19 years.
The expense for the DC Plan is nil for the year ended December 31, 2003 (2002 -
$6 million; 2001 - $7 million). In 2003, the Company also expensed $1 million
(2002 - nil; 2001 - nil) related to retirement savings plans for its U.S.
employees.
Information about the Company's DB Plans measured and valued at December 31 is
as follows.
Pension Benefit Other Benefit
Plans Plans
---------------------------- -----------------------------
(MILLIONS OF DOLLARS) 2003 2002 2003 2002
------------------------------------------------------------------------------------------ -----------------------------
CHANGE IN BENEFIT OBLIGATION
Benefit obligation - beginning of year 841 659 95 60
Current service cost 25 11 2 2
Interest cost 52 43 6 4
Employee contributions 2 1 - -
Benefits paid (45) (58) (4) (4)
Actuarial loss 66 93 7 26
Acquisition of subsidiary 19 - - -
Plan amendment - 92 - 7
---------------------------- -----------------------------
Benefit obligation - end of year 960 841 106 95
---------------------------- -----------------------------
CHANGE IN PLAN ASSETS
Plan assets at fair value - beginning of year 621 573 - -
Actual return on plan assets 89 9 - -
Employer contributions 110 48 4 4
Employee contributions 2 1 - -
Benefits paid (45) (58) (4) (4)
Acquisition of subsidiary 22 - - -
Assets receivable from DC Plan - 48 - -
---------------------------- -----------------------------
Plan assets at fair value - end of year 799 621 - -
---------------------------- -----------------------------
Funded status - plan deficit (161) (220) (106) (95)
Unamortized net actuarial loss 263 246 39 33
Unamortized past service costs 41 44 6 7
Unamortized transitional obligation related to regulated
business - - 25 27
---------------------------- -----------------------------
Accrued benefit asset/(liability), net of valuation allowance
of nil(1) 143 70 (36) (28)
---------------------------- -----------------------------
---------------------------- -----------------------------
(1) Assets and liabilities are included in Other Assets and Deferred Amounts,
respectively, in TransCanada's Consolidated Balance Sheet.
F-28
The Company's expected contributions for the year 2004 are approximately $80
million for the pension benefit plans and approximately $5 million for the other
benefit plans.
The significant weighted average actuarial assumptions adopted in measuring the
Company's benefit obligations at December 31 are as follows.
Pension Benefit Plans Other Benefit Plans
------------------------------------------------------------------------------------------------ -----------------------
2003 2002 2003 2002
---------------------- -----------------------
Discount rate 6.00% 6.25% 6.25% 6.50%
Rate of compensation increase 3.50% 3.75%
The significant weighted average actuarial assumptions adopted in measuring the
Company's net benefit plan expense for years ended December 31 are as follows.
Pension Benefit Plans Other Benefit Plans
------------------------------------ -----------------------------------
2003 2002 2001 2003 2002 2001
---------------------------------------------------------------------------------------- -----------------------------------
Discount rate 6.25% 6.75% 6.80% 6.50% 6.85% 6.90%
Expected long-term rate of return on plan assets 7.25% 7.52% 7.10%
Rate of compensation increase 3.75% 3.50% 3.50%
The overall expected long-term rate of return on plan assets is based on
historical and projected rates of return for both the portfolio in aggregate and
for each asset class in the portfolio. Assumed projected rates of return are
selected after analyzing historical experience and future expectations of the
level and volatility of returns. Asset class benchmark returns, asset mix and
anticipated benefit payments from plan assets are also considered in the
determination of the overall expected rate of return.
For measurement purposes, a 7.5 per cent annual rate of increase in the per
capita cost of covered health care benefits was assumed for 2004. The rate was
assumed to decrease gradually to 5.0 per cent for 2009 and remain at that level
thereafter. A one percentage point increase or decrease in assumed health care
cost trend rates would have the following effects.
(MILLIONS OF DOLLARS) Increase Decrease
-------------------------------------------------------------------------------------------------------------------------
Effect on total of service and interest cost components 1 (1)
Effect on post-employment benefit obligation 11 (10)
The Company's net benefit plan expense is as follows.
Pension Benefit Plans Other Benefit Plans
--------------------------- ----------------------------
YEAR ENDED DECEMBER 31 (MILLIONS OF DOLLARS) 2003 2002 2001 2003 2002 2001
----------------------------------------------------------------------------------------- ----------------------------
Current service cost 25 11 12 2 2 2
Interest cost 52 43 41 6 4 4
Expected return on plan assets (51 ) (45 ) (41 ) - - -
Amortization of transitional obligation related to
regulated business - - - 2 2 2
Amortization of net actuarial loss 8 2 - 1 - -
Amortization of past service costs 3 - - 1 - -
--------------------------- ----------------------------
37 11 12 12 8 8
Net benefit cost recognized - discontinued
operations - - 2 - - -
--------------------------- ----------------------------
Net benefit cost recognized - continuing operations 37 11 10 12 8 8
--------------------------- ----------------------------
--------------------------- ----------------------------
F-29
The Company's pension plan weighted average asset allocation at December 31, by
asset category, and weighted average target allocation at December 31, by asset
category, is as follows.
Target
Percentage of Plan Assets Allocation
-------------------------------------- ------------------
ASSET CATEGORY 2003 2002 2003
----------------------------------------------------------------------------------------------------- ------------------
Debt securities 47% 51% 35% TO 60%
Equity securities 53% 49% 40% TO 65%
--------------------------------------
100% 100%
--------------------------------------
--------------------------------------
The assets of the pension plan are managed on a going concern basis subject to
legislative restrictions. The plan's investment policy is to maximize returns
within an acceptable risk tolerance. Pension assets are invested in a
diversified manner with consideration given to the demographics of the plan
participants.
NOTE 16 CHANGES IN OPERATING WORKING CAPITAL
YEAR ENDED DECEMBER 31 (MILLIONS OF DOLLARS) 2003 2002 2001
----------------------------------------------------------------------------------------------------------------
Decrease/(increase) in accounts receivable 26 (45) 38
Decrease/(increase) in inventories 15 (3) 52
Decrease/(increase) in other current assets 21 (53) (12)
Increase in accounts payable 52 120 105
(Decrease)/increase in accrued interest (2) 14 (13)
----------------------------------------
112 33 170
----------------------------------------
----------------------------------------
NOTE 17 COMMITMENTS, CONTINGENCIES AND GUARANTEES
COMMITMENTS
Future annual payments, net of sub-lease receipts, under the Company's operating
leases for various premises are approximately as follows.
Amounts
Minimum Lease Recoverable under Net
YEAR ENDED DECEMBER 31 (MILLIONS OF DOLLARS) Payments Sub-Leases Payments
----------------------------------------------------------------------------------------------------------------------------
2004 25 (7) 18
2005 25 (7) 18
2006 25 (7) 18
2007 24 (7) 17
2008 24 (7) 17
The operating lease agreements expire at various dates through 2011, with an
option to renew certain lease agreements for five years.
At December 31, 2003, TCPL held a 35.6 per cent interest in TransCanada Power,
L.P. which is a publicly-held limited partnership. On June 30, 2017, the
partnership will redeem all units outstanding, not held directly or indirectly
by TCPL, at their then fair market value, being the average of the fair market
values assigned thereto by independent valuators, plus all declared and unpaid
distributions of distributable cash thereon (the Redemption Price). TCPL is
required to fund the Redemption Price in accordance with the terms of the Power
LP Partnership agreement.
F-30
On June 18, 2003, the Mackenzie Delta gas producers, the Aboriginal Pipeline
Group (APG) and TransCanada reached an agreement which governs TCPL's role in
the Mackenzie Gas Pipeline Project. The project would result in a natural gas
pipeline being constructed from Inuvik, Northwest Territories to the northern
border of Alberta, where it would then connect with the Alberta System. Under
the agreement, TCPL has agreed to finance the APG for its one-third share of
project definition phase costs. This share is estimated to be approximately $90
million over three years. In the year ended December 31, 2003, TransCanada
funded $34 million of this loan which is included in Other Assets. The ability
to recover this investment is contingent upon the outcome of the project.
CONTINGENCIES
The Canadian Alliance of Pipeline Landowners' Associations and two individual
landowners have commenced an action under Ontario's Class Proceedings Act, 1992,
against TCPL and Enbridge Inc. for damages alleged to arise from the creation of
a control zone within 30 metres of the pipeline pursuant to section 112 of the
NEB Act. The Company believes the claim is without merit and will vigorously
defend the action. The Company has made no provision for any potential
liability. A liability, if any, would be dealt with through the regulatory
process.
The Company and its subsidiaries are subject to various other legal proceedings
and actions arising in the normal course of business. While the final outcome of
such legal proceedings and actions cannot be predicted with certainty, it is the
opinion of Management that the resolution of such proceedings and actions will
not have a material impact on the Company's consolidated financial position or
results of operations.
GUARANTEES
Upon acquisition of Bruce Power, the Company, together with Cameco Corporation
and BPC Generation Infrastructure Trust, guaranteed on a several pro-rata basis
certain contingent financial obligations of Bruce Power related to operator
licenses, the lease agreement, power sales agreements and contractor services.
TCPL's share of the net exposure under these guarantees at December 31, 2003 was
estimated to be approximately $215 million. The terms of the guarantees range
from 2004 to 2018. The current carrying amount of the liability related to these
guarantees is nil and the fair value is approximately $4 million.
TCPL has guaranteed the equity undertaking of a subsidiary which supports the
payment, under certain conditions, of principal and interest on the US$195
million public debt obligations of TransGas de Occidente, S.A. (TransGas). The
Company has a 46.5 per cent interest in TransGas. Under the terms of the
agreement, the Company severally with another major multinational company may be
required to fund more than their proportionate share of debt obligations of
TransGas in the event that the minority shareholders fail to contribute. Any
payments made by TCPL under this agreement convert into share capital of
TransGas. The potential exposure is contingent on the impact of any change of
law on TransGas' ability to service the debt. From the issuance of the debt in
1995 to date, there has been no change in applicable law and thus no exposure to
TCPL. The debt matures in 2010. The Company has made no provision related to
this guarantee.
F-31
NOTE 18 DISCONTINUED OPERATIONS
The Board of Directors approved plans to dispose of the Company's International,
Canadian Midstream, and certain other businesses (December Plan) and the Gas
Marketing business in December 1999 and July 2001, respectively. The Company's
disposals under both plans were substantially completed at December 31, 2001.
TCPL's investments in Gasoducto del Pacifico, INNERGY Holdings S.A. and P.T.
Paiton Energy Company approved for disposal under the December Plan will be
accounted for as part of continuing operations as of December 31, 2003, due to
the length of time it has taken the Company to dispose of these assets. It is
the intention of the Company to continue with its plan to dispose of these
investments.
The Company mitigated certain of its remaining exposures associated with the
contingent liabilities related to the divested Gas Marketing operations by
acquiring from a subsidiary of Mirant Corporation (Mirant) certain contracts
under which it still had exposure in 2003, and simultaneously hedging the market
price exposures of these contracts. The Company remains contingently liable for
certain residual obligations. In 2003, $50 million of the original approximately
$100 million after-tax deferred gain was recognized in income. The remaining
after-tax deferred gain is included in Deferred Amounts.
At December 31, 2003, TCPL reviewed the provision for loss on discontinued
operations and the deferred gain and concluded that the remaining provision was
adequate and the deferral of the remaining approximately $50 million of
after-tax deferred gain related to the Gas Marketing business was appropriate.
Revenues from discontinued operations for the year ended December 31, 2003 were
$2 million (2002 - $36 million; 2001 - $12,895 million). Net income/(loss) from
discontinued operations for the year ended December 31, 2003 was $50 million,
net of $29 million income taxes (2002 - nil; 2001 - $(67) million, net of $(33)
million income taxes). The provision for loss on discontinued operations at
December 31, 2003 was $41 million (2002 - $83 million). The provision for loss
on discontinued operations is included in Accounts Payable.
F-32
NOTE 19 U.S. GAAP
The Company's consolidated financial statements have been prepared in accordance
with Canadian GAAP, which, in some respects, differ from U.S. GAAP. The effects
of these differences on the Company's financial statements are as follows.
CONDENSED STATEMENT OF CONSOLIDATED INCOME AND COMPREHENSIVE INCOME IN
ACCORDANCE WITH U.S. GAAP(1)
YEAR ENDED DECEMBER 31 (MILLIONS OF DOLLARS) 2003 2002 2001
-------------------------------------------------------------------------------------------------------------------------------
Revenues(2) 4,919 4,565 4,165
---------------------------------------
Cost of sales(2) 592 441 47
Other costs and expenses 1,663 1,532 1,609
Depreciation 819 729 675
---------------------------------------
3,074 2,702 2,331
---------------------------------------
Operating income 1,845 1,863 1,834
Other (income)/expenses
Equity income(1)(3) (334) (260) (221)
Other expenses(4)(5) 841 850 931
Income taxes 515 499 407
---------------------------------------
1,022 1,089 1,117
---------------------------------------
Income from continuing operations - U.S. GAAP 823 774 717
Net income/(loss) from discontinued operations - U.S. GAAP 50 - (67)
---------------------------------------
Income before cumulative effect of the application of accounting changes in
accordance with U.S. GAAP 873 774 650
Cumulative effect of the application of accounting changes, net of tax(2)(4) (13) - (2)
---------------------------------------
NET INCOME IN ACCORDANCE WITH U.S. GAAP 860 774 648
Adjustments affecting comprehensive income under U.S. GAAP
Foreign currency translation adjustment, net of tax(6) (54) 1 -
Additional minimum liability for employee future benefits, net of tax(7) (2) (40) (56)
Unrealized gain/(loss) on derivatives, net of tax(4) 8 (4) (5)
---------------------------------------
Comprehensive income before cumulative effect of the application of accounting
changes in accordance with U.S. GAAP 812 731 587
Cumulative effect of the application of accounting changes, net of tax(4) - - (4)
---------------------------------------
COMPREHENSIVE INCOME IN ACCORDANCE WITH U.S. GAAP 812 731 583
---------------------------------------
---------------------------------------
RECONCILIATION OF INCOME FROM CONTINUING OPERATIONS
YEAR ENDED DECEMBER 31 (MILLIONS OF DOLLARS) 2003 2002 2001
-------------------------------------------------------------------------------------------------------------------------------
Net income from continuing operations in accordance with Canadian GAAP 859 805 753
U.S. GAAP adjustments
Preferred securities charges(8) (57) (58) (77)
Tax impact of preferred securities charges 21 22 32
Unrealized (loss)/gain on foreign exchange and interest rate derivatives(4) (9) 30 (14)
Tax impact of (loss)/gain on foreign exchange and interest rate derivatives 3 (12) 6
Unrealized gain/(loss) on energy trading contracts(2) 28 (21) (17)
Tax impact of unrealized gain/(loss) on energy trading contracts (10) 8 6
Equity loss(3) (18) - -
Tax impact of equity loss 6 - -
Income taxes from substantively enacted tax rates(9) - - 28
----------------------------------------
Income from continuing operations in accordance with U.S. GAAP 823 774 717
----------------------------------------
----------------------------------------
F-33
CONDENSED BALANCE SHEET IN ACCORDANCE WITH U.S. GAAP(1)
DECEMBER 31 (MILLIONS OF DOLLARS) 2003 2002
-----------------------------------------------------------------------------------------------------------------
Current assets 1,017 1,079
Long-term energy trading assets(2) - 218
Long-term investments(3)(10) 1,760 1,683
Plant, property and equipment(11) 15,798 14,992
Regulatory asset(12) 2,721 2,578
Other assets(4) 1,192 884
--------------------------
22,488 21,434
--------------------------
--------------------------
Current liabilities(13) 2,117 2,006
Long-term energy trading liabilities(2) - 41
Deferred amounts(2)(4)(10)(11) 741 789
Long-term debt(4) 9,494 8,963
Deferred income taxes(12) 3,039 2,692
Preferred securities(14) 694 694
Trust originated preferred securities - 218
Non-controlling interests 82 -
Shareholders' equity 6,321 6,031
--------------------------
22,488 21,434
--------------------------
--------------------------
STATEMENT OF OTHER COMPREHENSIVE INCOME IN ACCORDANCE WITH U.S. GAAP
Minimum
Cumulative Pension Cash Flow
Translation Liability Hedges
(MILLIONS OF DOLLARS) Account (SFAS No. 87) (SFAS No. 133) Total
------------------------------------------------------------------------------------------------------------------------------
Balance at January 1, 2001 13 - - 13
Additional minimum liability for employee future
benefits, net of tax of $30(7) - (56) - (56)
Unrealized loss on derivatives, net of tax of $2(4) - - (5) (5)
Cumulative effect of the application of accounting
changes, net of tax of $3(4) - - (4) (4)
------------------------------------------------------------------
Balance at December 31, 2001 13 (56) (9) (52)
Additional minimum liability for employee future
benefits, net of tax of $22(7) - (40) - (40)
Unrealized loss on derivatives, net of tax of $(1)(4) - - (4) (4)
Foreign currency translation adjustment, net of tax of
nil(6) 1 - - 1
------------------------------------------------------------------
Balance at December 31, 2002 14 (96) (13) (95)
Additional minimum liability for employee future
benefits, net of tax of $1(7) - (2) - (2)
Unrealized gain on derivatives, net of tax of nil(4) - - 8 8
Foreign currency translation adjustment, net of tax of
$(64)(6) (54) - - (54)
------------------------------------------------------------------
BALANCE AT DECEMBER 31, 2003 (40) (98) (5) (143)
------------------------------------------------------------------
------------------------------------------------------------------
F-34
(1) In accordance with U.S. GAAP, the Condensed Statement of Consolidated
Income and Condensed Balance Sheet are prepared using the equity method of
accounting for joint ventures. Excluding the impact of other U.S. GAAP
adjustments, the use of the proportionate consolidation method of
accounting for joint ventures, as required under Canadian GAAP, results in
the same net income and Shareholders' Equity.
(2) In 2002, for U.S. GAAP purposes, TCPL adopted the transitional provisions
of FASB Emerging Issues Task Force (EITF) 02-3, "Accounting for Contracts
Involved in Energy Trading and Risk Management Activities" whereby the
Company was netting all revenues and expenses related to derivative energy
trading contracts. The accounting change was applied retroactively with
reclassification of prior periods. Prior to adoption of EITF 02-3, energy
trading contracts were measured at fair value determined as at the balance
sheet date. Effective January 1, 2003, the Company fully adopted EITF 02-3.
This accounting change was effected through a cumulative adjustment of
$(13) million, after tax, in the current year's income with no restatement
of prior periods. Substantially all of the energy trading contracts are
accounted for as hedges under Canadian GAAP. Subsequent to October 1, 2003,
the energy trading contracts that qualified as hedges were accounted for as
hedges under the provisions of Statement of Financial Accounting Standards
(SFAS) No. 133. All gains or losses on the contracts that did not qualify
as hedges, and the amounts of any ineffectiveness on the hedging contracts,
are included in income each period. Substantially all of the amounts
recorded in 2003 as differences between U.S. and Canadian GAAP relate to
gains and losses on contracts that were not accounted for as hedges.
(3) (a) Under Canadian GAAP, pre-operating costs incurred during the
commissioning phase of a new project are deferred until commercial
production levels are achieved. After such time, those costs are amortized
over the estimated life of the project. Under U.S. GAAP, such costs are
expensed as incurred. Certain start-up costs incurred by Bruce Power are
required to be expensed under U.S. GAAP.
(b) Under both Canadian GAAP and U.S. GAAP, interest is capitalized on
expenditures relating to construction of development projects actively
being prepared for their intended use. In Bruce Power, under U.S. GAAP, the
carrying value of development projects against which interest is
capitalized is lower due to the expensing of pre-operating costs.
(4) In 2001, the Company adopted the provisions of SFAS No. 133 "Accounting for
Derivatives and Hedging Activities". SFAS No. 133 requires that all
derivatives be recognized as assets and liabilities on the balance sheet
and measured at fair value.
For derivatives designated as fair value hedges, changes in the fair value
are recognized in earnings together with an equal or lesser amount of
changes in the fair value of the hedged item attributable to the hedged
risk. For derivatives designated as cash flow hedges, changes in the fair
value of the derivative that are effective in offsetting the hedged risk
are recognized in other comprehensive income until the hedged item is
recognized in earnings. Any ineffective portion of the change in fair value
is recognized in earnings each period.
On initial adoption of SFAS No. 133 on January 1, 2001, additional assets
of $93 million and liabilities of $99 million were recorded for U.S. GAAP
purposes to reflect the fair value of derivatives designated as interest
rate hedges and the corresponding change in the fair value of items
designated as hedges. A charge of $2 million, after tax, relating to the
fair value of hedges was recognized in income and $4 million, after tax,
relating to the fair value of derivatives designated as cash flow hedges
was recognized in other comprehensive income as the cumulative effect of
application of SFAS No. 133.
During 2003, net gains of $47 million (2002 - $38 million; 2001 - $36
million) from the hedges of changes in the fair value of long-term debt,
and net losses of $53 million (2002 - $20 million; 2001 - $44 million) in
the fair value of the hedged item were included in earnings as an
adjustment to interest expense and foreign exchange losses. No amounts of
the derivatives' gains or losses were excluded from the assessment of hedge
effectiveness in fair value hedging relationships.
F-35
No amounts were included in income in 2003, 2002 and 2001 with respect to
ineffectiveness of cash flow hedges. For amounts included in other
comprehensive income at December 31, 2003, $9 million (2002 - $(5) million;
2001 - $(3) million) relates to the hedge of interest rate risk, $5 million
(2002 - $1 million; 2001 - $(2) million) relates to the hedge of foreign
exchange rate risk, and $(6) million (2002 - nil; 2001 - nil) relates to
the hedge of energy price risk. Of these amounts, $(5) million is expected
to be recorded in earnings during 2004.
At December 31, 2003, additional assets of $107 million (2002 - $198
million) and additional liabilities of $110 million (2002 - $203 million)
were recorded for U.S. GAAP purposes to reflect the fair value of
derivatives designated as hedges and the corresponding change in the fair
value of items designated as hedges.
(5) Other expenses include an allowance for funds used during construction of
$2 million for the year ended December 31, 2003 (2002 - $4 million; 2001 -
$5 million).
(6) Under U.S. GAAP, changes in the foreign currency translation adjustment
account must be recorded as a component of comprehensive income.
(7) Under U.S. GAAP, a net loss recognized pursuant to SFAS No. 87 "Employers'
Accounting for Pensions" as an additional pension liability not yet
recognized as net period pension cost, must be recorded as a component of
comprehensive income. The net amount recognized at December 31 is as
follows.
DECEMBER 31 (MILLIONS OF DOLLARS) 2003 2002
------------------------------------------------------------------------------
Prepaid benefit cost $ 143 $ 70
Accrued benefit cost - -
Intangible assets (41) (44)
Accumulated other comprehensive income (151) (148)
--------------------------
Net amount recognized $ (49) $(122)
--------------------------
--------------------------
The accumulated benefit obligation for the Company's DB Plans was $819
million at December 31, 2003 (2002 - $738 million).
(8) Under U.S. GAAP, the financial charges related to preferred securities are
recognized as an expense, rather than dividends.
(9) Under U.S. GAAP, only enacted rates can be used in measuring deferred tax
assets and liabilities; use of substantively enacted rates is not
permitted. The February 2000 and October 2000 Federal budgets would not be
considered enacted until the proposals were completely enacted into law in
June 2001 and, accordingly, the related tax recoveries were recognized in
2001.
(10) Effective January 1, 2003, the Company adopted the provisions of Financial
Interpretation (FIN) 45 that require the recognition of a liability for the
fair value of certain guarantees that require payments contingent on
specified types of future events. The measurement standards of FIN 45 are
applicable to guarantees entered into after January 1, 2003. For U.S. GAAP,
the Company has recorded the fair value of the guarantees ($4 million)
arising on the acquisition of the interest in Bruce Power as a liability
and an increase in the cost of the investment.
(11) Effective January 1, 2003, the Company adopted the provisions of SFAS No.
143 "Accounting for Asset Retirement Obligations", which addresses
financial accounting and reporting for obligations associated with asset
retirement costs. SFAS No. 143 requires that the fair value of a liability
for an asset retirement obligation be recognized in the period in which it
is incurred if a reasonable estimate of fair value can be made. The fair
value is added to the carrying amount of the associated asset. The
liability is accreted at the end of each period through charges to
operating expenses.
The plant, property and equipment of the regulated natural gas transmission
operations consist primarily of underground pipelines and above ground
compression equipment and other facilities. No amount has been recorded for
asset retirement obligations relating to these assets as it is not possible
to make a reasonable estimate of the fair value of the liability due to the
indeterminate timing and scope of the asset retirements. Management
believes that all retirement costs associated with the regulated pipelines
will be recovered through tolls in future periods.
The plant, property and equipment in the power business consists primarily
of power plants in Canada and the United States. The estimated fair value
of the liability for the power plants and associated assets as at January
1, 2003 was $6 million. The asset retirement cost, net of accumulated
depreciation that would have been recorded if the cost had been recorded in
the period in which it arose, is recorded as an additional cost of the
assets as at January 1, 2003. The estimated fair value of the liability as
at December 31, 2003 was $7 million. The cumulative effect of the
application of SFAS No. 143 on income with respect to the years ended
December 31, 2001 and 2002 would have been less than $1 million. The
Company has no legal liability for asset retirement obligations with
respect to its investment in Bruce Power and the Sundance A and B power
purchase arrangements.
F-36
(12) Under U.S. GAAP, the Company is required to record a deferred income tax
liability for its cost-of-service regulated businesses. As these deferred
income taxes are recoverable through future revenues, a corresponding
regulatory asset is recorded for U.S. GAAP purposes.
(13) Current liabilities at December 31, 2003 include dividends payable of $136
million (2002 - $125 million) and current taxes payable of $271 million
(2002 - $150 million).
(14) The fair value of the preferred securities at December 31, 2003 was $612
million (2002 - $743 million). The Company made preferred securities
charges payments of $57 million for the year ended December 31, 2003 (2002
- $58 million; 2001 - $77 million).
(15) The Company's Statement of Consolidated Cash Flows under U.S. GAAP would be
identical to that under Canadian GAAP except that the preferred securities
charges would be classified with funds generated from continuing
operations.
INCOME TAXES
The tax effects of differences between the accounting value and the tax value of
assets and liabilities are as follows.
DECEMBER 31 (MILLIONS OF DOLLARS) 2003 2002
-------------------------------------------------------------------------------------------------------------------
DEFERRED TAX LIABILITIES
Difference in accounting and tax bases of plant, equipment and PPAs 1,813 1,703
Taxes on future revenue requirement 962 876
Investments in subsidiaries and partnerships 373 379
Other 87 22
----------------------------
3,235 2,980
----------------------------
DEFERRED TAX ASSETS
Net operating and capital loss carry forwards 28 91
Deferred amounts 79 104
Other 113 126
----------------------------
220 321
Less: Valuation allowance 24 33
----------------------------
196 288
----------------------------
Net deferred tax liabilities 3,039 2,692
----------------------------
----------------------------
OTHER
In 2003, the FASB issued FIN 46 (Revised) "Consolidation of Variable Interest
Entities" that requires the consolidation of certain entities that are
controlled through financial interests that indicate control (referred to as
"variable interests"). Variable interests are the rights or obligations that
convey economic gains or losses from changes in the values of an entity's assets
or liabilities. The holder of the majority of an entity's variable interests
will be required to consolidate the variable interest entity. Adopting the
provisions of FIN 46 (Revised) has had no impact on the U.S. GAAP financial
statements of the Company.
F-37
In May 2003, the FASB issued SFAS No. 150 "Accounting for Certain Financial
Instruments with Characteristics of both Liabilities and Equity". This Statement
establishes standards for how an issuer classifies and measures in its statement
of financial position certain financial instruments with characteristics of both
liabilities and equity. It requires that an issuer classify a financial
instrument that is within its scope as a liability (or an asset in some
circumstances) because that financial instrument embodies an obligation of the
issuer. Many of those instruments were previously classified as equity. Adopting
the provisions of SFAS No. 150 has had no impact on the U.S. GAAP financial
statements of the Company. Effective January 1, 2005, in accordance with
Canadian GAAP, certain instruments that are currently classified as equity will
be classified as liabilities, under new Canadian accounting standards.
SUMMARIZED FINANCIAL INFORMATION OF LONG-TERM INVESTMENTS(16)
YEAR ENDED DECEMBER 31 (MILLIONS OF DOLLARS) 2003 2002 2001
-------------------------------------------------------------------------------------------------------------------
INCOME
Revenues 1,063 798 695
Other costs and expenses (528) (273) (191)
Depreciation (141) (146) (143)
Financial charges and other (53) (112) (136)
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Proportionate share of income before income taxes of long-term investments 341 267 225
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DECEMBER 31 (MILLIONS OF DOLLARS) 2003 2002
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BALANCE SHEET
Current assets 385 246
Plant, property and equipment 2,944 3,251
Other assets (net) - 112
Current liabilities (204) (216)
Deferred amounts (net) (286) -
Non-recourse debt (1,060) (1,646)
Deferred income taxes (19) (64)
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Proportionate share of net assets of long-term investments 1,760 1,683
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(16) This includes those investments that are accounted for by the equity method
under U.S. GAAP (including those that are accounted for by the
proportionate consolidation method under Canadian GAAP).
F-38