RNS Number:8668J
TransCanada Pipelines Ld
16 March 2005
PART 3
SCHEDULE "B"
CHARTER OF
THE AUDIT COMMITTEE
PART 1
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 seven
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.
TRANSCANADA PIPELINES LIMITED 59
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 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. Review of Charter and Evaluation of Committee
The Committee shall review its Charter annually or otherwise, as it deems
appropriate, and if necessary propose changes to the Governance Committee
and the Board. The Committee shall annually review the Committee's own
performance.
14. Outside Experts and Advisors
The Committee, and on behalf of the Committee, the Committee Chair, is
authorized when deemed necessary or desirable to retain independent counsel,
outside experts 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.
60 TRANSCANADA PIPELINES LIMITED
PART II
Specific 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 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;
TRANSCANADA PIPELINES LIMITED 61
(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;
(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;
62 TRANSCANADA PIPELINES LIMITED
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;
(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
TRANSCANADA PIPELINES LIMITED 63
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;
(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;
(e)
review and approve the Company's hiring policies for employees or former
employees of the external auditors (recognizing the Sarbanes-Oxley Act
of 2002 does not permit the CEO, controller, CFO or chief accounting
officer to have participated in the Company's audit as an employee of
the external auditors' during the preceding one-year period) and monitor
the Company's adherence to the 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
64 TRANSCANADA PIPELINES LIMITED
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 65
FINANCIAL HIGHLIGHTS
Year ended December 31 (millions of dollars)
2004 2003 2002 2001 2000
Income Statement
Net income/(loss) applicable to common
shares
Continuing operations 978 801 747 686 628
Discontinued operations 52 50 - (67 ) 61
1,030 851 747 619 689
Cash Flow Statement
Funds generated from continuing 1,672 1,810 1,827 1,624 1,495
operations
Capital expenditures and acquisitions 1,992 961 827 1,077 1,135
Balance Sheet
Total assets 22,129 20,698 20,172 20,141 24,924
Long-term debt 9,713 9,465 8,815 9,347 9,928
Common shareholders' equity 6,484 6,044 5,747 5,426 5,211
CONSOLIDATED FINANCIAL REVIEW
The Management's Discussion and Analysis dated March 1, 2005 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, 2004. Amounts are stated in Canadian dollars unless otherwise
indicated.
HIGHLIGHTS
Net Income In 2004, net income applicable to common shares was $1.03 billion
compared to $851 million in 2003.
Net Earnings In 2004, TCPL's net income applicable to common shares from
continuing operations (net earnings) increased $177 million to $978 million
compared to $801 million in 2003.
Investing Activities In 2004, TCPL invested more than $2.6 billion
(including assumed debt) in the Gas Transmission and Power businesses.
Approximately $2.1 billion was invested in the acquisition of the Gas
Transmission Northwest System and the North Baja System (collectively GTN).
Balance Sheet In 2004, TCPL's shareholders' equity increased by
approximately $0.4 billion.
CONSOLIDATED RESULTS-AT-A-GLANCE
Year ended December 31 (millions of dollars)
2004 2003 2002
Net Income Applicable to Common Shares
Continuing operations* 978 801 747
Discontinued operations 52 50 -
1,030 851 747
SEGMENT RESULTS-AT-A-GLANCE
Year ended December 31 (millions of dollars)
2004 2003 2002
Gas Transmission 586 622 653
Power 396 220 146
Corporate (4 ) (41 ) (52 )
Continuing operations* 978 801 747
Discontinued operations 52 50 -
Net Income Applicable to Common Shares 1,030 851 747
* Net earnings.
Net income applicable to common shares for the year ended December 31, 2004 was
$1.030 billion compared to $851 million for 2003. This includes net income from
discontinued operations of $52 million in 2004 and $50 million in 2003,
reflecting income recognized on the initially deferred gains relating to the
disposition in 2001 of the company's Gas Marketing business. Net income
applicable to common shares in 2002 was $747 million.
TCPL's net earnings for the year ended December 31, 2004 were $978 million
compared to $801 million in 2003 and $747 million in 2002. The increase of $177
million in 2004 compared to 2003 was primarily due to significantly higher net
earnings from the Power business. In addition, lower net earnings from the Gas
Transmission business were offset by reduced net expenses in the Corporate
segment.
Net earnings from the Power business increased $176 million in 2004 compared to
2003 primarily due to the realization in 2004 of a gain of $15 million after tax
($25 million pre tax) on the sale of the ManChief and Curtis Palmer power plants
to TransCanada Power, L.P. (Power LP) and the recognition of $172 million of
dilution and other gains resulting from a reduction in TCPL's ownership interest
in Power LP and the removal of Power LP's obligation, in 2017, to redeem units
M-1
not owned by TCPL. TCPL was previously required to fund this redemption,
therefore, the removal of Power LP's obligation eliminates this requirement.
Excluding the above-mentioned $187 million of combined gains included in net
earnings related to Power LP and the recognition in 2003 of a $19 million
after-tax settlement with a former counterparty, Power's net earnings in 2004
were $8 million higher than in 2003. Higher equity income from TCPL's investment
in Bruce Power L.P. (Bruce Power), acquired in February 2003, was partially
offset by lower contributions from Eastern Operations and TCPL's investment in
Power LP.
The decrease in net earnings of $36 million in the Gas Transmission business in
2004 compared to 2003 were primarily due to a decline in the Alberta System's
and Canadian Mainline's net earnings. The Alberta System's net earnings in 2004
reflect the impacts of the Alberta Energy and Utilities Board (EUB) decisions in
2004 on Phase I of the General Rate Application (GRA) and Generic Cost of
Capital (GCOC). The decline in the Canadian Mainline's net earnings was
primarily as a result of a lower rate of return on common equity (ROE) as
determined by the generic ROE formula set by the National Energy Board (NEB) and
a lower average investment base. These decreases were partially offset by net
earnings from GTN, which TCPL acquired on November 1, 2004, higher earnings from
CrossAlta Gas Storage & Services Ltd. (CrossAlta) and TransCanada Pipeline
Ventures Limited Partnership (Ventures LP), and a $7 million gain on sale of the
company's equity interest in the Millennium Pipeline project (Millennium). The
2003 results included TCPL's $11 million share of a positive future income tax
benefit adjustment recognized by TransGas de Occidente S.A. (TransGas).
The decrease in net expenses of $37 million in the Corporate segment in 2004
was primarily due to the positive impacts of income tax and foreign exchange
related items throughout 2004 and the release in 2004 of previously established
restructuring provisions.
The increase of $54 million in 2003 net earnings compared to 2002 was mainly
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. Net earnings from the Power business in 2003 included
equity income of $73 million after tax from TCPL's investment in Bruce Power and
a $19 million after-tax settlement with a former counterparty. The reduction in
net earnings in the Gas Transmission business in 2003 compared to 2002 reflects
a decline in the Canadian Mainline and the Alberta System's net earnings. The
2002 results included TCPL's $7 million share of a favourable ruling for Great
Lakes Gas Transmission Limited Partnership 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 years ended December
31, 2004 and 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 and marketing opportunities in regions where
it enjoys significant competitive advantages. Natural gas transmission and power
are complementary businesses for TCPL. They are driven by similar supply and
demand fundamentals, they are both capital intensive businesses, and use similar
technology and operating practices. They are businesses with significant
long-term growth prospects.
North American natural gas demand is growing and that demand is mainly driven
by the demand for electricity. Experts predict that demand for electricity will
increase at an average annual rate of approximately two per cent over the next
ten years primarily due to a growing population and an increase in gross
domestic product. A large part of that demand growth is expected to be met
through higher utilization of new gas-fired generating plants that were built as
part of the massive capacity additions that occurred in many North American
markets over the last five years.
Coal-fired plants are still the largest source of electric power in North
America and coal reserves are significant. Nuclear facilities have also played a
significant role in supplying North America with power in the past and new
nuclear capacity will likely come on stream over time.
M-2
However, the long lead times required to complete new coal and nuclear
projects, the associated environmental and public relations issues, the high
capital costs and the difficulty in locating these plants near load centres may
impede the development and completion of new coal or nuclear generation over the
next five to ten years. As a result, North America is expected to continue to
rely on natural gas-fired generation to satisfy its growing electricity needs in
the near term. This is expected to lead to a significant increase in natural gas
consumption. Overall, North American natural gas demand is expected to grow to
85 billion cubic feet per day (Bcf/d) by 2015, an increase of 15 Bcf/d when
compared to 2004. New natural gas-fired power generation is expected to account
for approximately 10 Bcf/d of that growth.
While growing demand will provide a number of opportunities, the natural gas
industry also faces a number of challenges. North America has entered a period
when it will no longer be able to rely solely on traditional sources of natural
gas supply to meet its growing needs. Current high natural gas prices are clear
evidence that North America is in a period of transition and significant change.
Natural gas supply is tight and this is likely to continue until major
investments are made in the infrastructure required to bring new supply to
market. Looking forward, production from North America's traditional basins is
expected to remain flat over the next decade. An increase in production in the
United States Rockies will likely only offset declines in other basins,
including the Gulf of Mexico. This outlook for traditional basins means that
northern gas and offshore liquefied natural gas (LNG) will be required to fill
the shortfall between supply and demand.
TCPL is well positioned in North America to serve growing power generation
demand in the near term and to bring new natural gas supply to market in the
medium to longer term.
TCPL'S STRATEGY
TCPL's strong position in North America is the direct result of successfully
executing its corporate strategy which was first adopted five years ago. While
the plan has evolved over time in response to actual and anticipated changes in
the business environment, it fundamentally remains the same. Today, TCPL's
corporate strategy consists of the following five components:
*
Grow the North American Gas Transmission business.
*
Maximize the long-term value of the Canadian wholly-owned Gas
Transmission business.
*
Grow the North American Power business.
*
Drive for operational excellence.
*
Maximize the corporate strength and value of TCPL.
GAS TRANSMISSION
TCPL's natural gas transmission assets link the Western Canada Sedimentary
Basin (WCSB) with premium North American markets. With more than 41,000
kilometres (km) of pipeline, the company's network of wholly-owned pipeline
assets is one of the largest in North America.
In 2004, the wholly-owned Alberta System gathered 64 per cent of the natural
gas produced in Western Canada or 16 per cent of total North American
production. TCPL exports gas from the WCSB to Eastern Canada and the U.S. West,
Midwest and Northeast through four wholly-owned systems - the Canadian Mainline,
the Gas Transmission Northwest System, the Foothills System and the BC System -
and six partially-owned systems - Trans Quebec & Maritimes System (TQM), Great
Lakes Gas Transmission System (Great Lakes), Iroquois Gas Transmission System
(Iroquois), Portland Natural Gas Transmission System (Portland), Northern Border
Pipeline (Northern Border) and Tuscarora Gas Transmission System (Tuscarora).
The company's strategy in Gas Transmission is focused on both growing its North
American natural gas transmission network and maximizing the long-term value of
its Canadian wholly-owned pipelines. In order to grow the Gas Transmission
business, TCPL is focusing its efforts on expanding and extending its existing
systems to connect new supply to growing markets, increasing its ownership in
partially-owned entities, acquiring other pipelines that provide it with a
significant regional presence and in the long term, connecting new sources of
supply in the form of northern gas and LNG.
The company's ability to successfully execute its strategy has been and
continues to be directly related to the core competencies that have been
developed in Gas Transmission.
M-3
Over the past 50 years, TCPL has developed significant expertise in
large-diameter, cold-weather natural gas pipeline design, construction,
operation and maintenance. It has also developed significant expertise in the
design, optimization and operation of large gas turbine compressor stations.
Today, TCPL operates one of the largest, most sophisticated, remote-controlled
pipeline networks in the world with a solid reputation for safety and
reliability. TCPL also has strong project development and management skills and
is committed as an organization to the highest levels of operational excellence.
The company's strong financial position allows it to build large-scale
infrastructure and act quickly on quality opportunities as they arise.
Significant milestones were achieved in the Gas Transmission business in 2004.
The acquisition of GTN is a prime example. The Gas Transmission Northwest System
consists of 2,174 km of pipeline extending from Kingsgate, British Columbia on
the B.C./Idaho border to Malin, Oregon on the Oregon/California border. It
interconnects with the BC System and Foothills System and transports WCSB
natural gas to growing markets in the Pacific Northwest, California and Nevada.
The North Baja System is a 128 km system that extends from Ehrenberg, Arizona to
a point near Ogilby, California on the California/Mexico border. In the future,
this line could be modified at relatively low cost to allow natural gas to flow
from LNG terminals in Baja, Mexico to markets in the U.S.
Looking north, TCPL has secured a position in the Mackenzie Gas Pipeline
Project and, in Alaska, it has assembled significant legal, technical and
environmental information. Foothills Pipe Lines Ltd. (Foothills) was granted
certificates for the Canadian portion of the Alaska Highway Pipeline Project
over 25 years ago. Certificates of Public Convenience and Necessity were granted
to Foothills under the Northern Pipeline Act of Canada (NPA). Foothills holds
the priority right to build, own and operate the first pipeline through Canada
for the transportation of Alaskan gas. This right was granted under the NPA,
following a lengthy competitive hearing before the NEB in the late 1970's, which
resulted in a decision in favour of Foothills. The NPA creates a single window
regulatory regime that is uniquely available to Foothills. It has been used by
Foothills to construct the facilities in Alberta which constitute a prebuild for
the Alaska Highway Pipeline Project, and to expand those facilities five times,
the latest of which was in 1998. Continued development under the NPA should
ensure the earliest in-service date for the project.
During 2004, to continue to move the Alaska Highway Pipeline Project forward,
the company filed an application under the State of Alaska's Stranded Gas
Development Act, which is the State's vehicle for dealing with fiscal
concessions and other matters related to this project. TCPL's application is one
of three applications currently before the State. As well, TCPL requested the
State to resume processing its long-pending application for a right-of-way lease
on State lands. TCPL holds the complementary rights-of-way on federal lands in
Alaska. In addition, the company continued discussions with a number of parties,
including Alaska North Slope producers, the State of Alaska, the government of
Canada and key players in the North American natural gas market.
If the Mackenzie Gas Pipeline Project and the Alaska Highway Pipeline Project
are constructed and connected to TCPL's existing infrastructure, they would
represent additional growth opportunities for TCPL and enhance the long-term
viability of the company's existing Gas Transmission business, especially the
Canadian wholly-owned pipelines.
In 2004, TCPL also took steps to advance a number of LNG projects. TCPL is of
the view that LNG will play a significant role in meeting growing North American
gas demand. Based on North American natural gas prices, the company believes
that Eastern Canada and the Northeast U.S., where natural gas sells at a
premium, are logical locations to import LNG. TCPL is currently assessing a
number of long-term opportunities in these regions including the Cacouna Energy
Project in Quebec and the Broadwater Energy Project in New York. In general, LNG
projects may experience siting challenges.
TCPL's focus on these projects is on the regasification terminal and related
pipeline infrastructure that complements and supports the company's existing
pipeline investments.
The company's initiatives in the natural gas storage business are a logical
extension of its Gas Transmission business. TCPL believes Alberta-based natural
gas storage will continue to serve market needs and could play an important role
should northern gas be connected to North American markets. In January 2005,
TCPL announced plans to develop a natural gas storage facility near Edson,
Alberta. The Edson facility will have a capacity of approximately 50 Bcf and
connect to TCPL's Alberta System. In addition, in 2004, the company secured a
long-term contract with a third party for existing Alberta-based natural gas
storage capacity, ramping up from approximately 20 Bcf in 2005 to 30 Bcf in 2006
and to 40 Bcf in 2007. These initiatives, combined with the company's current 60
per cent ownership interest in CrossAlta,
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position TCPL to become one of the largest natural gas storage providers in
Western Canada with 110 Bcf of storage capacity by 2007 which will represent
approximately one-third of the natural gas storage capacity available in
Alberta.
In addition to growing the North American Gas Transmission business, the
company continues to place a strategic priority on maximizing the long-term
value of its Canadian wholly-owned pipelines. Efforts in this area are focused
on achieving a fair return on invested capital and streamlining and harmonizing
processes and tariff provisions for and among TCPL's regulated pipelines.
Further, the company continues to respond to changes in the market by
introducing new services to meet customer needs.
In 2004, TCPL received a number of regulatory decisions from the NEB and the
EUB with mixed results. TCPL was generally pleased with the NEB's decision on
the 2004 Canadian Mainline Tolls and Tariff Application (2004 Application) Phase
I and its decision to approve North Bay Junction (NBJ) as a new receipt and
delivery point, which TCPL views as forward steps in ensuring the long-term
sustainability of the Canadian Mainline to the benefit of all stakeholders.
However, two decisions from the EUB in 2004 related to the Alberta System were
disappointing.
In July 2004, the EUB released its decision in the GCOC proceeding. All Alberta
provincially regulated utilities, including the Alberta System, were mandated an
ROE of 9.60 per cent for 2004. This generic ROE will be adjusted annually by 75
per cent of the change in long-term Government of Canada bonds from the previous
year, consistent with the approach used by the NEB. The EUB also established a
deemed common equity of 35 per cent for the Alberta System. This result was
significantly less than the applied for ROE of 11 per cent on deemed common
equity of 40 per cent, which the company considered to be a fair return.
In September 2003, TCPL filed Phase I of the 2004 GRA with the EUB, consisting
of evidence in support of the applied-for rate base and revenue requirement. In
its August 24, 2004 decision, the EUB approved the purchase of the Simmons
Pipeline System (Simmons) for approximately $22 million and the costs of firm
transportation (FT) service arrangements with the Foothills, Simmons and
Ventures LP systems. However, a significant amount of costs were disallowed for
recovery, which reduced revenue requirement and rate base.
In September 2004, TCPL filed with the Alberta Court of Appeal for leave to
appeal the EUB's decision on Phase I of the 2004 GRA with respect to the
disallowance of applied-for incentive compensation costs. In its decision, the
EUB disallowed approximately $24 million (pre tax) of operating costs, which
included $19 million of applied-for incentive compensation costs. TCPL believes
the EUB made errors of law in deciding to deny the inclusion of these
compensation-related costs in the revenue requirement. The company believes
these are necessary costs that it reasonably and prudently incurs for the safe,
reliable and efficient operation of the Alberta System. At the request of TCPL,
the Alberta Court of Appeal adjourned the appeal for an indefinite period of
time while TCPL considers the merits of a review and variance application to the
EUB in respect of 2004 costs. On February 24, 2005, TCPL advised the EUB that an
agreement in principle had been reached with negotiating parties on a revenue
requirement settlement for the period January 1, 2005 to December 31, 2007. The
agreement is subject to formal approval by participating parties, and ultimately
by the EUB.
In 2004, TCPL applied for an allowed return for the Canadian Mainline based on
the NEB's ROE formula on a 40 per cent deemed common equity. An NEB decision is
expected in second quarter 2005.
On February 14, 2005, TCPL announced it had reached a settlement with its
Canadian Mainline shippers regarding 2005 tolls. This settlement establishes
operating, maintenance and administration (OM&A) costs for 2005 at $169.5
million, which is comparable to the 2004 level. Any variance between actual OM&A
costs in 2005 and those agreed to in the settlement will accrue to TCPL. All
other cost elements of the 2005 revenue requirement will be treated on a flow
through basis. Further, the 2005 ROE for the Canadian Mainline will be 9.46 per
cent as determined under the NEB formula, and the common equity component of the
Canadian Mainline's capital structure for 2005 shall be based on the NEB's
decision in the recently concluded hearing on the Canadian Mainline's cost of
capital for 2004, subject to the outcome of any review applications or appeals.
In February 2005, TCPL announced that it is proposing a US$1.7 billion oil
pipeline project to transport approximately 400,000 barrels per day of heavy
crude oil from Alberta to Illinois. The proposed Keystone Pipeline (Keystone)
would be approximately 3,000 km in length. In addition to new pipeline
construction, Keystone would require the conversion of approximately 1,240 km of
one of the lines in TCPL's existing multi-line natural gas pipeline systems in
Alberta, Saskatchewan and Manitoba.
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TCPL will continue to meet with oil producers, refiners and industry groups,
including the Canadian Association of Petroleum Producers, to gauge additional
interest and support for Keystone. Preliminary discussions have begun with
stakeholders, including communities, government representatives and landowners
along the proposed route. TCPL will proceed with the necessary regulatory
applications when sufficient support for this project from oil producers and
shippers is obtained.
TCPL will require various regulatory approvals from Canadian and U.S. agencies
before construction can begin. Input from all stakeholders will be received
through the regulatory process and an extensive public consultation process.
TCPL is in the business of connecting energy supplies to markets and it views
this opportunity as another way of providing a valuable service to its
customers. Converting one of the company's natural gas pipeline assets for oil
transportation is an innovative, cost-competitive way to meet the need for
pipeline expansions to accommodate anticipated growth in Canadian crude oil
production during the next decade.
POWER
TCPL has built a substantial power business over the last ten years. Currently,
the power plants and power supply that TCPL owns, operates and/or controls,
including those under construction or in development, in the aggregate,
represent approximately 5,700 megawatts (MW) of power generation capacity in
Canada and the U.S. The company's physical assets are concentrated in two main
regions - one in the west, the other in the east. The western business is
focused in Alberta where TCPL is one of the largest providers of wholesale power
in the province. Assets include five gas-fired cogeneration plants and power
purchase arrangements (PPAs) at the Sundance A and B coal-fired plants. In the
east, the focus has been on the Ontario, Quebec, New England and New York
markets. The company started with a minority interest in Ocean State Power
(OSP), a 560 MW gas-fired plant in Rhode Island. In Ontario, TCPL began by
developing three natural gas-fired plants adjacent to compressor stations along
the Canadian Mainline. Today, through its investments, TCPL is the largest
private sector generator in Ontario.
TCPL's strategy for growth and value creation in Power has been driven by four
main principles.
First, the company has focused its efforts on acquiring low-cost, base-load
generation in markets it knows. PPA entitlements at the Sundance A and B
coal-fired plants in Alberta, its investment in Bruce Power and the pending
acquisition of USGen New England (USGen) are prime examples of this approach.
The company believes that being a low-cost provider and/or having long-term
power sales contracts is critical to being successful in the power business.
Second, TCPL has focused on developing low-risk, greenfield, gas-fired
cogeneration projects. Although higher on the cost curve than hydro, nuclear or
coal, they are much more efficient than various other forms of generation
including combined-cycle gas-fired plants. To reduce the risk associated with
these higher cost sources of production, TCPL has focused on selling a
significant portion of the output from these plants to strong counterparties
under long-term contracts where the buyer also assumes the risk associated with
fluctuations in the natural gas price. The Grandview and Becancour projects are
examples of this approach.
Third, TCPL actively participates in markets that are in transition. The
changes that took place in New England and Alberta, and the changes that
continue in Ontario, allow the company to capture opportunities that are created
as a result of markets in transition.
Lastly, TCPL has focused its attention on optimizing its existing asset
portfolio by running the company's facilities as efficiently and
cost-effectively as possible through its drive for operational excellence.
TCPL's ability to successfully execute its strategy is directly related to the
core competencies that it has developed in the power business. Over the years,
the company has gained a broad understanding of North American energy markets
and a deep understanding of its core markets in Alberta, Ontario, Quebec, and
the Northeastern U.S. It has been an active participant in deregulated markets.
The experience gained in its core markets serves the company well as it pursues
opportunities in those and other areas. TCPL uses its ability to structure deals
and manage risk which is critical to mitigating volatility and uncertainty for
its industrial customers and its shareholders. TCPL's financial position allows
it to build large-scale infrastructure and gives it the ability to act quickly
on quality opportunities as they arise. The company has strong project
development skills and is committed as an organization to operational
excellence.
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In 2004, TCPL continued to add to its diverse portfolio of quality power
generation assets.
In addition to the completion of the restart of Unit 3 at Bruce Power and the
commissioning of the MacKay River cogeneration plant in 2004, the company also
completed construction of the Grandview facility, a 90 MW natural gas-fired
cogeneration power plant located in Saint John, New Brunswick. All of the power
and heat output from the Grandview plant will be sold to Irving Oil Limited
under a 20 year PPA. The company also continued to make progress on the new 550
MW Becancour natural gas-fired cogeneration plant, which is located near
Trois-Rivieres, Quebec. All of the power output from that plant will be sold
under a 20 year PPA to Hydro-Quebec Distribution (Hydro-Quebec). Final approvals
for this project were received in July 2004 and construction has commenced. It
is scheduled to be in-service in late 2006.
In October 2004, TCPL announced that Cartier Wind Energy (Cartier Wind), owned
62 per cent by TCPL, was awarded six projects by Hydro-Quebec representing a
total of 739.5 MW. Long-term electricity supply contracts were signed with
Hydro-Quebec on February 25, 2005 for each of the facilities. The six projects
are expected to be commissioned between 2006 and 2012 at an estimated total
capital cost of more than $1.1 billion.
In December 2004, TCPL announced it would proceed with the purchase of
hydroelectric generation assets with a total generating capacity of 567 MW from
USGen for US$505 million. The assets include generating assets on two river
systems in New England. The purchase is subject to the sale of the 49 MW Bellows
Falls hydroelectric facility to the Vermont Hydroelectric Power Authority
(Vermont Hydroelectric), which has exercised its pre-existing option to purchase
this plant. This would result in a US$72 million reduction in the purchase price
to US$433 million for 518 MW.
TCPL is well positioned to play a role in helping Ontario meet its future
energy needs. The Ontario government has estimated that $25 billion to $40
billion of capital investment will be required to refurbish, rebuild, replace or
conserve 25,000 MW of generating capacity by 2020. Bruce Power, 31.6 per cent
owned by TCPL, continues to evaluate the feasibility of restarting Units 1 and 2
and talks between Bruce Power and a provincially appointed negotiator regarding
the potential restart of the two 750 MW units are ongoing. TCPL also submitted
proposals to the Ontario government under its recent request-for-proposal
process that seeks up to 2,500 MW of new electricity generation capacity and/or
conservation measures. This power is expected to come on-line between 2005 and
2009.
TCPL, together with its Bruce Power partners, is also evaluating a potential
investment in the refurbishment of the 680 MW Point Lepreau nuclear generating
station in New Brunswick. Discussions are currently ongoing with New Brunswick
Power.
TCPL expects its Power business to continue to be a key growth driver in the
years ahead. The company is committed to growing the Power business through
asset acquisitions, selected greenfield developments and further expansions of
its existing business and footprint. The goal is to build and establish a
diverse portfolio of high quality assets that deliver strong returns to TCPL's
shareholders.
OPERATIONAL EXCELLENCE AND "SPIRIT"
In addition to growing its Gas Transmission and Power businesses, TCPL is
committed to an operational excellence business model. Its focus is on being a
cost-conscious, reliable and safe operator, providing desired services to its
customers in an effective and timely manner. The company's values guide the way
business is conducted at TCPL. Within TCPL, these values are commonly referred
to as "SPIRIT". They are the principles that direct how the company works and
they include - Social responsibility, Passion, Integrity, Results, Innovation
and Teamwork. The company's commitment to these values helps ensure it maintains
its reputation as one of North America's premier energy companies.
TCPL has approximately 2,450 employees who through their talent, hard work and
results provide the company a strong competitive advantage because of their
industry-leading expertise in pipeline and power operations, project management,
depth of market and industry knowledge, and financial acumen.
OUTLOOK
In 2005, TCPL will continue to execute its corporate strategy in a disciplined
and focused manner by directing its energies towards long-term growth
opportunities that will strengthen its financial performance and create
long-term value for
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shareholders. The company's 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.
In Gas Transmission, the company will continue to focus its efforts on
expanding and extending its existing systems to connect new supply to growing
markets, increasing its ownership in partially-owned entities, acquiring other
pipelines that provide it with a significant regional presence and connecting
new sources of supply in the form of northern gas and LNG. The company will also
focus on maximizing the long-term value of its Canadian wholly-owned natural gas
pipelines.
In 2005, there will be a full year's contribution from GTN, which was acquired
on November 1, 2004. The company expects lower allowed ROEs and lower average
investment bases for both the Canadian Mainline and the Alberta System. The
outcome of customer settlement negotiations and regulatory proceedings could
have a significant positive or negative impact on earnings from the Gas
Transmission segment in 2005.
In the Power business, the company will continue to focus on acquiring
low-cost, base-load generation, developing low-risk greenfield cogeneration
projects, capitalizing on opportunities in markets that are in transition and
optimizing its existing asset portfolio.
The potential variability in Bruce Power's earnings caused by changes in prices
realized, operating expenses, and plant availability, and the outcome of a
fourth arbitration related to the cost of fuel gas for OSP expected by the end
of third quarter 2005 could impact earnings in 2005.
A $1.00 per megawatt hour (MWh) change in the spot price for electricity in
Ontario would change TCPL's after-tax equity income from Bruce Power by
approximately $5 million. Bruce Power operating expenses are expected to
increase in 2005 due to higher outage costs, higher depreciation on the Bruce A
units and recent capital programs and higher fuel costs. The average
availability in 2005 for Bruce Power is expected to be 85 per cent compared to
82 per cent in 2004.
In 2004, as a result of a third arbitration process, OSP's cost of fuel gas was
substantially increased to a price in excess of market. Should a fourth
arbitration decision at OSP, expected in 2005, continue to support a pricing
mechanism for fuel gas in excess of market price and if anticipated market
conditions do not change substantially, management expects there could be an
asset impairment write-down of this facility. The net carrying value of OSP at
December 31, 2004 was approximately US$150 million.
The sale of the Curtis Palmer and ManChief plants in April 2004 results in the
loss of earnings from these plants for a full year in 2005. The Grandview
cogeneration plant and the proposed acquisition of the USGen assets are expected
to have a positive impact on 2005 earnings from the Power segment. In addition,
plant availability, fluctuating market prices, weather and regulatory decisions
could impact earnings.
In 2004, income tax and foreign exchange related items and the release of a
previously established restructuring provision had a significantly positive
impact on the results of the Corporate segment. In 2005, the Corporate segment
is expected to incur a more normalized level of net expenses with higher net
expenses than in 2004.
GAS TRANSMISSION
HIGHLIGHTS
Net Earnings Net earnings from Gas Transmission decreased $36 million to $586
million in 2004 compared to $622 million in 2003.
This decrease is primarily due to a $40 million decrease from the Alberta
System and an $18 million decrease from the Canadian Mainline offset by a $14
million increase due to the acquisition of GTN.
Canadian Mainline The NEB, in its decision on Phase 1 of the 2004 Application,
approved virtually all applied-for costs, as well as a new non-renewable firm
transportation (FT-NR) service.
In December, the NEB approved TCPL's application to establish the North Bay
Junction as a new receipt and delivery point on the Canadian Mainline.
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Alberta System In July 2004, TCPL received a decision from the EUB on the GCOC
proceeding which established an ROE of 9.60 per cent for all Alberta utilities
for 2004 and an equity thickness for the Alberta System of 35 per cent.
The EUB disallowed approximately $24 million pre tax of operating costs
associated with the operation of the Alberta System in its decision on Phase I
of the 2004 GRA which dealt with revenue requirement and rate base.
Simmons became part of the Alberta System on October 1, 2004.
GTN On November 1, 2004, TCPL acquired GTN which is a high-quality, reliable
operation that exemplifies the company's growth strategy.
GTN contributed $14 million of earnings for the two months ended December 31,
2004.
Other Gas Transmission In 2004, TCPL announced plans to develop two new LNG
facilities, one in Cacouna, Quebec, and one offshore in the New York State
waters of Long Island Sound.
In June 2004, TCPL filed an application under the Alaska Stranded Gas
Development Act and proceeded to process its application with the State of
Alaska for a right-of-way across State lands for the Alaska Highway Pipeline
Project.
TCPL continued to fund the Aboriginal Pipeline Group's (APG) participation in
the Mackenzie Gas Pipeline Project.
TCPL entered into arrangements that will increase TCPL's natural gas storage
capacity in Alberta commencing in 2005. In January 2005, it announced plans to
develop a $200 million natural gas storage project near Edson, Alberta.
GAS TRANSMISSION NET EARNINGS-AT-A-GLANCE
Year ended December 31 (millions of dollars)
2004 2003 2002
Wholly-Owned Pipelines
Canadian Mainline 272 290 307
Alberta System 150 190 214
GTN1 14
Foothills System2 22 20 17
BC System 7 6 6
465 506 544
Other Gas Transmission
Great Lakes 55 52 66
Iroquois 17 18 18
TC PipeLines, LP 16 15 17
Portland3 10 11 2
Ventures LP 15 10 7
TQM 8 8 8
CrossAlta 13 6 13
TransGas 11 22 6
Northern Development (6 ) (4 ) (6 )
General, administrative, support costs and other (18 ) (22 ) (22 )
121 116 109
Net earnings 586 622 653
(1)
TCPL acquired GTN on November 1, 2004. Amounts in this table reflect TCPL's
100 per cent ownership interest in GTN's net earnings from the acquisition
date.
(2)
The remaining ownership interests in the Foothills System, previously not
held by TCPL, were acquired on August 15, 2003. Amounts in this table
reflect TCPL's proportionate interest in Foothills' net earnings prior to
acquisition and 100 per cent interest thereafter.
(3)
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 net
earnings from Portland.
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In 2004, net earnings from the Gas Transmission business were $586 million
compared to $622 million and $653 million in 2003 and 2002, respectively. The
decrease in 2004 compared to 2003 was mainly due to lower net earnings from
Wholly-Owned Pipelines, partially offset by higher net earnings from Other Gas
Transmission. The 2004 decrease in Wholly-Owned Pipelines' net earnings was
primarily due to a reduction in the Alberta System's net earnings of $40
million, reflecting the EUB's disallowance of certain operating costs in its
decision on Phase I of the 2004 GRA and in its decision in the GCOC proceeding
to allow an ROE in 2004 lower than the return implicit in the 2003 revenue
requirement settlement with stakeholders. In addition, net earnings on the
Canadian Mainline were lower by $18 million in 2004 compared to 2003 due to a
decline in both the average investment base and the allowed ROE. The addition of
GTN had a positive effect on 2004 net earnings. Higher 2004 net earnings from
Other Gas Transmission were primarily due to increased earnings from CrossAlta
and Ventures LP and a $7 million gain on sale of Millennium, partially offset by
the negative impact of a weaker U.S. dollar.
The overall decrease of $31 million in 2003 Gas Transmission net earnings
compared to 2002 was mainly due to higher incremental earnings in 2002 due to
the NEB's Fair Return decision in 2002 and lower investment bases in 2003.
GAS TRANSMISSION - EARNINGS ANALYSIS
Canadian Mainline The Canadian Mainline is regulated by the NEB. The NEB sets
tolls which provide TCPL the opportunity to recover projected costs of
transporting natural gas and provide a return on the Canadian Mainline's average
investment base. New facilities are approved by the NEB before construction
begins. Changes in investment base, the ROE, the level of deemed common equity
and the potential for incentive earnings affect the net earnings of the Canadian
Mainline.
The Canadian Mainline generated net earnings of $272 million in 2004, a
decrease of $18 million and $35 million, respectively, when compared to 2003 and
2002 earnings. The decrease in net earnings in 2004 from 2003 is primarily due
to a decline in average investment base and allowed ROE. The NEB-approved ROE
decreased to 9.56 per cent in 2004 from 9.79 per cent in 2003. The reduction in
net earnings from $307 million in 2002 to $290 million in 2003 is due to the
combined effect of a lower average investment base and recognition of
incremental earnings in 2002 as a result of the NEB's June 2002 Fair Return
decision in which it increased the deemed common equity ratio to 33 per cent
from 30 per cent effective January 1, 2001. This decision resulted in additional
net earnings of $16 million for the year ended December 31, 2001, which the
company recognized in 2002.
Alberta System The Alberta System is regulated by the EUB primarily under
the provisions of the Gas Utilities Act (Alberta) (GUA) and the Pipeline Act
(Alberta). Under the GUA, its rates, tolls and other charges, and terms and
conditions of service are subject to approval by the EUB.
Net earnings of $150 million in 2004 were $40 million lower than 2003 and $64
million lower than 2002. These decreases were primarily due to the impacts of
the EUB decisions in respect of Phase I of the 2004 GRA in August 2004 and on
the GCOC proceeding in July 2004. In the 2004 GRA Phase I decision, the EUB
disallowed approximately $24 million of operating costs associated with the
operation of the pipeline. In addition, the GCOC decision resulted in a lower
return on deemed common equity in 2004 compared to the earnings implicit in the
2003 and 2002 negotiated settlements which included fixed revenue requirement
components, before non-routine adjustments, of $1.277 billion and $1.347
billion, respectively. Net earnings in 2004 reflect a return of 9.60 per cent on
deemed common equity of 35 per cent as approved in the GCOC decision. The
negative impact of the two EUB decisions on 2004 net earnings was partially
offset by lower operating costs.
GTN GTN is regulated by the U.S. Federal Energy Regulatory Commission (FERC),
which has authority to regulate rates for natural gas transportation in
interstate commerce. Both the Gas Transmission Northwest System and the North
Baja System operate under fixed rate models, under which maximum and minimum
rates for various service types have been ordered by the FERC and under which
GTN is permitted to discount or negotiate rates on a non-discriminatory basis.
The Gas Transmission Northwest System's last filed rate case was in 1994 and it
was settled and approved by the FERC in 1996. The North Baja System's rates were
established in the FERC's initial order in 2002 certifying construction and
operation of the system. The net earnings of GTN are impacted by variations in
volumes delivered under the various service types that are provided, as well as
by variations in the costs of providing transportation service. Net earnings
were $14 million for the two months ended December 31, 2004.
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Other Gas Transmission TCPL's direct and indirect investments in various
natural gas pipelines and gas transmission related businesses are included in
Other Gas Transmission. It also includes project development activities related
to TCPL's pursuit of new pipeline and natural gas transmission related
opportunities throughout North America, including northern gas and LNG.
TCPL's net earnings from Other Gas Transmission in 2004 were $121 million
compared to $116 million and $109 million in 2003 and 2002, respectively. The
increased net earnings of $5 million in 2004 compared to 2003 were due to higher
earnings from CrossAlta, reflecting favourable natural gas storage market
conditions in Alberta, higher earnings from Ventures LP as a result of an
expansion that was completed in 2003 and higher earnings from Great Lakes as a
result of successful marketing of short-term services. In addition, a $7 million
gain was recorded on the sale of the company's equity interest in Millennium in
2004. These increases were partially offset by the impact of a weaker U.S.
dollar and higher general, administrative and support costs. Earnings for 2003
also included a positive $11 million tax adjustment for TransGas.
GAS TRANSMISSION - OPPORTUNITIES AND DEVELOPMENTS
GTN Acquisition TCPL acquired GTN on November 1, 2004 for approximately US$1.2
billion, excluding assumed debt of approximately US$0.5 billion. The acquisition
of GTN complements TCPL's long-term commitment to serve the Pacific Northwest
and California markets, which the company has advanced over the past few years
with its 2002 West Path expansion and the purchase of the remaining interests in
Foothills in 2003 that it previously did not own. GTN consists of two interstate
pipeline systems: the Gas Transmission Northwest System, a 2,174 km pipeline
extending from Kingsgate, B.C. on the B.C./Idaho border to Malin, Oregon on the
Oregon/California border; and the North Baja System, a 128 km system that
extends from Ehrenberg, Arizona to a point near Ogilby, California on the
California/Mexico border. The North Baja System is well positioned to provide
natural gas transportation services from LNG regasification terminals currently
planned to be constructed on the coast of northern Baja California, Mexico.
Simmons Acquisition In October 2004, TCPL acquired Simmons for approximately
$22 million. The assets include 380 km of pipeline and metering facilities and
four compressor units located in northern Alberta. The system has a capacity of
approximately 185 MMcf/d. Simmons delivers natural gas to the Fort McMurray area
from several connecting receipt points within the Alberta System, along with
production connected directly to the pipeline. Continued development of oil
sands resources is expected to increase the demand for natural gas in the Fort
McMurray area, as oil sands production requires natural gas supply for hydrogen
feedstock, power generation and fuel.
Iroquois In February 2004, the Iroquois pipeline began commercial operation of
its Eastchester expansion. The expansion was the first major natural gas
transmission pipeline to be built into New York City in approximately 40 years.
In January 2004, Iroquois filed a rate application with the FERC to establish
rates for the Eastchester expansion. Iroquois received approval from the FERC in
October 2004 of its comprehensive settlement agreement, which implements an
eight year rate moratorium for Eastchester. In addition to settling the
Eastchester recourse rates, Iroquois also entered into negotiated rate
agreements with all of the initial shippers on the Eastchester project.
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Portland In August 2004, Portland initiated a restructuring plan whereby all
of its operating and administrative functions would be performed by TCPL
pursuant to service agreements. The transition of duties was completed by
December 2004.
Supply In 2004, primary supply growth within the WCSB came from northeastern
B.C. and the west central foothills area of Alberta. TCPL attracted incremental
volumes from the Sierra discovery in B.C. through the new Ekwan receipt
connection and incremental supply from the emerging Cutbank Ridge discovery in
B.C. In Alberta, TCPL saw increased incremental volumes from the central
foothills area as well as unconventional production from coalbed methane (CBM),
primarily from Horseshoe Canyon coal located in the central Alberta area between
Edmonton and Calgary.
TCPL continues to pursue the most cost effective and timely connection of these
volumes, which allows TCPL's customers to take advantage of continued premium
gas price environments. TCPL will continue to grow by seeking new opportunities
to connect additional gas supplies.
Western Markets TCPL continues to pursue growth opportunities within
existing and new natural gas markets. In 2004, TCPL further executed its
strategy to provide cost effective incremental delivery service into the growing
Fort McMurray, Alberta market. The acquisition of Simmons was approved by the
EUB and the costs of acquiring these assets were added to the Alberta System
rate base. The Alberta System's new arrangement for transportation service with
Ventures LP was also approved and this service commenced on October 1, 2004.
TCPL has also negotiated an arrangement with Husky Oil for transportation
service on the Kearl Lake Pipeline that will provide the Alberta System an
additional 110 MMcf/d delivery capacity. The fast growing production from
oil-sands supply in Fort McMurray has also driven expansion in the refining
sector of east Edmonton. As a result, TCPL has negotiated an arrangement for
transportation service with ATCO Pipelines (ATCO) that will allow TCPL to
provide incremental delivery service into the industrial market east of
Edmonton. Both the Husky Kearl Lake and ATCO transportation service arrangements
are included in the 2005 GRA.
Eastern Markets Demand for natural gas continues to be strong in Eastern
Canada and Northeast U.S. markets as reflected by the response to several open
seasons held on TCPL's Canadian Mainline. Power generation continues to be the
primary driver for incremental natural gas demand in these markets. Ontario and
Quebec markets continue to develop power projects that require significant
incremental natural gas volumes.
Customer behaviour continues to reinforce contract repositioning from long haul
to short haul transportation and TCPL seeks to address these market needs. To
that end, TCPL proposed a new contracting point near North Bay, Ontario to
provide customers with additional flexibility. The NEB approval of the NBJ
Application in 2004 means the market now has an additional short haul
contracting option available.
Northern Development In 2004, TCPL continued to pursue pipeline
opportunities to move both Mackenzie Delta and Alaska North Slope natural gas to
markets throughout North America.
TCPL, the Mackenzie Delta gas producers and the APG reached funding and
participation agreements in June 2003 that secured a role for TCPL in the
proposed Mackenzie Gas Pipeline Project and the APG to become an equity
participant. This project would result in a natural gas pipeline being
constructed from Inuvik, Northwest Territories to the northern border of
Alberta, where it would connect with the Alberta System. TCPL has agreed to
finance the APG for its one-third share of project development costs. This share
is currently expected to be approximately $90 million. The loan will be repaid
from the APG's share of available future pipeline revenues. TCPL funded $26
million of this loan in 2004, for a total of $60 million to December 31, 2004.
The ability to recover this investment is dependent upon the outcome of the
project. Under the terms of the agreement, 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.
In October 2004, Imperial Oil Resources applied for the main regulatory
approvals for the Mackenzie Gas Pipeline Project. These were submitted to the
boards, panels and agencies responsible for assessing and regulating energy
developments in the Northwest Territories. These filings mark a significant
milestone in the project definition phase.
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TCPL will continue to support the project through its position established under
the various project agreements and to facilitate the interconnection of
Mackenzie Delta natural gas into the Alberta System.
In 2004, TCPL continued its discussions with Alaska North Slope producers and
the State of Alaska relating to the Alaskan portion of the Alaska Highway
Pipeline Project. In June 2004, TCPL filed an application under the State of
Alaska's Stranded Gas Development Act and requested the State resume processing
of its long-pending application for a right-of-way lease across State lands.
Once the right-of-way lease application is approved, TCPL is prepared to convey
the lease to another entity if that entity is willing to connect with TCPL's
pipeline system. The lease conveyance would require an interconnection agreement
with TCPL at the Yukon/Alaska border. TCPL's application is one of three
applications currently before the State.
Foothills holds the priority right to build, own and operate the first pipeline
through Canada for the transportation of Alaskan gas. This right was granted
under the NPA, following a lengthy competitive hearing before the NEB in the
late 1970's, which resulted in a decision in favour of Foothills. The NPA
creates a single window regulatory regime that is uniquely available to
Foothills. It has been used by Foothills to construct the facilities in Alberta
which constitute a prebuild for the Alaska Highway Pipeline Project, and to
expand those facilities five times, the latest of which was in 1998. Continued
development under the NPA should ensure the earliest in-service date for the
project.
LNG In September 2004, TCPL and Petro-Canada signed a Memorandum of
Understanding to develop an LNG facility, Cacouna Energy, in Cacouna, Quebec.
TCPL and Petro-Canada will each own 50 per cent of the facility and TCPL will
operate the facility, while Petro-Canada will contract for all of the capacity
and supply the LNG. The proposed facility would be capable of receiving, storing
and regasifying imported LNG with an average annual send-out capacity of
approximately 500 MMcf/d of natural gas. The estimated cost of construction is
$660 million. Construction of the facility is subject to regulatory approval
from federal, provincial and municipal governments which is expected to take
approximately two years. If approval is received, the facility is expected to be
in-service towards the end of this decade.
In November 2004, TCPL and Shell US Gas & Power LLC (Shell) announced plans to
jointly develop an offshore LNG regasification terminal, Broadwater Energy, in
the New York State waters of Long Island Sound. The proposed floating storage
and regasification unit would be located approximately 15 km off the Long Island
coast and 18 km off the Connecticut coast. The proposed terminal would be
capable of receiving, storing and regasifying imported LNG with an average
send-out capacity of approximately one Bcf/d of natural gas. Broadwater Energy
LLC, an entity which will be owned 50 per cent by TCPL, will own and operate the
facility, while Shell will contract for all of the capacity and supply the LNG.
The estimated cost of construction is expected to be approximately US$700
million. Construction of the facility is subject to regulatory approval from
U.S. federal and state governments. The regulatory approval process is expected
to take approximately two to three years. TCPL and Shell have filed a request
with the FERC to initiate a six to nine month public review of the Broadwater
proposal. Provided the necessary approvals are received, it is expected the
facility will be in-service in late 2010.
In a referendum held in March 2004, the residents of Harpswell, Maine voted
against leasing a town-owned site to build the Fairwinds LNG regasification
facility. As a result, TCPL and its partner, ConocoPhillips Company, have
suspended further work on this LNG project.
Natural Gas Storage In September 2004, TCPL entered into long-term
arrangements, commencing in second quarter 2005, for approximately 20 Bcf of
additional natural gas storage capacity in Alberta. The capacity under contract
increases to approximately 30 Bcf in 2006 and approximately 40 Bcf in 2007.
In January 2005, TCPL announced that it is developing a $200 million natural
gas storage project near Edson, Alberta. The Edson facility will have a capacity
of approximately 50 Bcf and will connect to TCPL's Alberta System. Storage
capacity is expected to be available from the Edson facility commencing in
second quarter 2006, on a phased-in basis.
These developments, combined with the company's investment in the CrossAlta
natural gas storage facility, position TCPL to become one of the largest natural
gas storage providers in Western Canada. Upon completion of the Edson facility,
TCPL will own or control more than 110 Bcf, or approximately one-third, of the
storage capacity in Alberta at that time. Current market fundamentals for
natural gas storage are strong. The imbalance in North American natural gas
supply and demand has created natural gas price volatility, resulting in demand
for storage service. TCPL believes
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Alberta-based storage will continue to serve market needs and could play an even
more important role when northern gas is connected to North American markets.
Oil Pipeline In February 2005, TCPL announced that it is proposing a US$1.7
billion oil pipeline project to transport approximately 400,000 barrels per day
of heavy crude oil from Alberta to Illinois. The proposed Keystone project would
be approximately 3,000 km in length. In addition to new pipeline construction,
it would require the conversion of approximately 1,240 km of one of the lines in
TCPL's existing multi-line natural gas pipeline systems in Alberta, Saskatchewan
and Manitoba.
TCPL will continue to meet with oil producers, refiners and industry groups,
including the Canadian Association of Petroleum Producers, to gauge additional
interest and support for Keystone. Preliminary discussions have begun with
stakeholders, including communities, government representatives and landowners
along the proposed route. When sufficient support for this project from oil
producers and shippers is obtained, TCPL will proceed with the necessary
regulatory applications. TCPL will require various regulatory approvals from
Canadian and U.S. agencies before construction can begin.
TCPL is in the business of connecting energy supplies to markets and it views
this opportunity as another way of providing a valuable service to its
customers. Converting one of the company's natural gas pipeline assets for oil
transportation is an innovative, cost-competitive way to meet the need for
pipeline expansions to accommodate anticipated growth in Canadian crude oil
production during the next decade.
GAS TRANSMISSION - REGULATORY DEVELOPMENTS
In 2004, TCPL's principal regulatory activities included the appeal to the
Federal Court of Appeal (FCA) of the NEB's February 2003 decision on TCPL's
September 2002 application to review and vary its decision on the fair return
for the Canadian Mainline in 2001 and 2002 issued in June 2002; the EUB's GCOC
proceeding; the 2004 Application; Phase I and II of the Alberta System's 2004
GRA; and the NBJ proceeding. TCPL also filed the Alberta System's 2005 GRA-Phase
I application. On February 24, 2005, TCPL advised the EUB that it had reached
an agreement in principle for the Alberta System with negotiating parties and
requested a suspension of the established regulatory timetable for adjudication
of the 2005 GRA pending its finalization of the contemplated settlement
agreement. On February 25, 2005, the EUB granted this request. In February 2005,
TCPL reached a settlement with its Canadian Mainline shippers regarding 2005
tolls.
CANADIAN MAINLINE
In February 2003, the NEB denied TCPL's September 2002 request for a Review and
Variance of the Fair Return decision. TCPL maintained that the Fair Return
decision issued in June 2002 did not recognize the long-term business risks of
the Canadian Mainline, which led to an appeal of this decision with the FCA. In
May 2003, the FCA granted TCPL leave to appeal the NEB's February 2003 decision.
In April 2004, the FCA dismissed TCPL's appeal of the NEB's Fair Return Review
and Variance decision, while endorsing TCPL's view of the law relating to the
determination of a fair return by the NEB.
In September 2003, TCPL filed an application to define a new receipt and
delivery point near NBJ to better satisfy market requirements. A December 2004
NEB decision approved NBJ as a new contracting point.
In January 2004, TCPL filed its 2004 Application with the NEB, which included a
request for approval of an 11 per cent ROE on deemed common equity of 40 per
cent. Given the then pending appeal to the FCA on return issues, the NEB decided
to hear the application in a two-phase proceeding, with all matters except cost
of capital to be considered in the first phase. In its Phase I decision issued
in September 2004, the NEB approved virtually all applied-for costs and the new
FT-NR. Upon receipt of the FCA's decision dismissing TCPL's appeal in April
2004, TCPL amended its application to an ROE of 9.56 per cent, as determined
under the NEB's generic ROE formula, on deemed common equity of 40 per cent. The
NEB proceeded to consider cost of capital in the second phase of the proceeding
which commenced in November 2004 and continued into 2005. A decision is expected
in second quarter 2005.
In November 2004, the Canadian Association of Petroleum Producers (CAPP) filed
an application with the NEB to review and vary its Phase I decision with respect
to approving tolls for FT-NR to be determined on a biddable basis,
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allowing TCPL to include all forecast long-term incentive compensation costs in
its 2004 cost of service and allowing TCPL to recover, through tolls, certain
regulatory and legal costs relating to review and appeal proceedings.
On February 18, 2005, having considered whether there was a doubt as to the
correctness of its decision on these matters, the NEB decided to review its
decision on the toll to be charged for FT-NR service. It also decided not to
review its decision on the inclusion of the disputed regulatory and legal costs
in tolls. At CAPP's request, the NEB deferred its consideration of a review on
its decision regarding long-term incentive compensation costs. As a next step,
the NEB will consider the merits of confirming, amending or overturning its
decision on the FT-NR toll.
On February 14, 2005, TCPL announced it had reached a settlement with its
Canadian Mainline shippers regarding 2005 tolls. This settlement establishes OM&
A costs for 2005 at $169.5 million, which is comparable to the 2004 level. Any
variance between actual OM&A costs in 2005 and those agreed to in the settlement
will accrue to TCPL. All other cost elements of the 2005 revenue requirement
will be treated on a flow through basis. Further, the 2005 ROE for the Canadian
Mainline will be 9.46 per cent as determined under the NEB's generic ROE
formula, and the common equity component of the Canadian Mainline's capital
structure in 2005 shall be based on the NEB's decision in the recently concluded
hearing on the Canadian Mainline's cost of capital for 2004, subject to the
outcome of any review applications or appeals.
ALBERTA SYSTEM
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. In July
2004, the EUB released its decision on the GCOC Proceeding. In its GCOC
decision, the EUB set a generic ROE of 9.60 per cent for all Alberta utilities
for 2004 and an equity thickness for the Alberta System of 35 per cent. The EUB
decided that the generic ROE in future years will be adjusted by 75 per cent of
the change in long-term Canada bonds, consistent with the approach used by the
NEB. The EUB also indicated that a review of its ROE adjustment mechanism would
not occur prior to 2009, unless the ROE resulting from the application of the
ROE formula is less than 7.6 per cent or greater than 11.6 per cent. As for
changes in capital structure, the EUB expects changes would only be pursued if
there is a material change in investment risk.
In August 2004, TCPL received the EUB's decision on Phase I of the 2004 GRA
which consisted of evidence in support of the applied-for rate base and revenue
requirement. The EUB approved depreciation rates which resulted in a composite
rate of 4.05 per cent in 2004, the purchase of Simmons and the recovery of costs
associated with existing transportation arrangements with the Foothills, Simmons
and Ventures LP systems. However, the EUB decision disallowed certain operating
and capital costs.
In September 2004, TCPL filed with the Alberta Court of Appeal for leave to
appeal the EUB's decision on Phase I of the 2004 GRA with respect to the
disallowance of applied-for incentive compensation costs. In its decision, the
EUB disallowed approximately $24 million (pre tax) of operating costs, which
included $19 million of applied-for incentive compensation costs. TCPL believes
the EUB made errors of law in deciding to deny the inclusion of these
compensation-related costs in the revenue requirement. The company believes
these are necessary costs that it reasonably and prudently incurs for the safe,
reliable and efficient operation of the Alberta System. At the request of TCPL,
the Court of Appeal adjourned the appeal for an indefinite period of time while
TCPL considers the merits of a review and variance application to the EUB in
respect of 2004 costs, and works toward a negotiated settlement of future years'
tolls with its customers.
In October 2004, the EUB approved Phase II of the 2004 GRA, which primarily
dealt with rate design and services. The EUB also directed TCPL to file a 2005
GRA-Phase II application on or before April 1, 2005 to address certain cost
allocation issues related to rate design.
In December 2004, TCPL filed its 2005 Phase I GRA with the EUB. On February 24,
2005, TCPL advised the EUB that it had reached an agreement in principle for the
Alberta System with negotiating parties and requested a suspension of the
established regulatory timetable for adjudication of the 2005 GRA pending its
finalization of the contemplated settlement agreement. On February 25, 2005, the
EUB granted this request.
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GAS TRANSMISSION - 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 and markets served by TCPL's pipelines. In addition,
the continued expiration of transportation contracts has resulted in significant
reductions in firm contracted capacity on both the Canadian Mainline and Alberta
System.
As of December 2003, the WCSB had remaining discovered natural gas reserves of
55 trillion cubic feet and a reserves-to-production ratio of approximately nine
years at current levels of production. Historically, additional reserves have
continually been discovered to maintain the reserves-to-production ratio at
close to nine years. Natural gas prices in the future are expected to be higher
than long-term historical averages due to a tighter supply/demand balance which
should stimulate exploration and production in the WCSB. However, WCSB supply is
expected to remain essentially flat. With the expansion of capacity on 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.
TCPL's Alberta System provides the major natural gas gathering and export
transportation capacity for the WCSB by connecting to most of the natural gas
processing plants in Alberta and then transporting natural gas for domestic and
export deliveries. The Alberta System faces competition primarily from the
Alliance Pipeline, a natural gas pipeline from northeast B.C. to the Chicago
area for ex-Alberta deliveries. In addition, the Alberta System has faced, and
will continue to face, increasing competition from other pipelines.
The Canadian Mainline is TCPL's cross-continent natural gas pipeline serving
mid-western and eastern markets in Canada and the U.S. 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 historically received Canadian supplies only from TCPL are
now capable of receiving supplies from new pipelines into the region that can
source Western Canadian, Atlantic Canadian and U.S. supplies.
The Canadian Mainline has experienced reductions in long haul FT contracts.
This has been partially offset by an increase in short haul contracts. While
decreases in throughput do not directly impact Canadian Mainline earnings, such
decreases will impact the competitiveness of its tolls. Looking forward, in the
short to medium term, there is limited opportunity to reduce tolls by increasing
long haul volumes on the Canadian Mainline.
The Gas Transmission Northwest System must compete with other pipelines for
access to natural gas supplies and its markets. Transportation service capacity
on the Gas Transmission Northwest System provides customers with access to
supplies of natural gas primarily from the WCSB and serves markets in the
Pacific Northwest, California and Nevada. These three markets may also access
supplies from other competing basins in addition to supplies from the WCSB.
Historically, natural gas supplies from the WCSB have been competitively priced
on the Gas Transmission Northwest System in relation to natural gas supplies
from the other supply regions serving these markets. Natural gas transported
from the WCSB on the Gas Transmission Northwest System competes for the
California and Nevada markets against supplies from the Rocky Mountain and
southwest U.S. supply basins. In the Pacific Northwest market, natural gas
transported on the Gas Transmission Northwest System competes against Rocky
Mountain gas supply as well as additional western Canadian supply that is
transported by Williams' Northwest Pipeline.
Transportation service on the North Baja System provides access to natural gas
supplies primarily from both the Permian Basin, located in western Texas and
southeastern New Mexico, and the San Juan Basin, primarily located in
northwestern New Mexico and Colorado. The North Baja System delivers gas to
Gasoducto Bajanorte Pipeline at the California/Mexico border, which transports
the gas to markets in northern Baja California, Mexico. While there are
currently no direct competitors to deliver natural gas to the North Baja
System's downstream markets, the pipeline may compete with fuel oil which is an
alternative to natural gas in the operation of some electric generation plants
in the North Baja region. The North Baja System's market is near locations of
interest for LNG development companies who may be interested in delivering
foreign natural gas supplies to the area.
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Financial Risk Regulatory decisions continue to have a significant impact on
the financial returns for existing and future investments in TCPL's Canadian
wholly-owned pipelines. TCPL remains concerned the approved financial returns
discourage additional investment in existing Canadian natural gas transmission
systems. TCPL had applied for a return of 11 per cent on 40 per cent deemed
common equity, both to the NEB in the Canadian Mainline's 2004 Application and
to the EUB in the Alberta System's application in the GCOC proceeding. In its
GCOC decision, the EUB set a generic ROE of 9.60 per cent for all Alberta
utilities for 2004 and a deemed equity thickness for the Alberta System of 35
per cent. Following the FCA's decision, TCPL revised its 2004 Application to
reflect a return of 9.56 per cent based on the NEB formula on 40 per cent common
equity. The NEB's deliberations on the 2004 Application respecting these matters
are currently under way with a decision expected in second quarter 2005.
The company is cognisant of the views and shares the concerns of credit rating
agencies regarding the Canadian regulatory environment. Credit ratings and
liquidity have risen to the forefront of investor attention. In light of the
developments in the Canadian regulatory environment, there exists a view that
current Canadian regulatory policy is eroding the credit worthiness of utilities
which, over the long term, could make it increasingly difficult for utilities to
access capital on reasonable terms.
Foreign Exchange TCPL's earnings from GTN, as well as a significant amount
of earnings in Other Gas Transmission are generated in U.S. dollars. The
performance of the Canadian dollar relative to the U.S. dollar would either
positively or negatively impact Gas Transmission's net earnings.
Throughput Risk As transportation contracts expire on Great Lakes, Northern
Border and GTN, these pipelines will be more exposed to throughput risk and
their revenues will more likely experience increased variability. Throughput
risk is created by supply availability, economic activity, weather variability,
pipeline competition and pricing of alternative fuels.
Regulation The Alberta System is regulated by the EUB. The remaining
Canadian pipelines, other than Ventures LP, are regulated by the NEB. In the
U.S., TCPL's wholly- and partially-owned pipelines are regulated by the FERC.
These regulators approve the pipelines' respective ROE, costs of service,
capital structures, tolls and system expansions.
GAS TRANSMISSION - OTHER
OPERATIONAL EXCELLENCE
TCPL continued its commitment to operational excellence in 2004 by further
advancing initiatives that will improve the company's ability to provide
low-cost, reliable and responsive service to customers. TCPL continues to pursue
this strategy in order to become the preferred company that customers choose to
connect new natural gas supplies and markets.
In 2004, TCPL reduced operating and maintenance costs through rationalizing
maintenance and streamlining the delivery of services. The company met its
ongoing goals in the management of greenhouse gases. TCPL also achieved a high
level of plant operating performance, as measured by the number of operational
perfect days on both the Canadian Mainline and the Alberta System.
In 2004, TCPL maintained high levels of customer satisfaction with the launch
of a new website called "Customer Express". Customer Express is integrated into
TCPL's website and provides customers with more efficient access to commercial
information needed to make transportation decisions. Customer feedback indicates
this new website was very well received. Also, through a collaborative effort
with customers, a new long-haul firm transportation service enhancement (FT-RAM)
was offered on a one year pilot basis beginning November 1, 2004. The purpose of
FT-RAM is to mitigate unutilized demand charges and provide greater flexibility
in order to attract and retain contracts for FT service.
In 2005, TCPL will continue to focus efforts on efficiencies, operational
reliability, and environmental and safety performance. Greenhouse gas emissions
management programs will continue to receive focused attention. Additional
effort will be undertaken in 2005 with respect to improving contractor safety
performance.
Safety TCPL worked closely with regulators, customers and communities during
2004 to ensure the continued safety of employees and the public. Pipeline safety
performance in 2004 was excellent with no line-breaks or other serious
incidents. Under the approved regulatory models in Canada, expenditures on
pipeline integrity have no negative impact
M-17
on earnings. The company expects to spend approximately $70 million in 2005 for
pipeline integrity on its Wholly-Owned Pipelines, which is comparable to amounts
spent in 2004. 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 2004, TCPL continued to conduct activities to increase
environmental protection through proactive sampling, remediation and monitoring
programs. Compressor stations on the Alberta System have been assessed through
the company's Site Assessment, Remediation & Monitoring program. In 2004, TCPL
invested in improved environmental protection measures. This program of actively
assessing and addressing environmental issues will continue into the future. In
addition, the decommissioning of six Canadian Mainline compressor plants and two
Alberta compressor plants was undertaken in 2004, effectively reclaiming each
project site.
For information on management of risks with respect to the Gas Transmission
business, see the Risk Management section.
GAS TRANSMISSION - OUTLOOK
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, Gas
Transmission has focused on providing market-responsive products and services,
competitive cost-effective structures and the highest levels of reliability to
customers.
TCPL continues to actively pursue pipeline and natural gas transmission-related
development and acquisition opportunities in North America, where these
opportunities are driven by strong customer demand and sound economics. The
company will continue to evaluate options in a disciplined fashion to maintain a
strong financial position.
World geo-political events will have an impact on the level of development of
future and existing natural gas supplies worldwide. This could directly impact
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 northern and Atlantic Canada natural gas reserves.
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 advantages
including expertise in the design, construction and operation of large diameter
pipe 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.
In 2005, the company will continue to focus on achieving additional efficiency
improvements in all aspects of the business by maintaining focus on operational
excellence and leveraging technological advancements. TCPL will also continue to
work collaboratively with all stakeholders on negotiated settlements and the
evolution of services that will increase the value of TCPL's business to
customers and shareholders.
Looking forward, as the supply/demand balance tightens, producers will continue
to explore and develop new fields, particularly in northeastern B.C. and the
central foothills regions of Alberta, as well as unconventional supply such as
gas production from CBM reserves. In addition, TCPL anticipates filing an
application in 2005 with the EUB to construct Alberta System facilities required
to connect additional natural gas supplies delivered to the Alberta System from
the Mackenzie Delta.
TCPL's earnings from its Canadian wholly-owned pipelines are primarily
determined by the average investment base, ROE, deemed common equity and
opportunity for incentive earnings. In the short to medium term, the company
expects a modest level of investment in these mature assets and therefore
anticipates, due to depreciation, a continued decline in the average investment
base. Accordingly, without an increase in ROE, deemed common equity or incentive
opportunities, future earnings are anticipated to decrease. However, these
mature assets will continue to generate strong cash flows that can be redeployed
to other projects offering higher returns. Under the current regulatory model,
earnings
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from the Canadian wholly-owned pipelines are not affected by short-term
fluctuations in the commodity price of natural gas, changes in throughput
volumes or changes in contract levels.
Earnings On February 14, 2005 TCPL announced it had reached a settlement
with its Canadian Mainline shippers regarding 2005 tolls. This settlement
essentially establishes an OM&A at-risk model for 2005 and has fixed OM&A at a
level comparable to 2004. This OM&A at-risk settlement will provide some
opportunity for incentive earnings as TCPL continues to focus efforts on cost
efficiencies in 2005. This settlement also establishes the 2005 ROE for the
Canadian Mainline at 9.46 per cent as determined under the NEB formula, and its
capital structure for 2005 to be subject to the outcome of the recently
concluded hearing of the 2004 Application - Phase II.
In February 2005, TCPL reached an agreement in principle with its Alberta
System shippers on a revenue requirement settlement for the period January 1,
2005 to December 31, 2007. TCPL is proceeding with finalizing the terms of the
settlement with the negotiating parties and anticipates executing the settlement
agreement in March 2005. TCPL expects to file the settlement agreement with the
EUB for approval shortly thereafter.
In 2005, there will be a full year's contribution from GTN, which was acquired
on November 1, 2004.
Net earnings for Other Gas Transmission in 2005 will be affected by factors
such as the level of project development costs and the performance of the
Canadian dollar relative to the U.S. dollar.
Capital Expenditures
Total capital spending for the Canadian wholly-owned pipelines during 2004 was
$132 million. Overall capital spending on the Wholly-Owned Pipelines, including
GTN, in 2005 is expected to be approximately $171 million. Capital expenditures
on the Edson natural gas storage project are expected to be approximately $150
million in 2005.
NATURAL GAS THROUGHPUT VOLUMES
(Bcf)
2004 2003 2002
Canadian Mainline(1) 2,621 2,628 2,630
Alberta System(2) 3,909 3,883 4,146
Gas Transmission Northwest System(3) 181
Foothills System 1,139 1,110 1,098
BC System 360 325 371
Great Lakes 801 856 863
Northern Border 845 850 839
Iroquois 356 341 340
TQM 159 164 175
Ventures LP 136 111 85
Portland 50 53 52
Tuscarora 25 22 20
TransGas 18 16 16
(1)
Canadian Mainline deliveries originating at the Alberta border and in
Saskatchewan for the year ended December 31, 2004 were 2,017 Bcf (2003 -
2,055 Bcf; 2002 - 2,221 Bcf).
(2)
Field receipt volumes for the Alberta System for the year ended December 31,
2004 were 3,952 Bcf (2003 - 3,892 Bcf; 2002 - 4,101 Bcf).
(3)
TCPL acquired GTN on November 1, 2004. The North Baja System's total
delivery volumes were 13 Bcf. The delivery volumes represent November and
December 2004 throughput.
DESCRIPTION OF TCPL'S SIGNIFICANT GAS TRANSMISSION OPERATIONS
CANADIAN MAINLINE
TCPL's 100 per cent owned 14,898 km natural gas transmission system in Canada
extends from the Alberta/Saskatchewan border east to the Quebec/Vermont border
and connects with other natural gas pipelines in Canada and the U.S.
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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, the Foothills
System and other pipelines. The 23,186 km system is one of the largest carriers
of natural gas in North America.
GAS TRANSMISSION NORTHWEST SYSTEM
TCPL's 100 per cent owned natural gas transmission system extends 2,174 km and
links the BC System and the Foothills System with Pacific Gas and Electric
Company's California Gas Transmission System and with Tuscarora, a
partially-owned entity that runs from the Oregon/California border into Nevada.
FOOTHILLS SYSTEM
TCPL's 100 per cent owned 1,040 km natural gas transmission system in Western
Canada carries natural gas for export from central Alberta to the U.S. border to
serve markets in the U.S. Midwest, Pacific Northwest, California and Nevada.
BC SYSTEM
TCPL's 100 per cent owned natural gas transmission system extends 201 km from
Alberta's western border through B.C. to connect with the Gas Transmission
Northwest System at the U.S. border, serving markets in B.C. as well as the
Pacific Northwest, California and Nevada.
NORTH BAJA SYSTEM
The North Baja System is a 100 per cent owned, 128 km natural gas transmission
system that extends from southwestern Arizona to a point near Ogilby, California
on the California/Mexico border and connects with a pipeline system in Mexico.
VENTURES LP
Ventures LP, which is 100 per cent owned by TCPL, owns a 121 km pipeline and
related facilities which supply natural gas to the oil sands region of northern
Alberta, and a 27 km pipeline which supplies natural gas to a petrochemical
complex at Joffre, Alberta.
GREAT LAKES
Great Lakes connects with the Canadian Mainline at Emerson, Manitoba and serves
markets in central Canada and the eastern and midwestern U.S. TCPL has a 50 per
cent ownership interest in this 3,387 km pipeline system.
TQM
TQM is a 572 km natural gas pipeline system which connects with the Canadian
Mainline and transports natural gas from Montreal to Quebec City and to the
Portland system. TCPL holds a 50 per cent ownership interest in TQM.
IROQUOIS
Iroquois connects with the Canadian Mainline near Waddington, New York and
delivers natural gas to customers in the Northeastern U.S. TCPL has a 41 per
cent ownership interest in this 663 km pipeline system.
PORTLAND
Portland is a 471 km pipeline that connects with TQM near East Hereford, Quebec
and delivers natural gas to customers in the Northeastern U.S. TCPL has a 61.7
per cent ownership interest in Portland.
NORTHERN BORDER
Northern Border is a 2,010 km natural gas pipeline system which serves the U.S.
Midwest from a connection with the Foothills System. TCPL indirectly owns
approximately 10 per cent of Northern Border through its 33.4 per cent ownership
interest in TC PipeLines, LP.
TUSCARORA
Tuscarora operates a 386 km pipeline system transporting natural gas from the
Gas Transmission Northwest System at Malin, Oregon to Wadsworth, Nevada with
delivery points in northeastern California and northwestern Nevada. 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.
M-20
CROSSALTA
CrossAlta is an underground natural gas storage facility connected to the
Alberta System and is located near Crossfield, Alberta. CrossAlta has a working
natural gas capacity of 40 Bcf with a maximum deliverability capability of 410
million cubic feet per day (MMcf/d). TCPL holds a 60 per cent ownership interest
in CrossAlta.
EDSON
TCPL is currently developing the Edson natural gas storage facility near Edson,
Alberta. The Edson facility will have a capacity of approximately 50 Bcf and
will connect to TCPL's Alberta System. The facility is expected to be in-service
in second quarter 2006.
TRANSGAS
TransGas is a 344 km natural gas pipeline system which runs from Mariquita in
the central region of Colombia to Cali in the southwest of Colombia. TCPL holds
a 46.5 per cent ownership interest in this pipeline.
GAS PACIFICO
Gas Pacifico is a 540 km natural gas pipeline extending from Loma de la Lata,
Argentina to Concepcion, Chile. TCPL holds a 30 per cent ownership interest in
Gas Pacifico.
INNERGY
INNERGY is an industrial natural gas marketing company based in Concepcion,
Chile that markets natural gas transported on Gas Pacifico. TCPL holds a 30 per
cent ownership interest in INNERGY.
POWER
HIGHLIGHTS
Net Earnings Power's net earnings in 2004 were $396 million compared to $220
million in 2003 with the increase primarily due to $187 million of gains
related to Power LP.
Power's net earnings for 2004, excluding the $187 million of gains related to
Power LP, would have been $209 million which was an increase of $8 million
compared to $201 million in 2003, excluding a positive settlement in 2003 of $19
million after tax with a former counterparty.
Bruce Power Pre-tax equity income from Bruce Power of $130 million in 2004
increased $31 million compared to TCPL's period of ownership in 2003.
Unit 3 returned to service in first quarter 2004 increasing TCPL's share of
nominal generating capacity of Bruce Power to 1,487 MW.
A feasibility study was commenced with respect to the restart of Units 1 and 2.
A study of a potential investment in the refurbishment of the 680 MW Point
Lepreau nuclear generating station in New Brunswick was commenced.
Expanding Asset Base TCPL announced it will proceed with the purchase of
hydroelectric generation assets from USGen with a total generating capacity of
567 MW for US$505 million. The acquisition is subject to regulatory approvals
and pending the sale of the 49 MW Bellows Falls hydroelectric facility to
Vermont Hydroelectric. If Vermont Hydroelectric acquires Bellows Falls, for
which it exercised a pre-existing option to purchase, the purchase price will be
reduced by US$72 million to US$433 million for generating capacity of 518 MW.
The MacKay River plant in Alberta was placed in-service in 2004.
Construction of the 90 MW Grandview cogeneration plant was completed on time
and within budget.
Construction commenced in third quarter 2004 of the 550 MW Becancour natural
gas-fired cogeneration power plant in Quebec to be in-service in late 2006.
TCPL announced that Hydro-Quebec awarded Cartier Wind, owned 62 per cent by
TCPL, six projects totalling 739.5 MW which are scheduled to be commissioned
between 2006 and 2012.
M-21
The company responded to the Ontario government's Request For Proposals for
2,500 MW of new electricity generation capacity.
Plant Availability Weighted average plant availability was 96 per cent in
2004, excluding Bruce Power, compared to 94 per cent in 2003.
Including Bruce Power, weighted average plant availability remained the same in
2004 as 2003 at 90 per cent.
POWER NET EARNINGS-AT-A-GLANCE
Year ended December 31 (millions of dollars)
2004 2003 2002
Western operations 138 160 131
Eastern operations 108 127 149
Bruce Power investment 130 99
Power LP investment 29 35 36
General, administrative, support costs and other (89 ) (86 ) (73 )
Operating and other income 316 335 243
Financial charges (13 ) (12 ) (13 )
Income taxes (94 ) (103 ) (84 )
209 220 146
Gains related to Power LP (after tax) 187 - -
Net earnings 396 220 146
Power's net earnings in 2004 of $396 million increased $176 million compared to
$220 million in 2003, primarily due to $187 million of gains related to Power LP
recorded in 2004. On April 30, 2004, TCPL sold the ManChief and Curtis Palmer
power facilities to Power LP for US$402.6 million, excluding closing
adjustments, resulting in an after-tax gain on sale of $15 million (pre-tax gain
of $25 million). At a meeting in April 2004, Power LP unitholders approved these
acquisitions and the removal of Power LP's obligation to redeem all units not
owned by TCPL in 2017. TCPL was required to fund this redemption, thus the
removal of Power LP's obligation eliminated this requirement. To partially
finance the acquisition, Power LP issued 8.1 million subscription receipts which
were subsequently converted into partnership units and TCPL contributed $20
million of the net proceeds of $286.8 million from this issue. This issue also
reduced TCPL's ownership interest in Power LP from 35.6 per cent to 30.6 per
cent. As a result of these events, TCPL recognized dilution and other gains of
$172 million in 2004, $132 million of which were previously deferred and were
being amortized into income to 2017. Dilution gains arose when TCPL's ownership
interest in Power LP was decreased at different times as a result of Power LP
issuing new partnership units at a market price in excess of TCPL's per unit
carrying value of the investment.
The 2003 results include recognition in Western Operations of a $31 million
pre-tax ($19 million after-tax) settlement with a former counterparty that
defaulted in 2001 under power forward contracts. Power's net earnings for 2004,
excluding the $187 million of gains related to Power LP in 2004, would have been
$209 million which was an increase of $8 million compared to $201 million in
2003, excluding the positive settlement with a former counterparty. Pre-tax
equity income from Bruce Power of $130 million in 2004 increased $31 million
compared to TCPL's period of ownership in 2003. This was partially offset by
lower contributions from Eastern Operations and Power LP investment.
Power's net earnings of $220 million in 2003 increased $74 million or 51 per
cent compared to earnings of $146 million in 2002. This increase is primarily
attributable to the February 2003 acquisition of a 31.6 per cent interest in
Bruce Power and higher contributions from Western Operations relating to the
settlement with a former counterparty. Partially offsetting these increases were
lower earnings from Eastern Operations and higher general, administrative,
support costs and other associated with TCPL's focus on growth of the Power
business.
M-22
POWER PLANTS - NOMINAL GENERATING CAPACITY AND FUEL TYPE
MW Fuel Type
Western operations
Sundance A(1) 560 Coal
Sundance B(1) 353 Coal
MacKay River 165 Natural gas
Carseland 80 Natural gas
Bear Creek 80 Natural gas
Redwater 40 Natural gas
Cancarb 27 Natural gas
1,305
Eastern operations
OSP 560 Natural gas
Becancour(2) 550 Natural gas
Cartier Wind(3) 458 Wind
USGen(4) 518 Hydro
Grandview(5) 90 Natural gas
2,176
Bruce Power investment(6) 1,487 Nuclear
Power LP investment(7)
ManChief 300 Natural gas
Williams Lake 66 Wood waste
Castleton 64 Natural gas/waste
heat
Curtis Palmer 60 Hydro
Mamquam and Queen Charlotte 56 Hydro
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
744
Total Nominal Generating Capacity 5,712
(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 under construction.
(3)
Currently in pre-construction design phase. Represents TCPL's 62 per cent of
739.5 MW.
(4)
The purchase transaction is expected to close in the first half of 2005. The
518 MW excludes the Bellows Falls facility.
(5)
Placed in-service in first quarter 2005.
(6)
Represents TCPL's 31.6 per cent equity interest in Bruce Power. Bruce A
consists of four 750 MW reactors. Bruce A Unit 4 was returned to service in
fourth quarter 2003. Bruce A Unit 3 was returned to service in first quarter
2004. Bruce A Units 1 and 2 remain in a laid-up state. Bruce B consists of
four reactors, which are currently in operation, with a capacity of
approximately 3,200 MW. The generating capacity includes 2 MW from TCPL's 17
per cent indirect share in Huron Wind L.P. which owns a 9 MW wind farm near
Bruce Power.
(7)
At December 31, 2004, TCPL operated and managed Power LP and held a 30.6 per
cent ownership interest in Power LP. The volumes in the table represent 100
per cent of plant capacity.
M-23
POWER - EARNINGS ANALYSIS
WESTERN OPERATIONS
The focus of Western Operations is to optimize and expand its existing asset
base and maximize asset value through a combination of long- and short-term
contracts for power and steam sales. The asset portfolio is among the lowest
cost, most competitive generation in the market area. Western Operations
directly controls more than 1,300 MW of power supply in Alberta from its five
gas-fired co-generation facilities and two Sundance long-term PPAs.
Western Operations has two integrated functions - marketing and plant
operations. Based in Calgary, Alberta, the marketing function purchases and
resells electricity related to the Sundance PPAs, markets uncommitted generation
from the Alberta plants and purchases and resells power and gas to maximize the
value of its asset base. Plant operations primarily consists of the Alberta
power plants and fees earned to manage and operate the Power LP.
The marketing function is integral to optimizing Power's return from its assets
and managing risks around uncontracted volumes. A significant portion of plant
generation is sold under long-term contract to mitigate price risk. Some output
is intentionally not committed under long-term contract to assist in managing
Power's overall portfolio of generation. This approach to portfolio management
assists in minimizing costs in situations where TCPL would otherwise have to
purchase power in the open market to fulfil its contractual obligations. In
2004, 86 per cent of total sales volumes were sold under medium- to long-term
contracts. The marketing function's primary role is to manage these open
positions and it will also, at times, purchase and re-sell both power and gas in
an effort to optimize contributions from each of the generation facilities. In
order to mitigate market price risk, Western Operations has sold approximately
81 per cent of the total generation for 2005 and 65 per cent of the expected,
average combined total power supply for the next three years. Western
Operations' largest power supply comes from its Sundance PPAs. TCPL has sold
essentially all of the Sundance PPAs' power supply in 2005 and 80 per cent and
52 per cent of the expected combined power supply for 2006 and 2007,
respectively.
With the placing in-service of the MacKay River cogeneration facility in 2004,
plant operations currently consists of five plants in Alberta with a total
generating capacity of approximately 400 MW. The expansion of Alberta generation
is consistent with TCPL's focus on capitalizing on the company's expertise in
developing new projects and maintaining its position in a region it knows well.
In second quarter 2004, and consistent with TCPL's portfolio management strategy
to divest mature assets and redeploy capital, TCPL sold the 300 MW ManChief
power facility to Power LP.
Operating and other income for 2004 of $138 million was $22 million lower
compared to the same period in 2003. The decrease was mainly due 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, as
well as reduced income from ManChief following the sale of the plant to Power LP
in April 2004. Partially offsetting these decreases were contributions from the
MacKay River plant which was placed in-service in 2004, fees earned with respect
to Power LP's asset acquisitions in 2004 and the impact of higher net margins
achieved in second and third quarter 2004 on the overall portfolio.
In 2003, operating and other income from Western Operations increased by 22 per
cent to $160 million from $131 million in 2002 due primarily to the 2003
settlement with a former counterparty. 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 Cancarb carbon black facility.
EASTERN OPERATIONS
Eastern Operations is focused on the New England and New York deregulated power
markets in the U.S. and on development opportunities in Ontario, Quebec and New
Brunswick. TransCanada Power Marketing Limited (TCPM), located in Westborough,
Massachusetts, continues to navigate through New England's deregulation process
and firmly establish itself as a leading energy provider and marketer in the New
England power market.
TCPL's success in the Northeast U.S. is the direct result of a knowledgeable
region-specific marketing operation which is conducted through TCPM. TCPM is
focused on selling power under contract to wholesale, commercial and industrial
M-24
customers while managing a portfolio of power supplies sourced from its own
generation, wholesale power purchases and power purchased from the output of
Power LP's 64 MW Castleton plant in New York State. In fourth quarter 2004, TCPL
closed a transaction with Boston Edison Company (Boston Edison) resulting in the
company assuming the remaining 23.5 per cent share of the OSP power purchase
contracts. All of the OSP output is now marketed by TCPM. TCPM is a full service
provider offering varied products and services to assist customers in managing
their power supply and power prices in deregulated power markets.
Eastern Operations' power generation assets include OSP and Grandview. OSP is a
560 MW natural gas-fired plant located in Rhode Island. Grandview is a 90 MW
natural gas-fired cogeneration facility on the site of the Irving Oil Refinery
in Saint John, New Brunswick. Construction of the Grandview facility was
complete at the end of 2004 and it was commissioned in first quarter 2005. 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. On April
30, 2004, and consistent with TCPL's portfolio management strategy to divest
mature assets and redeploy capital, TCPL sold the 60 MW Curtis Palmer
hydroelectric power facility to Power LP.
Operating and other income for 2004 was $108 million or $19 million lower than
the $127 million earned in 2003. This decrease was mainly due to a reduction in
income as a result of the sale of the Curtis Palmer hydroelectric facilities to
Power LP in April 2004, the unfavourable impact of higher natural gas fuel costs
at OSP and a weaker U.S. dollar in 2004. Partially offsetting these decreases
was a $16 million positive impact from the restructuring transaction related to
the power purchase contracts between OSP and Boston Edison. TCPL recognized
earnings from the transaction's effective date of April 1, 2004.
Operating and other 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 on sales to wholesale, 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
operated in Cobourg, Ontario during the summer of 2003.
In late 2004, management conducted a review of the operating plan for OSP with
respect to the negative impacts of a third arbitration received in August 2004
whereby OSP's cost of fuel gas substantially increased to a price in excess of
market. The outcome of a fourth arbitration is expected by the end of third
quarter 2005. At December 31, 2004, there was determined to be no impairment of
OSP; however, there existed uncertainty with respect to the outcome of this
arbitration process and future market conditions. Should the fourth arbitration
decision continue to support a pricing mechanism for fuel gas in excess of
market price and if anticipated market conditions do not change substantially,
management expects the negative impact of the continued above-market gas prices
could result in an asset impairment write-down of the OSP facility. The net
carrying value of OSP at December 31, 2004 was approximately US$150 million.
BRUCE POWER INVESTMENT
On February 14, 2003, the company completed the acquisitions of a 31.6 per cent
interest in Bruce Power and 33.3 per cent interest in Bruce Power Inc., the
general partner of Bruce Power, for $409 million. TCPL also funded, through a
loan arrangement, a one-third share ($75 million) of a $225 million accelerated
deferred rent payment made by Bruce Power to Ontario Power Generation (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 comprised of two nuclear plants - Bruce A and Bruce B. Bruce B
consists of four reactors with a capacity of approximately 3,200 MW. Bruce A
consists of four reactors which, up until 2003, were not operating. In fourth
quarter 2003, Bruce Power completed commissioning of Bruce A Unit 4 and in first
quarter 2004, it completed commissioning of Unit 3. These two Bruce A units
added 1,500 MW of capacity, bringing Bruce Power's total capacity to
approximately 4,700 MW.
Bruce Power is the tenant under a lease with OPG on the Bruce nuclear power
facility. The lease expires in 2018 with an option to extend the lease by up to
25 years. The Bruce Power nuclear facility continues to be managed and operated
by
M-25
the management and staff of Bruce Power. Spent fuel and decommissioning
liabilities remain the responsibility of OPG but the lease agreement with OPG
provides for adjustments to the base rent every five years contingent upon the
projected decommissioning costs for the Bruce Power facility.
TCPL's share of power output from Bruce Power in 2004 was 10,608 gigawatt hours
(GWh). This includes power output from Unit 3 from March 1, 2004. Unit 3 began
producing electricity to the Ontario electricity grid on January 8, 2004 and was
considered commercially in-service March 1, 2004. Bruce Power's cumulative
restart cost for Units 3 and 4 was approximately $720 million.
Pre-tax equity income for 2004 was $130 million compared to $99 million for the
same period in 2003. This increase was primarily due to higher output in 2004 as
a result of the return to service of Units 3 and 4 as well as a full year of
earnings in 2004 compared to earnings from February 14 to December 31 in 2003,
reflecting TCPL's period of ownership in 2003.
Adjustments to TCPL's interest in Bruce Power income before income taxes for
2004 were lower than the same period in 2003 primarily due to the cessation of
interest capitalization upon the return to service of Units 3 and 4. Operating
costs for 2004 were $35 per MWh compared to $36 per MWh for the period February
14 to December 31, 2003. Average realized prices in 2004 were $47 per MWh
compared to $48 per MWh during TCPL's period of ownership in 2003. Approximately
52 per cent of Bruce Power's output in 2004 was sold into Ontario's wholesale
spot market.
TCPL has not made any cash contributions to, and has not received any cash
distributions from, Bruce Power subsequent to the acquisition of the company's
ownership interest in February 2003.
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 36 per cent of
planned output for 2005. Bruce Power's operating expenses in 2005 are expected
to increase from 2004 due to higher depreciation and amortization on the Bruce A
units, higher outage costs and higher fuel costs.
The average availability in 2005 is expected to be 85 per cent compared to 82
per cent achieved in 2004. Unit 3 began its first planned maintenance outage on
January 8, 2005 and is expected to be offline for approximately two months. Unit
4 is scheduled to go offline later in first quarter 2005 for a similar
inspection program. Maintenance outages of approximately two to three months
each are also planned for two other units in 2005. One outage is expected to
begin in second quarter 2005 and the other outage is expected to begin in third
quarter 2005.
BRUCE POWER RESULTS-AT-A-GLANCE
Year ended December 31 (millions of dollars)
Bruce Power (100 per cent basis) 2004 2003
Revenues 1,583 1,208
Operating expenses (1,178 ) (853 )
Operating income 405 355
Financial charges (67 ) (69 )
Income before income taxes 338 286
TCPL's interest in Bruce Power income before income taxes(1) 107 65
Adjustments(2) 23 34
TCPL's income from Bruce Power before income taxes 130 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 8 to the December 31, 2004 consolidated financial statements for an
explanation of the purchase price amortizations. The amount allocated to the
investment in Bruce Power includes a purchase price allocation of $301
million to the initial lease of the Bruce Power plant which is being
amortized on a straight-line basis over the lease term that extends to 2018,
resulting in an annual amortization expense of $19 million. The amount
allocated to the power sales agreements is being 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.
M-26
Power LP Investment Power LP Investment includes the earnings generated from
TCPL's 30.6 per cent investment in Power LP, which is one of Canada's largest
publicly-held, power-based income funds. Power LP owns 11 power plants, eight in
Canada and three in the U.S., that are hydroelectric or fuelled by natural gas,
waste heat, wood waste or a combination thereof. Power LP increased its
generating capacity in 2004 from 328 MW to 744 MW through the acquisition of
four power facilities, Curtis Palmer and ManChief from TCPL and Mamquam and
Queen Charlotte through the acquisition of Hydro Investment Corporation.
TCPL's investment in Power LP decreased in 2004 from 35.6 per cent to 30.6 per
cent. In 2004, Power LP issued 8.1 million subscription receipts to partially
finance the purchase of the Curtis Palmer and ManChief power generation
facilities from TCPL. TCPL purchased 540,000 of these subscription receipts for
$20 million. All of the subscription receipts were converted to limited
partnership units on April 30, 2004 upon Power LP's acquisition of the Curtis
Palmer and ManChief facilities, thereby reducing TCPL's ownership of the
partnership to 30.6 per cent. TCPL continues to be the largest unitholder and
the manager of Power LP, owning approximately 14.5 million units at December 31,
2004.
TCPL is the manager of Power LP and its power plant operations. In this
capacity, TCPL manages the operations and maintenance requirements of all Power
LP plants, the fuel supply and associated price exposure and, when market
conditions warrant, 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 maximized investment value for unitholders, including
TCPL.
Operating and other income from the investment in Power LP of $29 million for
2004 was $6 million lower compared to 2003. Additional earnings from Power LP's
April 2004 acquisition of the Curtis Palmer and ManChief facilities were more
than offset by the impact of TCPL's reduced ownership interest in Power LP and
the recognition of $132 million of previously deferred gains resulting from the
removal of the Power LP redemption obligation. Prior to the removal of the
redemption obligation, TCPL was recognizing into income the amortization of
these deferred gains over a period through to 2017.
The cash distributions to TCPL from Power LP in 2004 were approximately $36
million compared to $35 million in 2003. At December 31, 2004, Power LP units
closed at $35.40 on the Toronto Stock Exchange.
POWER SALES VOLUMES AND PLANT AVAILABILITY
Power Sales Volumes (GWh) 2004 2003 2002
Western operations(1) 11,695 12,296 12,065
Eastern operations(1) 6,198 6,906 5,630
Bruce Power investment(2) 10,608 6,655
Power LP investment(1)(3) 2,419 2,153 2,416
Total 30,920 28,010 20,111
(1)
ManChief and Curtis Palmer are included in Power LP Investment, effective
April 30, 2004.
(2)
Acquired on February 14, 2003. Sales volumes in 2003 reflect TCPL's 31.6 per
cent share of Bruce Power output from the date of acquisition.
(3)
At December 31, 2004, TCPL operated and managed Power LP and held a 30.6 per
cent ownership interest in Power LP. The volumes in the table represent 100
per cent of Power LP's sales volumes.
Power sales volumes increased 10 per cent in 2004 to 30,920 GWh compared to
28,010 GWh in 2003 primarily due to TCPL's full year of ownership in Bruce
Power, in addition to the restart of Bruce Power Units 3 and 4.
Sales volumes for Western Operations were lower in 2004 compared to 2003 due to
the sale of ManChief to Power LP in April 2004, and lower portfolio management
trading activity, partially offset by new volumes from the MacKay River plant
placed in-service in 2004. Eastern Operations' sales volumes decreased in 2004
compared to 2003 primarily as a result of the sale of Curtis Palmer to Power LP
in April 2004, lower utilization of OSP and a reduction in contract volumes due
to lower demand. Sales volumes for the Bruce Power investment increased by 59
per cent as a result of the restart of Bruce Power Units 3 and 4 and TCPL's full
year of ownership in 2004 partially offset by decreased plant availability.
M-27
Volumes for Power LP increased due to the purchase of Curtis Palmer and ManChief
in April 2004 and Mamquam and Queen Charlotte in July 2004.
Weighted Average Plant Availability(1)
2004 2003 2002
Western operations(2) 95% 93% 99%
Eastern operations(2) 95% 94% 95%
Bruce Power investment(3) 82% 83%
Power LP investment(2) 97% 96% 94%
All plants, excluding Bruce Power investment 96% 94% 96%
All plants 90% 90% 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)
ManChief and Curtis Palmer are included in Power LP Investment effective
April 30, 2004.
(3)
The comparative 2003 percentage is calculated from the February 14, 2003
date of acquisition. Unit 4 is included effective November 1, 2003 and Unit
3 is included effective March 1, 2004.
POWER - OPPORTUNITIES AND DEVELOPMENTS
TCPL is committed to develop, acquire, own and operate the lowest-cost power
sources or have facilities with secure long-term contracts in markets it knows.
TCPL seeks to build or acquire low-cost, base-load facilities with low operating
costs and high reliability. TCPL seeks to avoid high-cost facilities that sell
into volatile merchant markets without long-term contracts. Power intends to
execute its strategy by:
*
Focusing on markets and regions where it has a competitive advantage -
primarily Western Canada and the Northwestern U.S., and Eastern Canada
and the Northeastern U.S.
*
Focusing on low-cost, base-load generation.
*
Focusing on new projects underpinned by secure long-term contracts.
*
Structuring deals to keep risks low.
*
Using solid disciplined marketing and trading operations to sell power
that is not contracted and optimize and protect power-generation cash
flows.
In fourth quarter 2004, TCPL announced that it will purchase hydroelectric
generation assets from USGen with a total generating capacity of 567 MW for
US$505 million. The purchase is subject to the sale of the 49 MW Bellows Falls
hydroelectric facility to Vermont Hydroelectric, which exercised its
pre-existing option to purchase the facility. This would result in a US$72
million reduction in purchase price to US$433 million for generating capacity of
518 MW. All bankruptcy court approvals have been granted for TCPL's USGen
acquisition. However, other regulatory approvals and conditions will need to be
met prior to closing. The transaction is expected to close in the first half of
2005.
Cartier Wind, owned 62 per cent by TCPL, announced in fourth quarter 2004 it
was awarded six wind energy projects in Quebec by Hydro-Quebec representing a
total of 739.5 MW. The six projects are expected to be commissioned between 2006
and 2012 and are expected to cost a total of more than $1.1 billion. Long-term
electricity supply contracts with Hydro-Quebec for each of the six facilities
were executed on February 25, 2005.
Construction of the 550 MW Becancour natural gas-fired cogeneration power plant
in Quebec began in third quarter 2004, to be in-service in late 2006. In
mid-2003, TCPL announced its plans to develop the power plant which is located
in the Becancour Industrial Park, near Trois-Rivieres. The entire power output
will be supplied to Hydro-Quebec under a 20 year power purchase contract. The
plant will also supply steam to certain major businesses located within the
industrial park.
Late in fourth quarter 2004, TCPL responded to the Ontario government's Request
For Proposals for 2,500 MWs of new electricity generation capacity, of which
Portlands Energy Centre L.P. (Portlands Energy) was one of the submitted
projects by TCPL. Portlands Energy is a 550 MW natural gas-fuelled facility in
downtown Toronto and would be developed through a partnership with OPG.
M-28
Following the successful restart of Bruce A Units 3 and 4, Bruce Power began
conducting a technical review to assess the feasibility of refurbishing Bruce A
Units 1 and 2. Units 1 and 2 were laid-up in 1995 and 1997, respectively.
Information has been gathered to evaluate the condition of the units to fully
understand the project scope and cost, and environmental assessment of the
project continues to be performed. In September 2004, the province of Ontario
appointed a special negotiator to work with Bruce Power to negotiate an
agreement for additional electricity supply. While no decision has been
finalized with respect to the refurbishment of Units 1 and 2, the return to
service of these units would be a significant step towards satisfying the
province of Ontario's future energy requirements. This technical review will
also establish improvements that will be required to extend the lives of the six
operating units which are scheduled to be taken out of service over the next 15
years. In 2004, Bruce Power expensed $16 million related to this project.
TCPL, together with its Bruce Power partners, is evaluating a potential
investment in the Point Lepreau nuclear generating station in New Brunswick.
Point Lepreau, which is indirectly owned by the New Brunswick provincial
government, is a 680 MW nuclear power plant with a CANDU reactor similar to the
Bruce reactors in Ontario. No decision has been made by TCPL and its partners as
to whether Bruce Power will proceed with investment in the Point Lepreau
facility. Discussions are ongoing with New Brunswick Power.
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 2005 and future years.
However, unexpected plant outages and/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 operates in highly competitive, deregulated
power 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:
*
long-term purchase and sales contracts for both electricity and plant
fuels;
*
control of generation output;
*
matching physical plant contracts or PPA supply with customer demand;
*
fee-for-service managed accounts rather than direct commodity exposure;
and
*
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. TCPL's largest exposure to sales price fluctuations is on Bruce
Power's uncontracted volumes. See the section below "Power - Business Risks -
Uncontracted Volumes".
Regulatory TCPL operates in both regulated and deregulated power markets. As
electricity markets evolve across North America, there is the potential for
regulatory bodies to implement new rules that could negatively impact TCPL as a
generator and marketer of electricity. These may be in the form of market rule
changes, 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.
Weather Temperature and weather events may create power and gas demand and
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.
Hydrology Power is subject to hydrology risk with its ownership, directly
and indirectly, of hydroelectric power generation facilities. Weather changes,
local river management and potential dam failures at these plants or upstream
plants pose potential risks to the company.
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
M-29
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 price volatility which directly impacts earnings.
POWER - OTHER
Operational Excellence TCPL is committed to its operational excellence model
to provide low cost, reliable operating performance at each of its plants in an
effort to achieve and sustain high performance as measured against broad
industry standards. Weighted average plant availability, excluding Bruce Power,
averaged 96 per cent in 2004, exceeding the comparative industry average of 90
per cent. Forced outage rates (unplanned outages) in 2004 were 1.6 per cent as
compared to a comparative industry average of 5.5 per cent.
POWER - OUTLOOK
Contributions from Eastern Operations are expected to be lower in 2005 due to
higher natural gas costs at OSP resulting from the 2004 arbitration decision, no
earnings in 2005 from Curtis Palmer as a result of its sale to Power LP in April
2004, the expiration of long-term contracts held by TCPM at the end of 2004 and
the expected non-recurrence of earnings recognized from the Boston Edison
transaction in 2004. Partially offsetting these reductions are earnings from
Grandview and the USGen acquisition expected to close in the first half of 2005.
Should the fourth arbitration decision at OSP, expected in 2005, result in a
continued pricing mechanism for fuel gas in excess of market price and if
anticipated market conditions do not change substantially, management expects
there could be an asset impairment write-down of this facility. The net carrying
value of OSP at December 31, 2004 was approximately US$150 million.
Bruce Power earnings are subject to potential variability as a result of prices
realized, plant availability and operating expense levels. A $1.00 per MWh
change in the spot price for electricity in Ontario would change TCPL's
after-tax equity income from Bruce Power by approximately $5 million. The
average availability of Bruce Power in 2005 is expected to be 85 per cent
compared to 82 per cent in 2004. Bruce Power operating expenses are expected to
increase in 2005 due to higher outage costs, higher depreciation on the Bruce A
units and recent capital programs, and higher fuel costs.
Earnings opportunities in Power may be affected by factors such as plant
availability, fluctuating market prices for power and gas and ultimately market
heat rates, regulatory changes, weather, sales of uncontracted volumes, currency
movements and overall stability of the power industry. Please see "Power -
Business Risks" for a complete discussion of these factors.
DESCRIPTION OF TCPL'S SIGNIFICANT POWER OPERATIONS
Bear Creek Commercial operation of this 80 MW natural gas-fired cogeneration
plant near Grande Prairie, Alberta commenced in March 2003.
MacKay River This 165 MW natural gas-fired cogeneration plant near Fort
McMurray, Alberta was placed in-service in 2004.
Redwater Commercial operation of this 40 MW natural gas-fired cogeneration
plant near Redwater, Alberta commenced in January 2002.
Sundance A&B The Sundance power facility in Alberta is the largest
coal-fired electrical generating facility in Western Canada. TCPL owns the
Sundance A PPA, which increased the company's power supply by 560 MW for a 17
year period commencing in 2001. TCPL effectively owns 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 in 2002.
Carseland Commercial operation of this 80 MW natural gas-fired cogeneration
plant near Carseland, 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.
M-30
Bruce Power In February 2003, TCPL acquired a 31.6 per cent equity interest
in Bruce Power, which operates the Bruce nuclear power facility located near
Lake Huron, Ontario. This investment indirectly increased TCPL's nominal
generating capacity initially by approximately 1,000 MW, with an additional 474
MW added with the restart of two laid-up units in late 2003 and early 2004.
OSP The OSP plant is a 560 MW natural gas-fired, combined-cycle facility in
Rhode Island.
Becancour The 550 MW Becancour natural gas-fired cogeneration power plant
located near Trois-Rivieres, Quebec is under construction and is expected to be
in-service in late 2006. The entire power output will be supplied to
Hydro-Quebec under a 20 year power purchase contract. Steam will also be
supplied to local businesses.
Cartier Wind Cartier Wind, 62 per cent owned by TCPL, announced in fourth
quarter 2004 it was awarded six wind projects by Hydro-Quebec totalling 739.5 MW
to be commissioned between 2006 and 2012. Construction on the first project is
expected to commence in late 2005.
Grandview Construction of the 90 MW Grandview natural gas-fired cogeneration
power plant located in Saint John, New Brunswick was completed by the end of
2004. Under a 20 year tolling arrangement, 100 per cent of the plant's heat and
electricity output will be sold to Irving Oil.
USGen In fourth quarter 2004, TCPL announced it intends to purchase
hydroelectric generation assets from USGen. The assets expected to be purchased
have a total generating capacity of 518 MW and are situated on two rivers in New
England. The output is not sold under long-term contracts. The transaction is
expected to close in the first half of 2005.
Curtis Palmer The 60 MW Curtis Palmer hydroelectric facility near Corinth,
New York was sold to Power LP in second quarter 2004. All output from this
facility is sold through a fixed-priced, long-term agreement.
ManChief The 300 MW simple-cycle ManChief facility near Brush, Colorado was
sold to Power LP in second quarter 2004. The entire capacity of this natural
gas-fired plant is sold under long-term tolling contracts that expire in 2012.
Williams Lake Power LP owns a 66 MW wood waste-fired power plant at Williams
Lake, B.C.
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.
Castleton Castleton is a 64 MW combined-cycle plant located at
Castleton-on-Hudson, New York and is owned by Power LP.
Mamquam and Queen Charlotte The 50 MW Mamquam and 6 MW Queen Charlotte
hydroelectric facilities are located in B.C. All energy produced from these
facilities is contracted long term to B.C. Hydro and Power Authority. The assets
were purchased by Power LP in third quarter 2004.
Paiton Paiton owns a power project consisting of two 615 MW coal-fired power
units located in Indonesia. TCPL effectively holds an approximate 11 per cent
interest in Paiton.
CORPORATE
HIGHLIGHTS
Net Expenses Net expenses in 2004 decreased $37 million compared to 2003.
M-31
CORPORATE RESULTS-AT-A-GLANCE
Year ended December 31 (millions of dollars)
2004 2003 2002
Indirect financial and preferred equity charges 81 89 91
Interest income and other (34 ) (21 ) (14 )
Income taxes (43 ) (27 ) (25 )
Net expenses, after tax 4 41 52
The Corporate segment reflects net expenses not allocated to specific business
segments, including:
*
Indirect Financial and Preferred Equity Charges Direct financial
charges are reported in their respective business segments and are
primarily associated with the debt and preferred securities related to
the company's Wholly-Owned Pipelines. Indirect financial charges,
including the related foreign exchange impacts, 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 and foreign exchange.
*
Interest Income and Other Interest income is earned on invested cash
balances. Gains and losses on foreign exchange related to working
capital in the Corporate segment are included in interest income and
other.
Net expenses, after tax, in the Corporate segment were $4 million in 2004
compared to $41 million in 2003 and $52 million in 2002.
The decrease in net expenses in 2004 from 2003 was primarily due to the
positive impacts of income tax related items, including refunds received and the
recognition of income tax benefits relating to additional loss carryforwards
utilized, the release in 2004 of previously established restructuring provisions
and positive impacts of foreign exchange related items.
The decrease in net expenses in 2003 from 2002 was primarily due to the
positive impacts of a weaker U.S. dollar compared to the prior year.
In 2005, the Corporate segment is expected to incur a more normalized level of
net expenses with higher net expenses than in 2004.
LIQUIDITY AND CAPITAL RESOURCES
Funds Generated from Continuing Operations Funds generated from continuing
operations were approximately $1.7 billion for 2004 compared to approximately
$1.8 billion for both 2003 and 2002. The decrease in 2004 was mainly as a result
of higher current income tax expenses in 2004 compared to the two prior years.
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 from operations
increased in 2004 compared to the two prior years.
At December 31, 2004, 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, was consistent with the past few
years.
Investing Activities Capital expenditures, excluding acquisitions, totalled
$476 million in 2004 compared to $391 million and $599 million in 2003 and 2002,
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 2004, TCPL acquired GTN for approximately US$1.2 billion, excluding
assumed debt of approximately US$0.5 billion, and sold the ManChief and Curtis
Palmer power facilities for US$402.6 million, excluding closing adjustments.
M-32
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 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. for $19 million.
Financing Activities In 2004, TCPL retired long-term debt of $997 million.
The company issued $200 million of 4.10 per cent medium-term notes due 2009,
US$350 million of 5.60 per cent senior unsecured notes due 2034 and US$300
million of 4.875 per cent senior unsecured notes due 2015. The company increased
its notes payable by $179 million during 2004.
In 2003, TCPL repaid long-term debt of $744 million, reduced notes payable by
$62 million and redeemed all of its outstanding US$160 million, 8.75 per cent
Junior Subordinated Debentures. The company issued $450 million of ten year,
5.65 per cent medium-term notes and US$350 million of ten year, 4.00 per cent
senior unsecured notes.
In 2002, the company funded long-term debt maturities of $486 million and
reduced notes payable by $46 million.
Dividends and preferred securities charges amounting to $623 million were paid
in 2004 compared to $588 million in 2003 and $546 million in 2002.
In February 2005, TCPL's Board of Directors declared a dividend for the quarter
ending March 31, 2005 in an aggregate amount equal to the aggregate quarterly
dividend to be paid on April 29, 2005 by TransCanada on the issued and
outstanding common shares as at the close of business on March 31, 2005.
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, 2004, under the most restrictive
provisions, approximately $1.4 billion was available for the payment of
dividends on common shares.
Financing activities include a net increase in TCPL's proportionate share of
non-recourse debt of joint ventures of $120 million in 2004 compared to net
reductions of $11 million in 2003 and $36 million in 2002.
Credit Activities In December 2004, TCPL renewed shelf prospectuses that
qualified for issuance $1.5 billion of medium-term notes in Canada and US$1
billion of debt securities in the U.S. In January 2005, $300 million of 5.10 per
cent medium-term notes due 2017 were issued under the Canadian shelf
prospectus.
At December 31, 2004, total credit facilities of $2.0 billion were available to
support the company's commercial paper program and for general corporate
purposes. Of this total, $1.5 billion is a committed syndicated credit facility
established in December 2002. This facility is comprised of a $1.0 billion
tranche with a five-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 2004: the $1.0 billion tranche to December 2009 and the $500 million
tranche to December 2005. The remaining amounts are either demand or
non-extendible facilities.
At December 31, 2004, TCPL had used approximately $61 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, 2004 was
approximately $10.5 billion compared to approximately $10.0 billion at December
31, 2003. TCPL's share of total non-recourse debt of joint ventures at December
31, 2004 was $862 million compared to $780 million at December 31, 2003. Total
notes payable, including the proportionate share of joint ventures, at December
31, 2004 were $546 million compared to $367 million at
M-33
December 31, 2003. 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 do not extend to the rights and assets of
TCPL, except to the extent of TCPL's investment.
Effective January 1, 2005, under new Canadian accounting standards, the equity
component of preferred securities, amounting to $670 million at December 31,
2004, will be classified as debt.
At December 31, 2004, 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)
2005 2006 2007 2008 2009 2010+
Long-term debt 766 387 615 545 753 7,413
Non-recourse debt of joint 83 49 18 18 141 553
ventures
Total principal repayments 849 436 633 563 894 7,966
At December 31, 2004, future annual payments, net of sub-lease receipts, under
the company's operating leases for various premises and a natural gas storage
facility are approximately as follows.
OPERATING LEASE PAYMENTS
Year ended December 31 (millions of dollars)
2005 2006 2007 2008 2009 2010+
Minimum lease payments 37 45 51 53 53 697
Amounts recoverable under (9 ) (10 ) (9 ) (9 ) (9 ) (21 )
sub-leases
Net payments 28 35 42 44 44 676
The operating lease agreements for premises expire at various dates through
2011, with an option to renew certain lease agreements for five years. The
operating lease agreement for the natural gas storage facility expires in 2030
with lessee termination rights every fifth anniversary commencing in 2010 and
with the lessor having the right to terminate the agreement every five years
commencing in 2015.
At December 31, 2004, the company's future purchase obligations are
approximately as follows.
PURCHASE OBLIGATIONS(1)
Year ended December 31 (millions of dollars)
2005 2006 2007 2008 2009 2010+
Gas Transmission
Transportation by others(2) 186 177 142 121 82 198
Other 94 46 42 40 2 3
Power
Commodity purchases(3) 429 255 259 266 277 2,658
Capital expenditures(4) 288 70 - - - -
Other(5) 93 100 89 84 88 223
Corporate
Information technology and 9 9 7 7 7 -
other
Total purchase obligations 1,099 657 539 518 456 3,082
M-34
(1)
The amounts in this table exclude funding contributions to the company's
pension plans and funding to APG.
(2)
Rates are based on known 2005 levels. Beyond 2005, demand rates are subject
to change. The contract obligations in the table are based on known or
contracted demand volumes only and exclude commodity charges incurred when
volumes flow.
(3)
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.
During 2005, TCPL expects to make funding contributions to the company's
pension plans and other benefit plans in the amount of approximately $67 million
and $6 million, respectively. The expected decrease in total funding in 2005
from $88 million in 2004 is due to investment performance above long-term
expectations in 2004 partially offset by continued reductions in discount rates
used to calculate plan obligations.
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
connect with the Alberta System. Under the agreement, TCPL agreed to finance the
APG for its one-third share of project development costs. This share is
currently estimated to be approximately $90 million. As at December 31, 2004,
TCPL had funded $60 million of this loan (2003 - $34 million) which is included
in other assets on the balance sheet. The ability to recover this investment is
dependent upon the outcome of the project.
TCPL had a $50 million operating line of credit to Power LP, available on a
revolving basis. In August 2004, the amount borrowed against this line of credit
was fully repaid by Power LP and the operating line of credit was terminated.
At December 31, 2004, 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 with
TCPL. At December 31, 2004, the partnership had US$6.5 million outstanding under
this credit facility (December 31, 2003 - nil).
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, 2004.
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, 2004 was
estimated to be approximately $158 million of a maximum of $293 million. The
terms of the guarantees range from 2005 to 2018. The current carrying amount of
the liability related to these guarantees is nil and the fair value is
approximately $9 million.
TCPL has guaranteed the equity undertaking of a subsidiary which supports the
payment, under certain conditions, of principal and interest on US$161 million
of 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.
In connection with the acquisition of GTN, US$241 million of the purchase price
was deposited into an escrow account. The escrowed funds represent the full face
amount of the potential liability under certain GTN guarantees and are to be
used to satisfy the liability under these designated guarantees.
M-35
Contingencies The Canadian Alliance of Pipeline Landowners' Associations and
two individual landowners commenced an action in 2003 under Ontario's Class
Proceedings Act, 1992, against TCPL and Enbridge Inc. for damages of $500
million 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.
This information is provided by RNS
The company news service from the London Stock Exchange
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