RNS Number:8669J
TransCanada Pipelines Ld
16 March 2005
PART 4
FINANCIAL AND OTHER INSTRUMENTS
The company issues short-term and long-term debt, including amounts in foreign
currencies, purchases and sells energy commodities and invests in foreign
operations. These activities result in exposures to interest rates, energy
commodity prices and foreign currency exchange rates. The company utilizes
derivative and other financial instruments to manage its exposure to the risks
that result from these activities.
A derivative must be designated and effective to be accounted for as a hedge.
Gains or losses relating to derivatives that are hedges are deferred and
recognized in the same period and in the same financial statement category as
the corresponding hedged transactions. The recognition of gains and losses on
derivatives used as hedges for Canadian Mainline, Alberta System, GTN and the
Foothills System exposures is determined through the regulatory process.
The carrying amounts of derivatives, which hedge the price risk of foreign
currency denominated assets and liabilities of self-sustaining foreign
operations, are recorded on the balance sheet at their fair value. Gains and
losses on these derivatives, realized and unrealized, are included in the
foreign exchange adjustment account in Shareholders' Equity as an offset to the
corresponding gains and losses on the translation of the assets and liabilities
of the foreign subsidiaries. As of January 1, 2004, carrying amounts for
interest rate swaps are recorded on the balance sheet at their fair value.
Foreign currency transactions hedged by foreign exchange contracts are recorded
at the contract rate. Power, natural gas and heat rate derivatives are recorded
on the balance sheet at their fair value.
The fair values of foreign exchange and interest rate derivatives have been
estimated using year-end market rates. The fair values of power, natural gas and
heat rate derivatives have been calculated using estimated forward prices for
the relevant period.
Notional principal amounts are not recorded in the financial statements because
these amounts are not exchanged by the company and its counterparties and are
not a measure of the company's exposure. Notional amounts are used only as the
basis for calculating payments for certain derivatives.
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Foreign Investments At December 31, 2004 and 2003, the company had foreign
currency denominated assets and liabilities which created an exposure to changes
in exchange rates. The company uses foreign currency derivatives to hedge this
net exposure on an after-tax basis. The foreign currency derivatives have a
floating interest rate exposure which the company partially hedges by entering
into interest rate swaps and forward rate agreements. The fair values shown in
the table below for those derivatives that have been designated as and are
effective as hedges for foreign exchange risk are offset by translation gains or
losses on the net assets and are recorded in the foreign exchange adjustment
account in Shareholders' Equity.
Net Investment in Foreign Assets
Asset/(Liability) December 31 2004 2003
(millions of dollars)
Accounting Fair Value Notional Fair Notional
Treatment or Value or
Principal Principal
Amount Amount
(U.S.) (U.S.)
U.S. dollar cross-currency swaps Hedge 95 400 65 250
(maturing 2006 to 2009)
U.S. dollar forward foreign Hedge (1 ) 305 3 125
exchange contracts (maturing
2005)
U.S. dollar options (maturing Non-hedge 1 100 - -
2005)
In accordance with the company's accounting policy, each of the above
derivatives is recorded on the consolidated balance sheet at its fair value in
2004. For derivatives that have been designated as and are effective as hedges
of the net investment in foreign operations, the offsetting amounts are included
in the foreign exchange adjustment account.
In addition, at December 31, 2004, the company had interest rate swaps
associated with the cross-currency swaps with notional principal amounts of $375
million (2003 - $311 million) and US$250 million (2003 - US$200 million). The
carrying amount and fair value of these interest rate swaps was $4 million (2003
- $3 million) and $4 million (2003 - $1 million), respectively.
Reconciliation of Foreign Exchange Adjustment Gains/(Losses)
December 31 (millions of dollars) 2004 2003
Balance at beginning of year (40 ) 14
Translation losses on foreign currency denominated net assets (64 ) (136 )
Foreign exchange gains on derivatives, net of income taxes 33 82
(71 ) (40 )
Foreign Exchange Gains/(Losses)
Foreign exchange gains/(losses) included in Other Expenses/(Income) for the
year ended December 31, 2004 are $4 million (2003 - nil; 2002 - $(11) million).
Foreign Exchange and Interest Rate Management Activity
The company manages certain of the foreign exchange risks of U.S. dollar debt,
U.S. dollar expenses and the interest rate exposures of the Canadian Mainline,
the Alberta System, GTN and the Foothills System through the use of foreign
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currency and interest rate derivatives. Certain of the realized gains and losses
on these derivatives are shared with shippers on predetermined terms. The
details of the foreign exchange and interest rate derivatives are shown in the
table below.
Asset/(Liability) December 31 2004 2003
(millions of dollars)
Accounting Fair Value Notional Fair Value Notional
Treatment or or
Principal Principal
Amount Amount
Foreign Exchange
Cross-currency swaps
(maturing 2010 to 2012) Hedge (39 ) U.S. 157 (26 ) U.S. 282
Interest Rate
Interest rate swaps
Canadian dollars
(maturing 2005 to 2008) Hedge 7 145 (1 ) 340
(maturing 2006 to 2009) Non-hedge 9 374 10 624
16 9
U.S. dollars
(maturing 2010 to 2015) Hedge (2 ) U.S. 275 11 U.S. 50
(maturing 2007 to 2009) Non-hedge 7 U.S. 100 (3 ) U.S. 50
5 8
In accordance with the company's accounting policy, each of the above
derivatives is recorded on the consolidated balance sheet at its fair value in
2004. At December 31, 2004, the company also had interest rate swaps associated
with the cross-currency swaps with notional principal amounts of $227 million
(2003 - $390 million) and US$157 million (2003 - US$282 million). The carrying
amount and fair value of these interest rate swaps was $(4) million (2003 - nil)
and $(4) million (2003 - $6 million), respectively.
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The company manages the foreign exchange and interest rate exposures of its
other businesses through the use of foreign currency and interest rate
derivatives. The details of these foreign currency and interest rate derivatives
are shown in the table below.
Asset/(Liability) December 31 2004 2003
(millions of dollars)
Accounting Fair Value Notional Fair Value Notional
Treatment or or
Principal Principal
Amount Amount
Foreign Exchange
Options (maturing 2005) Non-hedge 2 U.S. 225 1 U.S. 25
Forward foreign exchange
contracts
(maturing 2005) Non-hedge 1 U.S. 29 1 U.S. 19
Cross-currency swaps
(maturing 2013) Hedge (16 ) U.S. 100 (7 ) U.S. 100
Interest Rate
Options (maturing 2005) Non-hedge - U.S. 50 (2 ) U.S. 50
Interest rate swaps
Canadian dollar
(maturing 2007 to 2009) Hedge 4 100 2 50
(maturing 2005 to 2011) Non-hedge 1 110 2 100
5 4
U.S. dollar
(maturing 2006 to 2013) Hedge 5 U.S. 100 40 U.S. 250
(maturing 2006 to 2010) Non-hedge 22 U.S. 250 (3 ) U.S. 200
27 37
In accordance with the company's accounting policy, each of the above
derivatives is recorded on the consolidated balance sheet at its fair value in
2004. At December 31, 2004, the company also had interest rate swaps associated
with the cross-currency swaps with notional principal amounts of $136 million
(2003 - $136 million) and US$100 million (2003 - US$100 million). The carrying
amount and fair value of these interest rate swaps was $(10) million (2003 -
nil) and $(10) million (2003 - $(7) million), respectively.
Certain of the company's joint ventures use interest rate derivatives to manage
interest rate exposures. The company's proportionate share of the fair value of
the outstanding derivatives at December 31, 2004 was $1 million (2003 - $(1)
million).
Energy Price Risk Management The company executes power, natural gas and
heat rate derivatives for overall management of its asset portfolio. Heat rate
contracts are contracts for the sale or purchase of power that are priced based
on a natural gas index. The fair values and notional volumes of the swap,
option, forward and heat rate contracts are shown in the tables below. In
accordance with the company's accounting policy, each of the derivatives in the
table below is recorded on the balance sheet at its fair value in 2004 and 2003.
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Power
Asset/(Liability) December 31 (millions of dollars) 2004 2003
Accounting Fair Fair
Treatment Value Value
Power - swaps
(maturing 2005 to 2011) Hedge 7 (5 )
(maturing 2005) Non-hedge (2 ) -
Gas - swaps, forwards and options
(maturing 2005 to 2016) Hedge (39 ) (34 )
(maturing 2005) Non-hedge (2 ) (1 )
Heat rate contracts
(maturing 2005 to 2006) Hedge (1 ) (1 )
Power (GWh) Gas (Bcf)
Notional Volumes December 31, 2004 Accounting Purchases Sales Purchases Sales
Treatment
Power - swaps
(maturing 2005 to 2011) Hedge 3,314 7,029 - -
(maturing 2005) Non-hedge 438 - - -
Gas - swaps, forwards and options
(maturing 2005 to 2016) Hedge - - 80 84
(maturing 2005) Non-hedge - - 5 8
Heat rate contracts
(maturing 2005 to 2006) Hedge - 229 2 -
December 31, 2003
Power - swaps Hedge 1,331 4,787 - -
Non-hedge 59 77 - -
Gas - swaps, forwards and options Hedge - - 79 81
Non-hedge - - - 7
Heat rate contracts Hedge - 735 1 -
U.S. Dollar Transaction Hedges To reduce risk and protect margins when
purchase and sale contracts are denominated in different currencies, the company
may enter into forward foreign exchange contracts and foreign exchange options
which establish the foreign exchange rate for the cash flows from the related
purchase and sale transactions.
RISK MANAGEMENT
Risk Management Overview TCPL and its subsidiaries are exposed to market,
financial and counterparty risks in the normal course of their business
activities. The risk management function assists in managing these various
business activities and the risks associated with them. A strong commitment to a
risk management culture by TCPL's management supports this function. TCPL's
primary risk management objective is to protect earnings and cash flow.
The risk management function is guided by the following principles that are
applied to all businesses and risk types:
*
Board Oversight Risk strategies, policies and limits are subject to
review and approval by TCPL's Board of Directors.
*
Independent Review Risk-taking activities are subject to independent
review, separate from the business lines that initiate the activity.
*
Assessment Processes are in place to ensure that risks are properly
assessed at the transaction and counterparty levels.
*
Review and Reporting Market positions and exposures, and the
creditworthiness of counterparties are subject to ongoing review and
reporting to executive management.
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*
Accountability Business lines are accountable for all risks and the
related returns for their particular businesses.
*
Audit Review Individual risks are subject to internal audit review,
with independent reporting to the Audit Committee of TCPL's Board of
Directors.
The processes within TCPL's risk management function are designed to ensure
that risks are properly identified, quantified, reported and managed. Risk
management strategies, policies and limits are designed to ensure TCPL's risk
taking is consistent with the company's business objectives and risk tolerance.
Risks are managed within limits ultimately established by the company's Board of
Directors and implemented by senior management, monitored by risk management
personnel and audited by internal audit personnel.
TCPL manages market risk exposures in accordance with the company's corporate
market risk policies and position limits. The company's primary market risks
result from volatility in commodity prices, interest rates and foreign currency
exchange rates.
Senior management reviews these exposures and reports on a regular basis to the
Audit Committee of TCPL's Board of Directors.
Market Risk Management In order to manage market risk exposures created by
fixed and variable pricing arrangements at different pricing indices and
delivery points, the company enters into offsetting physical positions and
derivative financial instruments. Market risks are quantified using
value-at-risk methodology and are reviewed weekly by senior management.
Financial Risk Management TCPL monitors the financial market risk exposures
relating to the company's investments in foreign currency denominated net
assets, regulated and non-regulated long-term debt portfolios and foreign
currency exposure on transactions. The market risk exposures created by these
business activities are managed by establishing offsetting positions or through
the use of derivative financial instruments.
Counterparty Risk Management Counterparty risk is the financial loss that
the company would experience if the counterparty failed to meet its obligations
in accordance with the terms and conditions of its contracts with the company.
Counterparty risk is mitigated by conducting financial and other assessments to
establish a counterparty's creditworthiness, setting exposure limits and
monitoring exposures against these limits, and, where warranted, obtaining
financial assurances.
The company's counterparty risk management practices and positions are further
described in Note 15 to the consolidated financial statements.
Risks and Risk Management Related to the Kyoto Protocol TCPL believes that
the natural gas that is transported and the electricity that is generated by its
facilities play a critical role in meeting continental energy demand. The
company also recognizes, however, that its facilities produce emissions that can
also contribute to climate change and air related issues. For this reason, the
management of air emissions and climate change issues is a key area of the
company's environmental stewardship work.
Climate change policy development is well under way in North America. In
December 2002, the Canadian government registered its instrument of ratification
with the United Nations, making Canada the 100th country to ratify the Kyoto
Protocol. Following ratification, the federal government initiated discussions
with industry regarding emissions reductions from sources in three broad
categories: the oil and gas sector, the electricity sector and the mining/
manufacturing sector. The mechanism that is proposed for achieving the reduction
is a domestic emissions trading system that would cap emissions from sectors at
predetermined emissions intensity levels.
As direct emitters of greenhouse gas emissions, TCPL's facilities will be
impacted by climate change policy developments in Canada. The fossil-fired power
plants, pipeline systems and carbon black facilities are expected to be captured
under the proposed federal government plan for industrial emitters. At present,
however, the details of the target allocation within sectors and allowable
compliance options have not been finalized. Until the allocation of targets
within the sector are set and until compliance options are fully developed, it
is difficult to determine the level of impact to the company's Canadian asset
base.
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Over the next year, TCPL will continue to participate in climate change policy
discussions in the jurisdictions where the company has assets and business
interests. Climate change is a strategic issue for TCPL and management of this
important environmental concern has been ongoing for several years. TCPL has a
comprehensive climate change strategy in place that includes five key areas of
activities:
*
participation in policy forums;
*
implementation of direct emissions reduction programs;
*
assessment of new technology;
*
evaluation of emissions trading mechanisms; and
*
assessment of business opportunities.
Activities are ongoing in each of these areas and the company is committed to
sharing its progress on key activities publicly. Over the past several years,
TCPL has documented its technical activities and research and development work
in yearly reports to Canada's Climate Change Voluntary Challenge & Registry Inc.
The Canadian government has legislated mandatory greenhouse gas emissions
reporting beginning in 2005. TCPL will continue to report on the activities that
are under way to manage greenhouse gas emissions.
Disclosure Controls and Procedures and Internal Controls Pursuant to
regulations adopted by the U.S. Securities and Exchange Commission (SEC), under
the Sarbanes-Oxley Act of 2002, TCPL's management evaluates the effectiveness of
the design and operation of the company's disclosure controls and procedures
(disclosure controls). This evaluation is done under the supervision of, and
with the participation of, the President and Chief Executive Officer and the
Chief Financial Officer.
As of the end of the period covered by this report, TCPL's management evaluated
the effectiveness of its disclosure controls. Based on that evaluation, the
President and Chief Executive Officer and the Chief Financial Officer have
concluded that TCPL's disclosure controls are effective in ensuring that
material information relating to TCPL is made known to management on a timely
basis, and is included in this report.
To the best of these officers' knowledge and belief, there have been no
significant changes in internal controls over financial reporting or in other
factors that could significantly affect internal controls over financial
reporting subsequent to the date on which such evaluation was completed in
connection with this report.
CEO and CFO Certifications With respect to the year ending December 31,
2004, TCPL's President and Chief Executive Officer has provided the New York
Stock Exchange the annual CEO certification regarding TCPL's compliance with the
New York Stock Exchange's corporate governance listing standards applicable to
foreign issuers. In addition, TCPL's President and Chief Executive Officer and
Chief Financial Officer have filed with the SEC certifications regarding the
quality of TCPL's public disclosures relating to its fiscal 2004 reports filed
with the SEC.
CRITICAL ACCOUNTING POLICY
The company accounts for the impacts of rate regulation in accordance with
generally accepted accounting principles (GAAP) as outlined in Note 1 to the
consolidated financial statements. Three criteria must be met to use these
accounting principles: the rates for regulated services or activities must be
subject to approval by a regulator; the regulated rates must be designed to
recover the cost of providing the services or products; and it must be
reasonable to assume that rates set at levels to recover the cost can be charged
to and will be collected from customers in view of the demand for services or
products and the level of direct and indirect competition. The company's
management believes that all three of these criteria have been met. The most
significant impact from the use of these accounting principles is that in order
to appropriately reflect the economic impact of the regulators' decisions
regarding the company's revenues and tolls, and to thereby achieve a proper
matching of revenues and expenses, the timing of recognition of certain expenses
and revenues in the regulated businesses may differ from that otherwise expected
under GAAP. The most significant example of this relates to the recording of
income taxes on the taxes payable basis as outlined in Note 16 to the
consolidated financial statements.
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CRITICAL ACCOUNTING ESTIMATE
Since a determination of many assets, liabilities, revenues and expenses is
dependent upon future events, the preparation of the company's consolidated
financial statements requires the use of estimates and assumptions which have
been made using careful judgment. TCPL's critical accounting estimate is
depreciation expense. TCPL's plant, property and equipment are depreciated on a
straight-line basis over their estimated useful lives. Depreciation expense for
the year ended December 31, 2004 was $945 million. Depreciation expense impacts
the Gas Transmission and Power segments of the company. In the Gas Transmission
business, depreciation rates are approved by the regulators and recoverable
based on the cost of providing the services or products. A change in the
estimation of the useful lives of the plant, property and equipment in the Gas
Transmission segment would, if recovery through rates is permitted by the
regulators, have no material impact on TCPL's net income but would directly
impact funds generated from operations.
In 2004, TCPL recognized in income the remaining amount related to the critical
accounting estimate of the after-tax deferred gain recorded on the 2001 sale of
the Gas Marketing business, which is further described in Discontinued
Operations.
ACCOUNTING CHANGES
Asset Retirement Obligations In January 2003, the Canadian Institute of
Chartered Accountants (CICA) issued a new Handbook Section "Asset Retirement
Obligations". The new section focuses on the recognition and measurement of
liabilities for obligations associated with the retirement of property, plant
and equipment when those obligations result from the acquisition, construction,
development or normal operation of the assets. The section requires that the
fair value of a liability for an asset retirement obligation be recognized in
the period in which it is incurred if a reasonable estimate of fair value can be
made. The fair value is added to the carrying amount of the associated asset.
The liability is accreted at the end of each period through charges to operating
expenses. This section was effective for TCPL as of January 1, 2004 and was
applied retroactively with restatement of prior periods. See Note 2 to the
consolidated financial statements for the impact of this accounting change.
Hedging Relationships Effective January 1, 2004, the company adopted the
provisions of the CICA's new Accounting Guideline "Hedging Relationships" that
specifies the circumstances in which hedge accounting is appropriate, including
the identification, documentation, designation and effectiveness of hedges, and
the discontinuance of hedge accounting. See Note 2 to the consolidated financial
statements for the impact of this accounting change.
Generally Accepted Accounting Principles Effective January 1, 2004, the
company adopted the new Handbook Section "Generally Accepted Accounting
Principles" which establishes standards for financial reporting in accordance
with GAAP. It defines primary sources of GAAP and requires that an entity apply
every relevant primary source, therefore eliminating the ability to rely on
industry practice to support a particular accounting policy and provides an
exemption for rate-regulated operations. This section was applied prospectively.
See Note 2 to the consolidated financial statements for the impact of this
accounting change.
General Standards of Financial Statement Presentation Effective January 1,
2004, the company adopted the new Handbook Section "General Standards of
Financial Statement Presentation" which clarifies what constitutes "fair
presentation in accordance with GAAP". The adoption of this section did not have
an impact on the company's consolidated financial statements.
Employee Future Benefits In March 2004, the CICA amended the existing
Handbook Section "Employee Future Benefits". The amendments expand the
disclosure requirements for employee future benefits and are effective for
fiscal years ending on or after June 30, 2004. The company adopted these
provisions effective December 31, 2004. The impacts of the amendments have been
included in Note 19 to the consolidated financial statements.
Impairment of Long-Lived Assets Effective January 1, 2004, the company
adopted the new Handbook Section "Impairment of Long-Lived Assets". This section
establishes new standards for the recognition, measurement and disclosure of the
impairment of long-lived assets and establishes new write-down provisions. The
adoption of this section did not have an impact on the company's consolidated
financial statements.
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Consolidation of Variable Interest Entities In June 2003, the Accounting
Standards Board of the CICA issued a new Accounting Guideline "Consolidation of
Variable Interest Entities" which requires enterprises to identify variable
interest entities in which they have an interest, determine whether they are the
primary beneficiary of such entities and, if so, to consolidate them. For TCPL,
the guideline's requirements are effective as of January 1, 2005. Adopting the
provisions of this guideline is not expected to impact the company's
consolidated financial statements.
Financial Instruments - Disclosure and Presentation In November 2004, the
CICA amended the existing Handbook Section "Financial Instruments - Disclosure
and Presentation" to provide guidance for classifying certain financial
instruments that embody obligations that may be settled by the issuance of the
issuer's equity shares as debt when the instrument that embodies the obligations
does not establish an ownership relationship. This amendment is effective for
fiscal years beginning on or after November 1, 2004. As a result, the equity
component of preferred securities will be classified as debt effective January
1, 2005.
DISCONTINUED OPERATIONS
TCPL's Board of Directors approved plans in previous years to dispose of the
company's International, Canadian Midstream, Gas Marketing and certain other
businesses. As of December 31, 2003, TCPL's investments in Gasoducto del
Pacifico (Gas Pacifico), INNERGY Holdings S.A. (INNERGY) and P.T. Paiton Energy
Company (Paiton), which were previously approved for disposal, were accounted
for as part of continuing operations due to the length of time it had taken the
company to dispose of these assets. Gas Pacifico and INNERGY are included in the
Gas Transmission segment and Paiton is included in the Power segment. It is the
intention of the company to continue with its plan to dispose of these
investments.
In 2004, the company reviewed the provision for loss on discontinued operations
and the after-tax deferred gain. As a result of this review, TCPL recognized in
income in 2004 the remaining $52 million of the original $102 million after-tax
deferred gain.
In 2003, TCPL recognized in income $50 million of the original $102 million
after-tax deferred gain. The company's net income/(loss) from discontinued
operations in 2002 was nil.
SUBSIDIARIES AND INVESTMENTS
TCPL and its subsidiaries and investments that hold significant operating
assets are noted below.
Subsidiary/Investment Major Operating Organized Effective
Assets under the Percentage
Laws of Ownership
by TCPL
TransCanada PipeLines Limited Canadian Mainline, Canada
BC System
NOVA Gas Transmission Ltd. Alberta System Alberta 100
TransCanada Pipeline Ventures Ltd. Ventures LP Alberta 100
Foothills Pipe Lines Ltd. Foothills System Canada 100
TransCanada Pipeline USA Ltd. Nevada 100
Gas Transmission Northwest Corporation GTN California 100
TransCanada Power Marketing Ltd. U.S. power Delaware 100
operations
Great Lakes Gas Transmission Limited Great Lakes Delaware 50
Partnership
Iroquois Gas Transmission System L.P. Iroquois Delaware 41
Portland Natural Gas Transmission Portland Maine 61.7
System Partnership
TC PipeLines, LP TC PipeLines, LP's Delaware 33.4
assets
Northern Border Pipeline Company Northern Border Texas 10
Tuscarora Gas Transmission Company Tuscarora Nevada 17.4
TransCanada Energy Ltd. Canadian power Canada 100
operations
TransCanada Power, L.P. Power LP assets Ontario 30.6
Bruce Power L.P. Bruce Power Ontario 31.6
Trans Quebec & Maritimes Pipeline Inc. TQM Canada 50
CrossAlta Gas Storage & Services Ltd. CrossAlta Alberta 60
TransGas de Occidente S.A. TransGas Colombia 46.5
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SELECTED THREE YEAR CONSOLIDATED FINANCIAL DATA(1)
(millions of dollars except per share amounts) 2004 2003 2002
Income Statement
Revenues 5,107 5,357 5,214
Net income
Continuing operations 978 801 747
Discontinued operations 52 50 -
1,030 851 747
Balance Sheet
Total assets 22,129 20,698 20,172
Long-term debt 9,713 9,465 8,815
Non-recourse debt of joint ventures 779 761 1,222
Preferred securities (liability component) 19 22 238
Per Common Share Data
Net income - Basic
Continuing operations $2.03 $1.66 $1.56
Discontinued operations 0.11 0.11 -
$2.14 $1.77 $1.56
Net income - Diluted
Continuing operations $2.03 $1.66 $1.55
Discontinued operations 0.11 0.11 -
$2.14 $1.77 $1.55
Dividends declared(2) $1.17 $1.08 $1.00
(1)
The selected three year consolidated financial data has been prepared in
accordance with Canadian GAAP. Certain comparative figures have been
reclassified to conform with the current year's presentation. For a
discussion on the factors affecting the comparability of the financial data,
including discontinued operations, refer to Note 1 and Note 22 of TCPL's
2004 audited consolidated financial statements.
(2)
Effective May 15, 2003, TCPL dividends have been declared in an amount equal
to the aggregate dividend paid by TransCanada. The amounts presented reflect
the aggregate amount divided by total outstanding common shares of TCPL.
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SELECTED QUARTERLY CONSOLIDATED FINANCIAL DATA(1)
(millions of dollars except per share amounts) Fourth Third Second First
2004
Revenues 1,394 1,224 1,256 1,233
Net income applicable to common shares
Continuing operations 184 192 388 214
Discontinued operations - 52 - -
184 244 388 214
SHARE STATISTICS
Net income per share - Basic and Diluted
Continuing operations $0.38 $0.40 $0.81 $0.44
Discontinued operations - 0.11 - -
$0.38 $0.51 $0.81 $0.44
Fourth Third Second First
2003
Revenues 1,319 1,391 1,311 1,336
Net income applicable to common shares
Continuing operations 193 198 202 208
Discontinued operations - 50 - -
193 248 202 208
SHARE STATISTICS
Net income per share - Basic and Diluted
Continuing operations $0.40 $0.41 $0.42 $0.43
Discontinued operations - 0.11 - -
$0.40 $0.52 $0.42 $0.43
(1)
The selected quarterly consolidated financial data has been prepared in
accordance with Canadian GAAP. Certain comparative figures have been
reclassified to conform with the current year's presentation. For a
discussion on the factors affecting the comparability of the financial data,
including discontinued operations, refer to Note 1 and Note 22 of TCPL's
2004 audited consolidated financial statements.
Factors Impacting Quarterly Financial Information
In the Gas Transmission business, which consists primarily of the company's
investments in regulated pipelines, annual revenues and net earnings fluctuate
over the long term based on regulators' decisions and negotiated settlements
with shippers. Generally, quarter over quarter revenues and earnings during any
particular fiscal year remain fairly stable with fluctuations arising as a
result of adjustments being recorded due to regulatory decisions and negotiated
settlements with shippers and due to items outside of the normal course of
operations.
In the Power business, which consists primarily of the company's investments in
electrical power generation plants, quarter over quarter revenues and net
earnings are affected by seasonal weather conditions, customer demand, market
prices, planned and unplanned plant outages as well as items outside of the
normal course of operations.
Significant items which impacted 2004 and 2003 quarterly net earnings are as
follows.
*
In first quarter 2003, TCPL completed the acquisition of a 31.6 per cent
interest in Bruce Power, resulting in increased equity income in the
Power business from thereon.
*
Second quarter 2003 net earnings included a $19 million positive
after-tax earnings impact of a June 2003 settlement with a former
counterparty that had previously defaulted under power forward
contracts.
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*
Third quarter 2003 net earnings included TCPL's $11 million share of a
positive future income tax benefit adjustment recognized by TransGas.
*
First quarter 2004 net earnings included approximately $12 million of
income tax refunds and related interest.
*
Second quarter 2004 net earnings included gains related to Power LP of
$187 million, of which $132 million were previously deferred and were
being amortized into income to 2017.
*
In third quarter 2004, the EUB's decisions on the GCOC and Phase I of
the 2004 GRA resulted in lower earnings for the Alberta System compared
to the previous quarters. In addition, third quarter 2004 included a $12
million after-tax adjustment related to the release of previously
established restructuring provisions and recognition of $8 million of
non-capital loss carryforwards.
*
In fourth quarter 2004, TCPL completed the acquisition of GTN, thereby
recording $14 million of earnings from the November 1, 2004 acquisition
date. Power recorded a $16 million pre-tax positive impact of a
restructuring transaction related to power purchase contracts between
OSP and Boston Edison in Eastern Operations.
Fourth Quarter 2004 Highlights
SEGMENT RESULTS-AT-A-GLANCE
Three months ended December 31 (millions of dollars)
2004 2003
Gas Transmission 157 160
Power 31 44
Corporate (4 ) (11 )
Net Income Applicable to Common Shares 184 193
Net income applicable to common shares and net earnings for fourth quarter 2004
for TCPL were $184 million compared to $193 million for the same period in 2003.
This decrease was primarily due to lower net earnings from the Power and Gas
Transmission businesses, partially offset by lower net expenses in the Corporate
segment.
Power's net earnings in fourth quarter 2004 of $31 million decreased $13
million compared to $44 million in fourth quarter 2003 primarily due to lower
earnings from Western Operations and Eastern Operations. Operating and other
income from Western Operations in fourth quarter 2004 of $25 million was $6
million lower compared to the $31 million earned in the same period in 2003. The
decrease was mainly due to a reduction in income from ManChief following the
sale of the plant to Power LP in April 2004, cumulative operating cost
adjustments settled in fourth quarter 2004 at the MacKay River cogeneration
plant and reduced margins resulting from lower market heat rates on uncontracted
volumes.
Operating and other income from Eastern Operations in fourth quarter 2004 of
$31 million was $5 million lower compared to $36 million earned in the same
period in 2003. The decrease was primarily 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,
earnings recorded in 2003 on the Cobourg temporary generation facility and a
weaker U.S. dollar in 2004 compared to 2003. Partially offsetting these
reductions was a $16 million pre-tax positive impact of a restructuring
transaction related to power purchase contracts between OSP and Boston Edison.
In fourth quarter 2004, TCPL closed a transaction with Boston Edison resulting
in TCPL assuming a 23.5 per cent share of the OSP power purchase contracts and
recognized earnings from the effective date of April 1, 2004.
For fourth quarter 2004, Gas Transmission's net earnings were $157 million
compared to $160 million in fourth quarter 2003. The $3 million decrease was due
to a $5 million reduction in earnings from Wholly-Owned Pipelines, partially
offset by a $2 million increase in net earnings from the Other Gas Transmission
businesses. The reduction in earnings from Wholly-Owned Pipelines was primarily
due to a decline in the Canadian Mainline and the Alberta System net earnings.
Regulatory decisions in 2004, as well as lower returns and investment bases,
resulted in lower earnings for the Canadian Mainline and the Alberta System.
These decreases were partially offset by net earnings of $14 million during the
quarter from TCPL's investment in GTN which was acquired in November 2004. The
increase in earnings from Other
M-47
Gas Transmission was primarily due to higher earnings from CrossAlta as a result
of favourable gas market storage conditions as well as higher earnings from
Ventures LP. These increases were partially offset by the impact of a weaker
U.S. dollar.
Net expenses, after tax, in the Corporate segment for the quarter ended
December 31, 2004 were $4 million compared to $11 million for the corresponding
period in 2003. The $7 million decrease in Corporate net expenses for the three
months ended December 31, 2004 compared to the same period in 2003 was primarily
due to the positive impacts of income tax and foreign exchange related items.
SHARE INFORMATION
As at March 1, 2005, TCPL had 480,668,109 issued and oustanding common shares
and there were no outstanding options to purchase common shares.
OTHER INFORMATION
Additional information relating to TCPL, including the company's Annual
Information Form and continuous disclosure documents, is posted on SEDAR at
www.sedar.com under TransCanada PipeLines Limited.
Other selected consolidated financial information for the years ended December
31, 2004, 2003, 2002, 2001, and 2000 is found under the heading "Five-Year
Financial Highlights" on pages F-48 and F-49 of this report.
FORWARD-LOOKING INFORMATION
Certain information in this Management's Discussion and Analysis is
forward-looking and is subject to important risks and uncertainties. The results
or events predicted in this information may differ from actual results or
events. Factors which could cause actual results or events to differ materially
from current expectations include, among other things, the ability of TCPL to
successfully implement its strategic initiatives and whether such strategic
initiatives will yield the expected benefits, the availability and price of
energy commodities, regulatory decisions, competitive factors in the pipeline
and power industry sectors and the prevailing economic conditions in North
America. For additional information on these and other factors, see the reports
filed by TCPL with Canadian securities regulators and with the SEC. TCPL
disclaims any intention or obligation to update or revise any forward-looking
statements, whether as a result of new information, future events or otherwise.
M-48
GLOSSARY OF TERMS
2004 Application 2004 Canadian Mainline Tolls and Tariff Application
APG Aboriginal Pipeline Group
ATCO ATCO Pipelines
B.C. British Columbia
Bcf/d Billion cubic feet per day
Boston Edison Boston Edison Company
Bruce Power Bruce Power L.P.
Cameco Cameco Corporation
CAPP Canadian Association of Petroleum Producers
Cartier Wind Cartier Wind Energy
CBM Coalbed methane
CICA Canadian Institute of Chartered Accountants
CrossAlta CrossAlta Gas Storage & Services Ltd.
DBRS Dominion Bond Rating Service Limited
Disclosure controls Disclosure controls and procedures
EUB Alberta Energy and Utilities Board
FCA Federal Court of Appeal
FERC U. S. Federal Energy Regulatory Commission
Foothills Foothills Pipe Lines Ltd.
FT Firm transportation
FT-NR Non-renewable firm transportation
FT-RAM Firm transportation service enhancement
GAAP Generally accepted accounting principles
Gas Pacifico Gasoducto del Pacifico
GCOC Generic Cost of Capital
GRA General Rate Application
Great Lakes Great Lakes Gas Transmission System
GTN Gas Transmission Northwest System and the North Baja System,
collectively
GUA Gas Utilities Act (Alberta)
GWh Gigawatt hours
Hydro-Quebec Hydro-Quebec Distribution
INNERGY INNERGY Holdings S.A.
Iroquois Iroquois Gas Transmission System
Keystone Keystone Pipeline
Km Kilometres
LNG Liquefied natural gas
Millennium Millennium Pipeline project
MMcf/d Million cubic feet per day
Moody's Moody's Investors Service
MW Megawatts
MWh Megawatt hour
NBJ North Bay Junction
NEB National Energy Board
Net earnings Net income from continuing operations
Northern Border Northern Border Pipeline
NPA Northern Pipeline Act of Canada
OM&A Operating, maintenance and administration
OPG Ontario Power Generation
OSP Ocean State Power
Paiton P.T. Paiton Energy Company
Portland Portland Natural Gas Transmission System
Portlands Energy Portlands Energy Centre L.P.
Power LP TransCanada Power, L.P.
PPAs Power purchase arrangements
M-49
ROE Rate of return on common equity
SEC U.S. Securities and Exchange Commission
Shell Shell US Gas & Power LLC
Simmons Simmons Pipeline System
TCPL or the company TransCanada PipeLines Limited
TCPM TransCanada Power Marketing Limited
The Consortium The consortium that includes Cameco and BPC Generation Infrastructure
Trust
TQM Trans Quebec & Maritimes System
TransCanada TransCanada Corporation
TransGas TransGas de Occidente S.A.
Tuscarora Tuscarora Gas Transmission System
U.S. United States
USGen USGen New England
Ventures LP TransCanada Pipeline Ventures Limited Partnership
Vermont Hydroelectric Vermont Hydroelectric Power Authority
WCSB Western Canada Sedimentary Basin
M-50
TransCanada PipeLines Limited
Consolidated Financial Statements
December 31, 2004
F-1
REPORT OF MANAGEMENT
The consolidated financial statements included in this report are the
responsibility of Management and have been approved by the Board of Directors of
the Company. These consolidated financial statements have been prepared by
Management in accordance with generally accepted accounting principles (GAAP) in
Canada and include amounts that are based on estimates and judgments. Financial
information contained elsewhere in this report is consistent with the
consolidated financial statements.
Management has prepared Management's Discussion and Analysis which is based on
the Company's financial results prepared in accordance with Canadian GAAP. It
compares the Company's financial performance in 2004 to 2003 and should be read
in conjunction with the consolidated financial statements and accompanying
notes. In addition, significant changes between 2003 and 2002 are highlighted.
Note 23 to the consolidated financial statements describes the impact on the
consolidated financial statements of significant differences between Canadian
and United States GAAP.
Management has developed and maintains a system of internal accounting
controls, including a program of internal audits. Management believes that these
controls provide reasonable assurance that financial records are reliable and
form a proper basis for preparation of financial statements. The internal
accounting control process includes Management's communication to employees of
policies which govern ethical business conduct.
The Board of Directors has appointed an Audit Committee consisting of
unrelated, non-management directors which meets at least five times during the
year with Management and independently with each of the internal and external
auditors and as a group to review any significant accounting, internal control
and auditing matters. The Audit Committee reviews the consolidated financial
statements before the consolidated financial statements are submitted to the
Board of Directors for approval. The internal and external auditors have free
access to the Audit Committee without obtaining prior Management approval.
With respect to the external auditors, KPMG LLP, the Audit Committee approves
the terms of engagement and reviews the annual audit plan, the Auditors' Report
and results of the audit. It also recommends to the Board of Directors the firm
of external auditors to be appointed by the shareholders.
The independent external auditors, KPMG LLP, have been appointed by the
shareholders to express an opinion as to whether the consolidated financial
statements present fairly, in all material respects, the Company's financial
position, results of operations and cash flows in accordance with Canadian GAAP.
The report of KPMG LLP on page F-3 outlines the scope of their examination and
their opinion on the consolidated financial statements.
Harold N. Kvisle Russell K. Girling
President and Executive Vice-President, Corporate
Chief Executive Officer Development and Chief Financial Officer
February 28, 2005
F-2
AUDITORS' REPORT
To the Shareholder of TransCanada PipeLines Limited
We have audited the consolidated balance sheets of TransCanada PipeLines
Limited as at December 31, 2004 and 2003 and the statements of consolidated
income, consolidated retained earnings and consolidated cash flows for each of
the years in the three-year period ended December 31, 2004. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with Canadian generally accepted auditing
standards. Those standards require that we plan and perform an audit to obtain
reasonable assurance whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
In our opinion, these consolidated financial statements present fairly, in all
material respects, the financial position of the Company as at December 31, 2004
and 2003 and the results of its operations and its cash flows for each of the
years in the three-year period ended December 31, 2004 in accordance with
Canadian generally accepted accounting principles.
Chartered Accountants
Calgary, Canada
February 28, 2005
F-3
TRANSCANADA PIPELINES LIMITED
CONSOLIDATED INCOME
Year ended December 31 (millions of dollars) 2004 2003 2002
Revenues 5,107 5,357 5,214
Operating Expenses
Cost of sales 539 692 627
Other costs and expenses 1,635 1,682 1,546
Depreciation 945 914 848
3,119 3,288 3,021
Operating Income 1,988 2,069 2,193
Other Expenses/(Income)
Financial charges (Note 9) 812 821 867
Financial charges of joint ventures 60 77 90
Equity income (Note 7) (171 ) (165 ) (33 )
Interest income and other (65 ) (60 ) (53 )
Gains related to Power LP (Note 8) (197 ) - -
439 673 871
Income from Continuing Operations before Income Taxes and 1,549 1,396 1,322
Non- Controlling Interests
Income Taxes (Note 16)
Current 431 305 270
Future 77 230 247
508 535 517
Non-Controlling Interests 10 2 -
Net Income from Continuing Operations 1,031 859 805
Net Income from Discontinued Operations (Note 22) 52 50 -
Net Income 1,083 909 805
Preferred Securities Charges 31 36 36
Preferred Share Dividends 22 22 22
Net Income Applicable to Common Shares 1,030 851 747
Net Income Applicable to Common Shares
Continuing operations 978 801 747
Discontinued operations 52 50 -
1,030 851 747
The accompanying notes to the consolidated financial statements are an integral
part of these statements.
F-4
TRANSCANADA PIPELINES LIMITED
CONSOLIDATED CASH FLOWS
Year ended December 31 (millions of dollars) 2004 2003 2002
Cash Generated from Operations
Net income from continuing operations 1,031 859 805
Depreciation 945 914 848
Future income taxes 77 230 247
Gains related to Power LP (197 ) - -
Equity income in excess of distributions received (Note 7) (123 ) (119 ) (6 )
Pension funding in excess of expense (29 ) (65 ) (33 )
Other (32 ) (9 ) (34 )
Funds generated from continuing operations 1,672 1,810 1,827
Decrease in operating working capital (Note 20) 33 112 33
Net cash provided by continuing operations 1,705 1,922 1,860
Net cash (used in)/provided by discontinued operations (6 ) (17 ) 59
1,699 1,905 1,919
Investing Activities
Capital expenditures (476 ) (391 ) (599 )
Acquisitions, net of cash acquired (Note 8) (1,516 ) (570 ) (228 )
Disposition of assets (Note 8) 410 - -
Deferred amounts and other (24 ) (138 ) (112 )
Net cash used in investing activities (1,606 ) (1,099 ) (939 )
Financing Activities
Dividends and preferred securities charges (623 ) (588 ) (546 )
Advances from parent 35 46 -
Notes payable issued/(repaid), net 179 (62 ) (46 )
Long-term debt issued 1,042 930 -
Reduction of long-term debt (997 ) (744 ) (486 )
Non-recourse debt of joint ventures issued 233 60 44
Reduction of non-recourse debt of joint ventures (113 ) (71 ) (80 )
Partnership units of joint ventures issued 88 - -
Common shares issued - 18 50
Redemption of junior subordinated debentures - (218 ) -
Net cash used in financing activities (156 ) (629 ) (1,064 )
Effect of Foreign Exchange Rate Changes on Cash and
Short-Term
Investments (87 ) (52 ) (3 )
(Decrease)/Increase in Cash and Short-Term Investments (150 ) 125 (87 )
Cash and Short-Term Investments
Beginning of year 337 212 299
Cash and Short-Term Investments
End of year 187 337 212
The accompanying notes to the consolidated financial statements are an integral
part of these statements.
F-5
TRANSCANADA PIPELINES LIMITED
CONSOLIDATED BALANCE SHEET
December 31 (millions of dollars) 2004 2003
ASSETS
Current Assets
Cash and short-term investments 187 337
Accounts receivable 627 603
Inventories 174 165
Other 120 88
1,108 1,193
Long-Term Investments (Note 7) 840 733
Plant, Property and Equipment (Notes 4, 9 and 10) 18,704 17,415
Other Assets (Note 5) 1,477 1,357
22,129 20,698
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Notes payable (Note 17) 546 367
Accounts payable 1,215 1,131
Accrued interest 214 208
Current portion of long-term debt (Note 9) 766 550
Current portion of non-recourse debt of joint ventures (Note 10) 83 19
2,824 2,275
Deferred Amounts (Note 11) 666 561
Long-Term Debt (Note 9) 9,713 9,465
Future Income Taxes (Note 16) 509 427
Non-Recourse Debt of Joint Ventures (Note 10) 779 761
Preferred Securities (Note 12) 19 22
14,510 13,511
Non-Controlling Interests 76 82
Shareholders' Equity
Preferred securities (Note 12) 670 672
Preferred shares (Note 13) 389 389
Common shares (Note 14) 4,632 4,632
Contributed surplus 270 267
Retained earnings 1,653 1,185
Foreign exchange adjustment (Note 15) (71 ) (40 )
7,543 7,105
Commitments, Contingencies and Guarantees (Note 21)
22,129 20,698
The accompanying notes to the consolidated financial statements are an integral
part of these statements.
On behalf of the Board:
Harold N. Kvisle Harry G. Schaefer
Director Director
F-6
TRANSCANADA PIPELINES LIMITED
CONSOLIDATED RETAINED EARNINGS
Year ended December 31 (millions of dollars) 2004 2003 2002
Balance at beginning of year 1,185 854 586
Net income 1,083 909 805
Preferred securities charges (31 ) (36 ) (36 )
Preferred share dividends (22 ) (22 ) (22 )
Common share dividends (562 ) (520 ) (479 )
1,653 1,185 854
The accompanying notes to the consolidated financial statements are an integral
part of these statements.
F-7
TRANSCANADA PIPELINES LIMITED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
TransCanada PipeLines Limited (the Company or TCPL) is a leading North American
energy company. TCPL operates in two business segments, Gas Transmission and
Power, each of which offers different products and services.
Gas Transmission
The Gas Transmission segment owns and operates the following natural gas
pipelines:
*
a natural gas transmission system extending from the Alberta border east
into Quebec (the Canadian Mainline);
*
a natural gas transmission system in Alberta (the Alberta System);
*
a natural gas transmission system extending from the British Columbia/
Idaho border to the Oregon/California border, traversing Idaho,
Washington and Oregon (the Gas Transmission Northwest System);
*
a natural gas transmission system extending from central Alberta to the
B.C., Saskatchewan and the United States borders (the Foothills System);
*
a natural gas transmission system extending from the Alberta border west
into southeastern B.C. (the BC System);
*
a natural gas transmission system extending from a point near Ehrenberg,
Arizona to the Baja California, Mexico/California border (the North Baja
System); and
*
natural gas transmission systems in Alberta which supply natural gas to
the oil sands region of northern Alberta and to a petrochemical complex
at Joffre, Alberta (Ventures LP).
Gas Transmission also holds the Company's investments in other natural gas
pipelines and natural gas storage facilities located primarily in Canada and the
U.S. In addition, Gas Transmission investigates and develops new natural gas
transmission, natural gas storage and liquefied natural gas regasification
facilities in Canada and the U.S.
Power
The Power segment builds, owns and operates electrical power generation plants,
and markets electricity. Power also holds the Company's investments in other
electrical power generation plants. This business operates in Canada and the
U.S.
NOTE 1 ACCOUNTING POLICIES
The consolidated financial statements of the Company have been prepared by
Management in accordance with Canadian generally accepted accounting principles
(GAAP). These accounting principles are different in some respects from U.S.
GAAP and the significant differences are described in Note 23. Amounts are
stated in Canadian dollars unless otherwise indicated. Certain comparative
figures have been reclassified to conform with the current year's presentation.
Since a determination of many assets, liabilities, revenues and expenses is
dependent upon future events, the preparation of these consolidated financial
statements requires the use of estimates and assumptions which have been made
using careful judgment. In the opinion of Management, these consolidated
financial statements have been properly prepared within reasonable limits of
materiality and within the framework of the significant accounting policies
summarized below.
Basis of Presentation
Pursuant to a plan of arrangement, effective May 15, 2003, common shares of TCPL
were exchanged on a one-to-one basis for common shares of TransCanada
Corporation (TransCanada). As a result, TCPL became a wholly-owned subsidiary of
TransCanada. The consolidated financial statements include the accounts of TCPL,
the consolidated accounts of all subsidiaries and TCPL's proportionate share of
the accounts of the Company's joint venture investments.
F-8
On November 1, 2004, the Company acquired a 100 per cent interest in the Gas
Transmission Northwest System and the North Baja System (collectively GTN) and,
as a result, GTN was consolidated subsequent to that date. In December 2003,
TCPL increased its ownership interest in Portland Natural Gas Transmission
System Partnership (Portland) to 61.7 per cent from 43.4 per cent. Subsequent to
the acquisition, Portland was consolidated in the Company's financial statements
with 38.3 per cent reflected in non-controlling interests. In August 2003, the
Company acquired the remaining interests in Foothills Pipe Lines Ltd. and its
subsidiaries (Foothills) previously not held by TCPL, and Foothills was
consolidated subsequent to that date.
TCPL uses the equity method of accounting for investments over which the Company
is able to exercise significant influence.
Regulation
The Canadian Mainline, the BC System, the Foothills System, and Trans Quebec &
Maritimes Pipeline Inc. (Trans Quebec & Maritimes) are subject to the authority
of the National Energy Board (NEB) and the Alberta System is regulated by the
Alberta Energy and Utilities Board (EUB). These Canadian natural gas
transmission operations are regulated with respect to the determination of
revenues, tolls, construction and operations. The NEB approved interim tolls for
2004 for the Canadian Mainline. The tolls will remain interim pending a decision
on Phase II of the 2004 Tolls and Tariff Application, which will address capital
structure, for the Canadian Mainline. Any adjustments to the interim tolls will
be recorded in accordance with the NEB decision. The Gas Transmission Northwest
System, the North Baja System and the other natural gas pipelines in the U.S.
are subject to the authority of the Federal Energy Regulatory Commission (FERC).
In order to appropriately reflect the economic impact of the regulators'
decisions regarding the Company's revenues and tolls, and to thereby achieve a
proper matching of revenues and expenses, the timing of recognition of certain
revenues and expenses in these regulated businesses may differ from that
otherwise expected under GAAP.
Cash and Short-Term Investments
The Company's short-term investments with original maturities of three months or
less are considered to be cash equivalents and are recorded at cost, which
approximates market value.
Inventories
Inventories are carried at the lower of average cost or net realizable value and
primarily consist of materials and supplies including spare parts and storage
gas.
Plant, Property and Equipment
Gas Transmission
Plant, property and equipment of natural gas transmission operations are carried
at cost. Depreciation is calculated on a straight-line basis. Pipeline and
compression equipment are depreciated at annual rates ranging from two to six
per cent and metering and other plant are depreciated at various rates. An
allowance for funds used during construction, using the rate of return on rate
base approved by the regulators, is capitalized and included in the cost of gas
transmission plant.
Power
Plant, property and equipment in the Power business are recorded at cost and
depreciated on a straight-line basis over estimated service lives at average
annual rates generally ranging from two to four per cent. The cost of major
overhauls of equipment is capitalized and depreciated over the estimated service
lives. Interest is capitalized on capital projects.
F-9
Corporate
Corporate plant, property and equipment are recorded at cost and depreciated on
a straight-line basis over estimated useful lives at average annual rates
ranging from three to 20 per cent.
Power Purchase Arrangements
Power purchase arrangements (PPAs) are long-term contracts to purchase or sell
power on a predetermined basis. The initial payments for PPAs acquired by TCPL
are deferred and amortized over the terms of the contracts, from the dates of
acquisition, which range from eight to 23 years. Certain PPAs under which TCPL
sells power are accounted for as operating leases and, accordingly, the related
plant, property and equipment are accounted for as assets under operating
leases.
Income Taxes
As prescribed by the regulators, the taxes payable method of accounting for
income taxes is used for tollmaking purposes for Canadian natural gas
transmission operations. Under the taxes payable method, it is not necessary to
provide for future income taxes. As permitted by Canadian GAAP, this method is
also used for accounting purposes, since there is reasonable expectation that
future taxes payable will be included in future costs of service and recorded in
revenues at that time. The liability method of accounting for income taxes is
used for the remainder of the Company's operations. Under this method, future
tax assets and liabilities are recognized for the future tax consequences
attributable to differences between the financial statement carrying amounts of
existing assets and liabilities and their respective tax bases. Future income
tax assets and liabilities are measured using enacted or substantively enacted
tax rates expected to apply to taxable income in the years in which temporary
differences are expected to be recovered or settled. Changes to these balances
are recognized in income in the period in which they occur.
Canadian income taxes are not provided on the unremitted earnings of foreign
investments as the Company does not intend to repatriate these earnings in the
foreseeable future.
Foreign Currency Translation
Most of the Company's foreign operations are self-sustaining and are translated
into Canadian dollars using the current rate method. Under this method, assets
and liabilities are translated at period end exchange rates and items included
in the statements of consolidated income, consolidated retained earnings and
consolidated cash flows are translated at the exchange rates in effect at the
time of the transaction. Translation adjustments are reflected in the foreign
exchange adjustment in Shareholders' Equity.
Certain foreign operations included in TCPL's investment in TransCanada Power,
L.P. (Power LP) are integrated and are translated into Canadian dollars using
the temporal method. Under this method, monetary assets and liabilities are
translated at period end exchange rates, non-monetary assets and liabilities are
translated at historical exchange rates, revenues and expenses are translated at
the exchange rate in effect at the time of the transaction and depreciation of
assets translated at historical rates is translated at the same rate as the
asset to which it relates. Gains and losses on translation are reflected in
income when incurred.
Exchange gains or losses on the principal amounts of foreign currency debt and
preferred securities related to the Alberta System and the Canadian Mainline are
deferred until they are recovered in tolls.
Derivative Financial Instruments
The Company utilizes derivative and other financial instruments to manage its
exposure to changes in foreign currency exchange rates, interest rates and
energy commodity prices. Gains or losses relating to derivatives that are hedges
are
F-10
deferred and recognized in the same period and in the same financial statement
category as the corresponding hedged transactions. The recognition of gains and
losses on derivatives used as hedges for Canadian Mainline, Alberta System, GTN
and the Foothills System exposures is determined through the regulatory process.
A derivative must be designated and effective to be accounted for as a hedge.
For cash flow hedges, effectiveness is achieved if the changes in the cash flows
of the derivative substantially offset the changes in the cash flows of the
hedged position and the timing of the cash flows is similar. Effectiveness for
fair value hedges is achieved if changes in the fair value of the derivative
substantially offset changes in the fair value attributable to the hedged item.
In the event that a derivative does not meet the designation or effectiveness
criterion, the derivative is accounted for at fair value and realized and
unrealized gains and losses on the derivative are recognized in income. If a
derivative that qualifies as a hedge is settled early, the gain or loss at
settlement is deferred and recognized when the corresponding hedged transaction
is recognized. Premiums paid or received with respect to derivatives that are
hedges are deferred and amortized to income over the term of the hedge.
Employee Benefit and Other Plans
The Company sponsors defined benefit pension plans (DB Plans). The cost of
defined benefit pensions and other post-employment benefits earned by employees
is actuarially determined using the projected benefit method pro-rated on
service and Management's best estimate of expected plan investment performance,
salary escalation, retirement ages of employees and expected health care costs.
Pension plan assets are measured at fair value. The expected return on pension
plan assets is determined using market-related values based on a five-year
moving average value for all plan assets. Adjustments arising from plan
amendments are amortized on a straight-line basis over the average remaining
service period of employees active at the date of amendment. The excess of the
net actuarial gain or loss over 10 per cent of the greater of the benefit
obligation and the fair value of plan assets is amortized over the average
remaining service period of the active employees. When the restructuring of a
benefit plan gives rise to both a curtailment and a settlement, the curtailment
is accounted for prior to the settlement. The Company previously sponsored two
additional plans, a defined contribution plan and a combination of the defined
benefit and defined contribution plans, which were effectively terminated at
December 31, 2002.
NOTE 2 ACCOUNTING CHANGES
Asset Retirement Obligations
Effective January 1, 2004, the Company adopted the new standard of the Canadian
Institute of Chartered Accountants (CICA) Handbook Section "Asset Retirement
Obligations", which addresses financial accounting and reporting for obligations
associated with asset retirement costs. This section requires that the fair
value of a liability for an asset retirement obligation be recognized in the
period in which it is incurred if a reasonable estimate of fair value can be
made. The fair value is added to the carrying amount of the associated asset.
The liability is accreted at the end of each period through charges to operating
expenses. This accounting change was applied retroactively with restatement of
prior periods.
The plant, property and equipment of the regulated natural gas transmission
operations consists primarily of underground pipelines and above ground
compression equipment and other facilities. No amount has been recorded for
asset retirement obligations relating to these assets as it is not possible to
make a reasonable estimate of the fair value of the liability due to the
indeterminate timing and scope of the asset retirements. Management believes it
is reasonable to assume that all retirement costs associated with the regulated
pipelines will be recovered through tolls in future periods. For Gas
Transmission, excluding regulated natural gas transmission operations, the
impact of this accounting change resulted in an increase of $2 million in plant,
property and equipment and in the estimated fair value of the liability as at
January 1, 2003 and December 31, 2003.
F-11
The plant, property and equipment in the Power business consists primarily of
power plants in Canada and the U.S. The impact of this accounting change
resulted in an increase of $6 million and $7 million in plant, property and
equipment and in the estimated fair value of the liability as at January 1, 2003
and December 31, 2003, respectively. The asset retirement cost, net of
accumulated depreciation that would have been recorded if the cost had been
recorded in the period in which it arose, is recorded as an additional cost of
the assets as at January 1, 2003.
The impact of this change on TCPL's net income in prior years was nil. The
impact of this accounting change on the Company's financial statements as at and
for the year ended December 31, 2004 is disclosed in Note 18.
Hedging Relationships
Effective January 1, 2004, the Company adopted the provisions of the CICA's new
Accounting Guideline "Hedging Relationships" that specifies the circumstances in
which hedge accounting is appropriate, including the identification,
documentation, designation and effectiveness of hedges, and the discontinuance
of hedge accounting. The adoption of the new guideline, which TCPL applied
prospectively, had no significant impact on net income for the year ended
December 31, 2004.
Generally Accepted Accounting Principles
Effective January 1, 2004, the Company adopted the new standard of the CICA
Handbook Section "Generally Accepted Accounting Principles" that defines primary
sources of GAAP and the other sources that need to be considered in the
application of GAAP. The new standard eliminates the ability to rely on industry
practice to support a particular accounting policy and provides an exemption for
rate-regulated operations.
This accounting change was applied prospectively and there was no impact on net
income in the year ended December 31, 2004. In prior years, in accordance with
industry practice, certain assets and liabilities related to the Company's
regulated activities, and offsetting deferral accounts, were not recognized on
the balance sheet. The impact of the change on the consolidated balance sheet as
at January 1, 2004 is as follows.
(millions of dollars) Increase/
(Decrease)
Other assets 153
Deferred amounts 80
Long-term debt 76
Preferred securities (3 )
Total liabilities 153
F-12
NOTE 3 SEGMENTED INFORMATION
NET INCOME/(LOSS)(1)
Year ended December 31, 2004 (millions of Gas Power Corporate Total
dollars) Transmission
Revenues 3,917 1,190 - 5,107
Cost of sales(2) - (539 ) - (539 )
Other costs and expenses (1,225 ) (407 ) (3 ) (1,635 )
Depreciation (873 ) (72 ) - (945 )
Operating income/(loss) 1,819 172 (3 ) 1,988
Financial and preferred equity charges (785 ) (9 ) (81 ) (875 )
and non-controlling interests
Financial charges of joint ventures (56 ) (4 ) - (60 )
Equity income 41 130 - 171
Interest income and other 14 14 37 65
Gains related to Power LP - 197 - 197
Income taxes (447 ) (104 ) 43 (508 )
Continuing operations 586 396 (4 ) 978
Discontinued operations 52
Net Income Applicable to Common Shares 1,030
Year ended December 31, 2003 (millions of
dollars)
Revenues 3,956 1,401 - 5,357
Cost of sales(2) - (692 ) - (692 )
Other costs and expenses (1,270 ) (405 ) (7 ) (1,682 )
Depreciation (831 ) (82 ) (1 ) (914 )
Operating income/(loss) 1,855 222 (8 ) 2,069
Financial and preferred equity charges (781 ) (11 ) (89 ) (881 )
and non-controlling interests
Financial charges of joint ventures (76 ) (1 ) - (77 )
Equity income 66 99 - 165
Interest income and other 17 14 29 60
Income taxes (459 ) (103 ) 27 (535 )
Continuing operations 622 220 (41 ) 801
Discontinued operations 50
Net Income Applicable to Common Shares 851
F-13
Year ended December 31, 2002 (millions of Gas Power Corporate Total
dollars) Transmission
Revenues 3,921 1,293 - 5,214
Cost of sales(2) - (627 ) - (627 )
Other costs and expenses (1,166 ) (371 ) (9 ) (1,546 )
Depreciation (783 ) (65 ) - (848 )
Operating income/(loss) 1,972 230 (9 ) 2,193
Financial and preferred equity charges (821 ) (13 ) (91 ) (925 )
and non-controlling interests
Financial charges of joint ventures (90 ) - - (90 )
Equity income 33 - - 33
Interest income and other 17 13 23 53
Income taxes (458 ) (84 ) 25 (517 )
Continuing operations 653 146 (52 ) 747
Discontinued operations -
Net Income Applicable to Common Shares 747
(1)
In determining the net income of each segment, certain expenses such as
indirect financial charges and related income taxes are not allocated to
business segments.
(2)
Cost of sales is comprised of commodity purchases for resale.
TOTAL ASSETS
December 31 (millions of dollars) 2004 2003
Gas Transmission 18,428 17,064
Power 2,802 2,753
Corporate 892 870
Continuing operations 22,122 20,687
Discontinued operations 7 11
22,129 20,698
GEOGRAPHIC INFORMATION
Year ended December 31 (millions of dollars) 2004 2003 2002(4)
Revenues(3)
Canada - domestic 3,147 3,257 2,731
Canada - export 1,261 1,293 1,641
United States 699 807 842
5,107 5,357 5,214
(3)
Revenues are attributed to countries based on country of origin of product
or service.
(4)
Canada - domestic revenues were reduced in 2002 as a result of
transportation service credits of $662 million. These services were
discontinued in 2003.
F-14
PLANT, PROPERTY AND EQUIPMENT
December 31 (millions of dollars) 2004 2003
Canada 14,757 15,156
United States 3,947 2,259
18,704 17,415
CAPITAL EXPENDITURES
Year ended December 31 (millions of dollars) 2004 2003 2002
Gas Transmission 187 256 382
Power 285 132 193
Corporate and Other 4 3 24
476 391 599
F-15
NOTE 4 PLANT, PROPERTY AND EQUIPMENT
December 31 2004 2003
(millions of dollars)
Cost Accumulated Net Book Cost Accumulated Net Book
Depreciation Value Depreciation Value
Gas Transmission
Canadian Mainline
Pipeline 8,695 3,421 5,274 8,683 3,176 5,507
Compression 3,322 947 2,375 3,318 832 2,486
Metering and other 366 125 241 404 132 272
12,383 4,493 7,890 12,405 4,140 8,265
Under construction 16 - 16 12 - 12
12,399 4,493 7,906 12,417 4,140 8,277
Alberta System
Pipeline 4,978 2,055 2,923 4,934 1,908 3,026
Compression 1,496 599 897 1,507 549 958
Metering and other 861 262 599 862 211 651
7,335 2,916 4,419 7,303 2,668 4,635
Under construction 20 - 20 13 - 13
7,355 2,916 4,439 7,316 2,668 4,648
GTN(1)
Pipeline 1,131 9 1,122
Compression 726 2 724
Metering and other 187 1 186
2,044 12 2,032
Under construction 17 - 17
2,061 12 2,049
Foothills System
Pipeline 815 346 469 834 317 517
Compression 373 114 259 378 99 279
Metering and other 78 35 43 60 35 25
1,266 495 771 1,272 451 821
Joint Ventures and 3,213 1,053 2,160 3,361 1,052 2,309
other
26,294 8,969 17,325 24,366 8,311 16,055
Power(2)
Power generation 1,397 375 1,022 1,439 381 1,058
facilities
Other 77 45 32 84 41 43
1,474 420 1,054 1,523 422 1,101
Under construction 288 - 288 209 - 209
1,762 420 1,342 1,732 422 1,310
Corporate 124 87 37 122 72 50
28,180 9,476 18,704 26,220 8,805 17,415
(1)
TCPL acquired GTN on November 1, 2004.
(2)
Certain Power generation facilities are accounted for as assets under
operating leases. At December 31, 2004, the net book value of these
facilities was $70 million. Revenues of $7 million were attributed to the
PPAs of these facilities in 2004.
F-16
NOTE 5 OTHER ASSETS
December 31 (millions of dollars) 2004 2003
Derivative contracts 253 118
PPAs - Canada(1) 274 278
PPAs - U.S.(1) 98 248
Pension and other benefit plans 209 201
Regulatory deferrals 199 212
Loans and advances(2) 135 111
Goodwill 58 -
Other 251 189
1,477 1,357
(1)
The following amounts related to the PPAs are included in the consolidated
financial statements.
December 31 2004 2003
(millions of
dollars)
Cost Accumulated Net Cost Accumulated Net
Amortization Book Amortization Book
Value Value
PPAs - Canada 345 71 274 329 51 278
PPAs - U.S. 102 4 98 276 28 248
The aggregate amortization expense with respect to the PPAs was $24 million for
the year ended December 31, 2004 (2003 - $37 million; 2002 - $28 million).
The amortization expense with respect to the Company's PPAs approximate:
2005 - $26 million; 2006 - $26 million; 2007 - $26 million; 2008 - $26
million; and 2009 - $26 million. In April 2004, the Company disposed of all
its PPAs - U.S. to Power LP and, as a result of its joint venture investment
in Power LP, recorded US$74 million of PPAs - U.S. In 2004, TransCanada also
recorded $16 million of PPAs - Canada.
(2)
Includes a $75 million unsecured note receivable from Bruce Power L.P.
(Bruce Power) bearing interest at 10.5 per cent per annum, due February 14,
2008.
NOTE 6 JOINT VENTURE INVESTMENTS
TCPL's Proportionate Share
Income Before Income Taxes Net Assets
Year ended December 31 December 31
(millions of dollars) Ownership 2004 2003 2002 2004 2003
Interest
Gas Transmission
Great Lakes 50.0% (1) 86 81 102 379 419
Iroquois 41.0% (1) 28 31 30 175 169
TC PipeLines, LP 33.4% 22 21 24 124 130
Trans Quebec & Maritimes 50.0% 13 14 13 75 77
CrossAlta 60.0% (1) 20 11 21 24 25
Foothills (2) - 19 29 - -
Other Various 6 7 7 27 22
Power
Power LP 30.6% (3) 32 25 26 289 234
ASTC Power Partnership 50.0% (4) - - - 93 99
207 209 252 1,186 1,175
(1)
Great Lakes Gas Transmission Limited Partnership (Great Lakes); Iroquois Gas
Transmission System, L.P. (Iroquois); CrossAlta Gas Storage & Services Ltd.
(CrossAlta).
(2)
In August 2003, the Company acquired the remaining interests in Foothills
previously not held by TCPL, and Foothills was consolidated subsequent to
that date.
F-17
(3)
In April 2004, the Company's interest in Power LP decreased to 30.6 per cent
from 35.6 per cent.
(4)
The Company has a 50.0 per cent ownership interest in ASTC Power
Partnership, which is located in Alberta and holds a PPA. The underlying
power volumes related to the 50.0 per cent ownership interest in the
Partnership are effectively transferred to TCPL.
Consolidated retained earnings at December 31, 2004 include undistributed
earnings from these joint ventures of $509 million (2003 - $509 million).
Summarized Financial Information of Joint Ventures
Year ended December 31 (millions of dollars) 2004 2003 2002
Income
Revenues 559 623 680
Other costs and expenses (238 ) (275 ) (251 )
Depreciation (88 ) (96 ) (119 )
Financial charges and other (26 ) (43 ) (58 )
Proportionate share of income before income taxes of joint 207 209 252
ventures
Year ended December 31 (millions of dollars) 2004 2003 2002
Cash Flows
Operations 269 272 323
Investing activities (179 ) (114 ) (124 )
Financing activities (76 ) (156 ) (210 )
Effect of foreign exchange rate changes on cash and (5 ) (10 ) (1 )
short-term investments
Proportionate share of increase/(decrease) in cash and 9 (8 ) (12 )
short-term investments of joint ventures
December 31 (millions of dollars) 2004 2003
Balance Sheet
Cash and short-term investments 64 55
Other current assets 133 106
Long-term investments 105 118
Plant, property and equipment 1,644 1,693
Other assets and deferred amounts (net) 221 109
Current liabilities (153 ) (94 )
Non-recourse debt (779 ) (761 )
Future income taxes (49 ) (51 )
Proportionate share of net assets of joint ventures 1,186 1,175
F-18
NOTE 7 LONG-TERM INVESTMENTS
TCPL's Share
Distributions from Income from Equity Equity
Equity Investments Investments Investments
Year ended December 31 Year ended December 31 December 31
(millions of Ownership 2004 2003 2002 2004 2003 2002 2004 2003
dollars) Interest
Power
Bruce Power 31.6% - - - 130 99 - 642 513
Gas Transmission
Northern Border 10.0% (1) 27 22 26 23 22 25 91 103
TransGas de 46.5% 8 8 - 11 27 5 78 80
Occidente S.A.
Portland 61.7% (2) - 10 - - 14 2 - -
Other Various 13 6 1 7 3 1 29 37
48 46 27 171 165 33 840 733
(1)
The Northern Border equity investment effective ownership interest of 10.0
per cent is the result of the Company holding a 33.4 per cent interest in TC
PipeLines, LP, which holds a 30.0 per cent interest in Northern Border
Pipeline Company (Northern Border).
(2)
In September 2003, the Company increased its ownership interest in Portland
to 43.4 per cent from 33.3 per cent. In December 2003, the Company increased
its ownership interest to 61.7 per cent and the investment was fully
consolidated subsequent to that date.
Consolidated retained earnings at December 31, 2004 include undistributed
earnings from these equity investments of $285 million (2003 - $166 million).
NOTE 8 ACQUISITIONS AND DISPOSITIONS
Acquisitions
GTN
On November 1, 2004, TCPL acquired GTN for approximately US$1,730 million,
including US$528 million of assumed debt and closing adjustments. The purchase
price was allocated on a preliminary basis as follows using an estimate of fair
values of the net assets at the date of acquisition.
Purchase Price Allocation
(millions of U.S. dollars)
Current assets 45
Plant, property and equipment 1,712
Other non-current assets 30
Goodwill 48
Current liabilities (54 )
Long-term debt (528 )
Other non-current liabilities (51 )
1,202
Goodwill, which is attributable to the North Baja System, will be re-evaluated
on an annual basis for impairment. Factors that contributed to goodwill include
opportunities for expansion, a strong competitive position, strong demand for
gas
F-19
in the western markets and access to an ample supply of relatively low-cost gas.
The goodwill recognized on this transaction is expected to be fully deductible
for tax purposes.
The acquisition was accounted for using the purchase method of accounting. The
financial results of GTN have been consolidated with those of TCPL subsequent to
the acquisition date and included in the Gas Transmission segment.
Bruce Power
On February 14, 2003, the Company acquired a 31.6 per cent interest in Bruce
Power for $409 million, including closing adjustments. As part of the
acquisition, the Company also funded a one-third share ($75 million) of a $225
million accelerated deferred rent payment made by Bruce Power to Ontario Power
Generation. The resulting note receivable from Bruce Power is recorded in other
assets.
The purchase price of the Company's 31.6 per cent interest in Bruce Power was
allocated as follows.
Purchase Price Allocation
(millions of dollars)
Net book value of assets acquired 281
Capital lease 301
Power sales agreements (131 )
Pension liability and other (42 )
409
The amount allocated to the investment in Bruce Power includes a purchase price
allocation of $301 million to the capital lease of the Bruce Power plant which
is being amortized on a straight-line basis over the lease term which extends to
2018, resulting in an annual amortization expense of $19 million. The amount
allocated to the power sales agreements 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.
Dispositions
Power LP
On April 30, 2004, TCPL sold the ManChief and Curtis Palmer power facilities to
Power LP for US$402.6 million, plus closing adjustments of US$12.8 million, and
recognized a gain of $25 million pre tax ($15 million after tax). Power LP
funded the purchase through an issue of 8.1 million subscription receipts and
third party debt. As part of the subscription receipts offering, TCPL purchased
540,000 subscription receipts for an aggregate purchase price of $20 million.
The subscription receipts were subsequently converted into partnership units.
The net impact of this issue reduced TCPL's ownership interest in Power LP to
30.6 per cent from 35.6 per cent.
At a special meeting held on April 29, 2004, Power LP's unitholders approved an
amendment to the terms of the Power LP Partnership Agreement to remove Power
LP's obligation to redeem all units not owned by TCPL at June 30, 2017. TCPL was
required to fund this redemption, thus the removal of Power LP's obligation
eliminates this requirement. The removal of the obligation and the reduction in
TCPL's ownership interest in Power LP resulted in a gain of $172 million. This
amount includes the recognition of unamortized gains of $132 million on previous
Power LP transactions.
F-20
NOTE 9 LONG-TERM DEBT
2003
2004
Weighted
Maturity Outstanding Weighted Outstanding Average
Dates December 31 Average December 31 Interest
(1) Interest (1) Rate(2)
Rate(2)
CANADIAN MAINLINE(3)
First Mortgage Pipe Line Bonds
Pounds Sterling (2004 and 2007 58 16.5% 58 16.5%
2003 - #25)
Debentures
Canadian dollars 2008 to 2020 1,354 10.9% 1,354 10.9%
U.S. dollars (2004 - 2012 to 2021 722 9.5% 1,034 9.2%
US$600; 2003 - US$800)
Medium-Term Notes
Canadian dollars 2005 to 2031 2,167 6.9% 2,312 6.9%
U.S. dollars (2004 and 2003 2010 144 6.1% 155 6.1%
- US$120)
Foreign exchange differential - (60 )
recoverable through the
tollmaking process(8)
4,445 4,853
ALBERTA SYSTEM(4)
Debentures and Notes
Canadian dollars 2007 to 2024 607 11.6% 627 11.6%
U.S. dollars (2004 - 2012 to 2023 451 8.2% 646 8.3%
US$375; 2003 - US$500)
Medium-Term Notes
Canadian dollars 2005 to 2030 767 7.4% 767 7.4%
U.S. dollars (2004 and 2003 2026 to 2029 280 7.7% 301 7.7%
- US$233)
Foreign exchange differential - (16 )
recoverable through the
tollmaking process(8)
2,105 2,325
GTN(5)
Unsecured Debentures and Notes 2005 to 2025 632 7.2% -
(2004 - US$525)
FOOTHILLS SYSTEM(3)
Senior Secured Notes - 80 4.3%
Senior Unsecured Notes 2009 to 2014 400 4.9% 300 4.7%
400 380
PORTLAND(6)
Senior Secured Notes
U.S. dollars (2004 - 2018 308 5.9% 350 5.9%
US$256; 2003 - US$271)
OTHER
Medium-Term Notes(3)
Canadian dollars 2005 to 2030 592 6.2% 592 6.2%
U.S. dollars (2004 - 2006 to 2025 627 6.9% 859 6.8%
US$521; 2003 - US$665)
Subordinated Debentures(3)
U.S. dollars (2004 and 2003 2006 68 9.1% 74 9.1%
- US$57)
Unsecured Loans, Debentures
and Notes(7)
U.S. dollars (2004 - 2005 to 2034 1,302 5.1% 582 4.9%
US$1,082; 2003 - US$446)
2,589 2,107
10,479 10,015
Less: Current Portion of 766 550
Long-Term Debt
9,713 9,465
(1)
Amounts outstanding are stated in millions of Canadian dollars; amounts
denominated in currencies other than Canadian dollars are stated in
millions.
(2)
Weighted average interest rates are stated as at the respective outstanding
dates. The effective weighted average interest rates resulting from swap
agreements are as follows: Foothills senior unsecured notes in 2003 - 5.8
per cent; Portland senior secured notes in
F-21
2003 - 6.2 per cent; Other U.S. dollar subordinated debentures - 9.0 per
cent (2003 - 9.0 per cent); and Other U.S. dollar unsecured loans,
debentures and notes - 5.2 per cent (2003 - 5.2 per cent).
(3)
Long-term debt of TCPL.
(4)
Long-term debt of NOVA Gas Transmission Ltd. excluding a $241 million note
held by TCPL (2003 - $258 million).
(5)
Long-term debt of Gas Transmission Northwest Corporation.
(6)
Long-term debt of Portland.
(7)
Long-term debt of TCPL, excluding $85 million held by OSP Finance Company
and $14 million held by TC Ocean State Corporation.
(8)
See Note 2, Accounting Changes - "Generally Accepted Accounting Principles".
Principal Repayments
Principal repayments on the long-term debt of the Company approximate: 2005 -
$766 million; 2006 - $387 million; 2007 - $615 million; 2008 - $545 million; and
2009 - $753 million.
Debt Shelf Programs
At December 31, 2004, $1.5 billion of medium-term note debentures could be
issued under a base shelf program in Canada and US$1 billion of debt securities
could be issued under a debt shelf program in the U.S. In January 2005, the
Company issued $300 million of 12-year medium-term notes bearing interest of 5.1
per cent under the Canadian base shelf program.
CANADIAN MAINLINE
First Mortgage Pipe Line Bonds
The Deed of Trust and Mortgage securing the Company's First Mortgage Pipe Line
Bonds limits the specific and floating charges to those assets comprising the
present and future Canadian Mainline and TCPL's present and future gas
transportation contracts.
ALBERTA SYSTEM
Debentures
Debentures amounting to $225 million have retraction provisions which entitle
the holders to require redemption of up to 8 per cent of the then outstanding
principal plus accrued and unpaid interest on specified repayment dates. No
redemptions have been made to December 31, 2004.
Medium-Term Notes
Medium-term notes amounting to $50 million have a provision entitling the
holders to extend the maturity of the medium-term notes from the initial
repayment date of 2007 to 2027. If extended, the interest rate would increase
from 6.1 per cent to 7.0 per cent and the medium-term notes would become
redeemable at the option of the Company.
GAS TRANSMISSION NORTHWEST CORPORATION
Senior Unsecured Notes
Senior unsecured notes amounting to US$250 million are redeemable by the Company
at any time on or after June 1, 2005.
F-22
OTHER
Medium-Term Notes
Medium-term notes amounting to $150 million have retraction provisions which
entitle the holders to require redemption of the principal plus accrued and
unpaid interest in 2005.
Financial Charges
Year ended December 31 (millions of dollars) 2004 2003 2002
Interest on long-term debt 805 801 850
Regulatory deferrals and amortizations (31 ) (14 ) (17 )
Short-term interest and other financial charges 38 34 34
812 821 867
The Company made interest payments of $816 million for the year ended December
31, 2004 (2003 - $846 million; 2002 - $866 million). The Company capitalized $11
million of interest for the year ended December 31, 2004 (2003 - $9 million;
2002 - nil).
NOTE 10 NON-RECOURSE DEBT OF JOINT VENTURES
2004 2003
Maturity Outstanding Weighted Outstanding Weighted
Dates December 31 Average December 31 Average
(1) Interest (1) Interest
Rate(2) Rate(2)
Great Lakes
Senior Unsecured Notes
(2004 - US$235; 2003 - 2011 to 2030 283 7.9% 310 7.9%
US$240)
Iroquois
Senior Unsecured Notes
(2004 and 2003 - US$151) 2010 to 2027 182 7.5% 196 7.5%
Bank Loan
(2004 - US$36; 2003 - 2008 43 2.5% 56 2.3%
US$43)
Trans Quebec & Maritimes
Bonds 2005 to 2010 143 7.3% 143 7.3%
Term Loan 2006 29 3.2% 34 3.5%
F-23
TransCanada Power, L.P.
Senior Unsecured Notes
(2004 - US$58) 2014 70 5.9% -
Credit Facility 2009 64 3.2% -
Term Loan 2010 2 11.3% -
Other 2005 to 2012 46 4.9% 41 5.4%
862 780
Less: Current Portion of Non- Recourse
Debt of Joint Ventures 83 19
779 761
(1)
Amounts outstanding represent TCPL's proportionate share and are stated in
millions of Canadian dollars; amounts denominated in U.S. dollars are stated
in millions.
(2)
Weighted average interest rates are stated as at the respective outstanding
dates. At December 31, 2004, the effective weighted average interest rates
resulting from swap agreements are as follows: Iroquois bank loan - 4.1 per
cent (2003 - 4.5 per cent) and Power, L.P. Credit Facility - 5.2 per cent.
The debt of joint ventures is non-recourse to TCPL. The security provided by
each joint venture is limited to the rights and assets of that joint venture and
does not extend to the rights and assets of TCPL, except to the extent of TCPL's
investment.
The Company's proportionate share of principal repayments resulting from
maturities and sinking fund obligations of the non-recourse joint venture debt
approximates: 2005 - $83 million; 2006 - $49 million; 2007 - $18 million; 2008 -
$18 million; and 2009 - $141 million.
The Company's proportionate share of the interest payments of joint ventures was
$55 million for the year ended December 31, 2004 (2003 - $67 million; 2002 - $88
million).
NOTE 11 DEFERRED AMOUNTS
December 31 (millions of dollars) 2004 2003
Derivative contracts 209 40
Regulatory deferrals 229 131
Other benefit plans 63 32
Deferred revenue 58 215
Asset retirement obligation 36 9
Other 71 134
666 561
F-24
NOTE 12 PREFERRED SECURITIES
The US$460 million 8.25 per cent preferred securities are redeemable by the
Company at par at any time. The Company may elect to defer interest payments on
the preferred securities and settle the deferred interest in either cash or
common shares.
Since the deferred interest may be settled through the issuance of common shares
at the option of the Company, the preferred securities are classified into their
respective debt and equity components. At December 31, 2004, the debt component
of the preferred securities is $19 million (US$16 million) (2003 - $22 million
(US$14 million)) and the equity component of the preferred securities is $670
million (US$444 million) (2003 - $672 million (US$446 million)).
Effective January 1, 2005, under new Canadian accounting standards, the equity
component of preferred securities will be classified as debt.
NOTE 13 PREFERRED SHARES
December 31 Number of Dividend Redemption 2004 2003
Shares Rate Per Price Per (millions (millions
(thousands) Share Share of of
dollars) dollars)
Cumulative First Preferred Shares
Series U 4,000 $2.80 $50.00 195 195
Series Y 4,000 $2.80 $50.00 194 194
389 389
The authorized number of preferred shares issuable in series is unlimited. All
of the cumulative first preferred shares are without par value.
On or after October 15, 2013, for the Series U shares, and on or after March 5,
2014, for the Series Y shares, the Company may redeem the shares at $50 per
share.
NOTE 14 COMMON SHARES
Number of Amount
Shares (millions
(thousands) of
dollars)
Outstanding at January 1, 2002 476,631 4,564
Exercise of options 2,871 50
Outstanding at December 31, 2002 479,502 4,614
Exercise of options 1,166 18
Outstanding at December 31, 2003 and 2004 480,668 4,632
Common Shares Issued and Outstanding
The Company is authorized to issue an unlimited number of common shares of no
par value.
F-25
Restriction on Dividends
Certain terms of the Company's preferred shares, preferred securities, and debt
instruments could restrict the Company's ability to declare dividends on
preferred and common shares. At December 31, 2004, under the most restrictive
provisions, approximately $1.4 billion was available for the payment of
dividends on common shares.
NOTE 15 RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
The Company issues short-term and long-term debt, including amounts in foreign
currencies, purchases and sells energy commodities and invests in foreign
operations. These activities result in exposures to interest rates, energy
commodity prices and foreign currency exchange rates. The Company uses
derivatives to manage the risk that results from these activities.
Carrying Values of Derivatives
The carrying amounts of derivatives, which hedge the price risk of foreign
currency denominated assets and liabilities of self-sustaining foreign
operations, are recorded on the balance sheet at their fair value. Gains and
losses on these derivatives, realized and unrealized, are included in the
foreign exchange adjustment account in Shareholders' Equity as an offset to the
corresponding gains and losses on the translation of the assets and liabilities
of the foreign subsidiaries. As of January 1, 2004, carrying amounts for
interest rate swaps are recorded on the balance sheet at their fair value.
Foreign currency transactions hedged by foreign exchange contracts are recorded
at the contract rate. Power, natural gas and heat rate derivatives are recorded
on the balance sheet at their fair value. The carrying amounts shown in the
tables that follow are recorded in the consolidated balance sheet.
Fair Values of Financial Instruments
Cash and short-term investments and notes payable are valued at their carrying
amounts due to the short period to maturity. The fair values of long-term debt,
non-recourse long-term debt of joint ventures and junior subordinated debentures
are determined using market prices for the same or similar issues.
The fair values of foreign exchange and interest rate derivatives have been
estimated using year-end market rates. The fair values of power, natural gas and
heat rate derivatives have been calculated using estimated forward prices for
the relevant period.
Credit Risk
Credit risk results from the possibility that a counterparty to a derivative in
which the Company has an unrealized gain fails to perform according to the terms
of the contract. Credit exposure is minimized through the use of established
credit management techniques, including formal assessment processes, contractual
and collateral requirements, master netting arrangements and credit exposure
limits. At December 31, 2004, for foreign currency and interest rate
derivatives, total credit risk and the largest credit exposure to a single
counterparty were $127 million and $40 million, respectively. At December 31,
2004, for power, natural gas and heat rate derivatives, total credit risk and
the largest credit exposure to a single counterparty were $19 million and $7
million, respectively.
Notional or Notional Principal Amounts
Notional principal amounts are not recorded in the financial statements because
these amounts are not exchanged by the Company and its counterparties and are
not a measure of the Company's exposure. Notional amounts are used only as the
basis for calculating payments for certain derivatives.
F-26
Foreign Investments
At December 31, 2004 and 2003, the Company had foreign currency denominated
assets and liabilities which created an exposure to changes in exchange rates.
The Company uses foreign currency derivatives to hedge this net exposure on an
after-tax basis. The foreign currency derivatives have a floating interest rate
exposure which the Company partially hedges by entering into interest rate swaps
and forward rate agreements. The fair values shown in the table below for those
derivatives that have been designated as and are effective as hedges for foreign
exchange risk are offset by translation gains or losses on the net assets and
are recorded in the foreign exchange adjustment account in Shareholders' Equity.
Net Investment in Foreign Assets
Asset/(Liability)
2004 2003
December 31 (millions of dollars) Accounting Fair Notional Fair Notional
Treatment Value or Value or
Notional Notional
Principal Principal
Amount Amount
(U.S.) (U.S.)
U.S. dollar cross-currency swaps
(maturing 2006 to 2009) Hedge 95 400 65 250
U.S. dollar forward foreign exchange
contracts
(maturing 2005) Hedge (1 ) 305 3 125
U.S. dollar options
(maturing 2005) Non-hedge 1 100 - -
In accordance with the Company's accounting policy, each of the above
derivatives is recorded on the consolidated balance sheet at its fair value in
2004. For derivatives that have been designated as and are effective as hedges
of the net investment in foreign operations, the offsetting amounts are included
in the foreign exchange adjustment account.
In addition, at December 31, 2004, the Company had interest rate swaps
associated with the cross-currency swaps with notional principal amounts of $375
million (2003 - $311 million) and US$250 million (2003 - US$200 million). The
carrying amount and fair value of these interest rate swaps was $4 million (2003
- $3 million) and $4 million (2003 - $1 million), respectively.
Reconciliation of Foreign Exchange Adjustment Gains/(Losses)
December 31 (millions of dollars) 2004 2003
Balance at beginning of year (40 ) 14
Translation losses on foreign currency denominated net (64 ) (136 )
assets
Foreign exchange gains on derivatives, net of income taxes 33 82
(71 ) (40 )
Foreign Exchange Gains/(Losses)
Foreign exchange gains/(losses) included in Other Expenses/(Income) for the year
ended December 31, 2004 are $4 million (2003 - nil; 2002 - $(11) million).
F-27
Foreign Exchange and Interest Rate Management Activity
The Company manages certain of the foreign exchange risk of U.S. dollar debt,
U.S. dollar expenses and the interest rate exposures of the Canadian Mainline,
the Alberta System, GTN and the Foothills System through the use of foreign
currency and interest rate derivatives. Certain of the realized gains and losses
on these derivatives are shared with shippers on predetermined terms. The
details of the foreign exchange and interest rate derivatives are shown in the
table below.
Asset/(Liability)
2004 2003
December 31 (millions of dollars) Accounting Fair Notional Fair Notional
Treatment Value or Value or
Notional Notional
Principal Principal
Amount Amount
Foreign Exchange
Cross-currency swaps
(maturing 2010 to 2012) Hedge (39 ) U.S. 157 (26 ) U.S. 282
Interest Rate
Interest rate swaps
Canadian dollars
(maturing 2005 to 2008) Hedge 7 145 (1 ) 340
(maturing 2006 to 2009) Non-hedge 9 374 10 624
16 9
U.S. dollars
(maturing 2010 to 2015) Hedge (2 ) U.S. 275 11 U.S. 50
(maturing 2007 to 2009) Non-hedge 7 U.S. 100 (3 ) U.S. 50
5 8
In accordance with the Company's accounting policy, each of the above
derivatives is recorded on the consolidated balance sheet at its fair value in
2004. At December 31, 2004, the Company also had interest rate swaps associated
with the cross-currency swaps with notional principal amounts of $227 million
(2003 - $390 million) and US$157 million (2003 - US$282 million). The carrying
amount and fair value of these interest rate swaps was $(4) million (2003 - nil)
and $(4) million (2003 - $6 million), respectively.
F-28
The Company manages the foreign exchange and interest rate exposures of its
other businesses through the use of foreign currency and interest rate
derivatives. The details of these foreign currency and interest rate derivatives
are shown in the table below.
Asset/(Liability) 2004 2003
December 31 (millions of dollars) Accounting Fair Notional Fair Notional
Treatment Value or Value or
Notional Notional
Principal Principal
Amount Amount
Foreign Exchange
Options (maturing 2005) Non-hedge 2 U.S. 225 1 U.S. 25
Forward foreign exchange contracts
(maturing 2005) Non-hedge 1 U.S. 29 1 U.S. 19
Cross-currency swaps
(maturing 2013) Hedge (16 ) U.S. 100 (7 ) U.S. 100
Interest Rate
Options (maturing 2005) Non-hedge - U.S. 50 (2 ) U.S. 50
Interest rate swaps
Canadian dollar
(maturing 2007 to 2009) Hedge 4 100 2 50
(maturing 2005 to 2011) Non-hedge 1 110 2 100
5 4
U.S. dollar
(maturing 2006 to 2013) Hedge 5 U.S. 100 40 U.S. 250
(maturing 2006 to 2010) Non-hedge 22 U.S. 250 (3 ) U.S. 200
27 37
In accordance with the Company's accounting policy, each of the above
derivatives is recorded on the consolidated balance sheet at its fair value in
2004. At December 31, 2004, the Company also had interest rate swaps associated
with the cross-currency swaps with notional principal amounts of $136 million
(2003 - $136 million) and US$100 million (2003 - US$100 million). The carrying
amount and fair value of these interest rate swaps was $(10) million (2003 -
nil) and $(10) million (2003 - $(7) million), respectively.
Certain of the Company's joint ventures use interest rate derivatives to manage
interest rate exposures. The Company's proportionate share of the fair value of
the outstanding derivatives at December 31, 2004 was $1 million (2003 - $(1)
million).
Energy Price Risk Management
The Company executes power, natural gas and heat rate derivatives for overall
management of its asset portfolio. Heat rate contracts are contracts for the
sale or purchase of power that are priced based on a natural gas index. The fair
values and notional volumes of the swap, option, forward and heat rate contracts
are shown in the tables below. In accordance with the Company's accounting
policy, each of the derivatives in the table below is recorded on the balance
sheet at its fair value in 2004 and 2003.
F-29
Power
Asset/(Liability)
2004 2003
December 31 (millions of dollars) Accounting Fair Fair
Treatment Value Value
Power - swaps
(maturing 2005 to 2011) Hedge 7 (5 )
(maturing 2005) Non-hedge (2 ) -
Gas - swaps, forwards and options
(maturing 2005 to 2016) Hedge (39 ) (34 )
(maturing 2005) Non-hedge (2 ) (1 )
Heat rate contracts
(maturing 2005 to 2006) Hedge (1 ) (1 )
Notional Volumes
Power (GWh)(1) Gas (Bcf)(1)
December 31, 2004 Accounting Purchases Sales Purchases Sales
Treatment
Power - swaps
(maturing 2005 to 2011) Hedge 3,314 7,029 - -
(maturing 2005) Non-hedge 438 - - -
Gas - swaps, forwards and options
(maturing 2005 to 2016) Hedge - - 80 84
(maturing 2005) Non-hedge - - 5 8
Heat rate contracts
(maturing 2005 to 2006) Hedge - 229 2 -
December 31, 2003
Power - swaps
Hedge 1,331 4,787 - -
Non-hedge 59 77 - -
Gas - swaps, forwards and options
Hedge - - 79 81
Non-hedge - - - 7
Heat rate contracts
Hedge - 735 1 -
(1)
Gigawatt hours (GWh); billion cubic feet (Bcf).
U.S. Dollar Transaction Hedges
To reduce risk and protect margins when purchase and sale contracts are
denominated in different currencies, the Company may enter into forward foreign
exchange contracts and foreign exchange options which establish the foreign
exchange rate for the cash flows from the related purchase and sale
transactions.
F-30
Other Fair Values
2004 2003
December 31 (millions of dollars) Carrying Fair Carrying Fair
Amount Value Amount Value
Long-Term Debt
Canadian Mainline 4,445 5,473 4,853 5,922
Alberta System 2,105 2,668 2,325 2,893
GTN(1) 632 627
Foothills System 400 413 380 382
Portland 308 328 350 348
Other 2,589 2,687 2,107 2,214
Non-Recourse Debt of Joint Ventures 862 967 780 889
Preferred Securities 19 19 19 19
(1)
TCPL acquired GTN on November 1, 2004.
These fair values are provided solely for information purposes and are not
recorded in the consolidated balance sheet.
NOTE 16 INCOME TAXES
Provision for Income Taxes
Year ended December 31 (millions of dollars) 2004 2003 2002
Current
Canada 390 264 229
Foreign 41 41 41
431 305 270
Future
Canada 34 183 193
Foreign 43 47 54
77 230 247
508 535 517
Geographic Components of Income
Year ended December 31 (millions of dollars) 2004 2003 2002
Canada 1,253 1,115 1,042
Foreign 296 281 280
Income from continuing operations before income taxes and 1,549 1,396 1,322
non-controlling interests
F-31
Reconciliation of Income Tax Expense
Year ended December 31 (millions of dollars) 2004 2003 2002
Income from continuing operations before income taxes and 1,549 1,396 1,322
non-controlling interests
Federal and provincial statutory tax rate 33.9 % 36.7 % 39.2 %
Expected income tax expense 525 512 518
Income tax differential related to regulated operations 62 29 (8 )
Higher (lower) effective foreign tax rates 2 (2 ) (13 )
Large corporations tax 21 28 30
Lower effective tax rate on equity in earnings of (9 ) (11 ) (2 )
affiliates
Non-taxable portion of gains related to Power LP (66 ) - -
Change in valuation allowance (7 ) (3 ) 8
Other (20 ) (18 ) (16 )
Actual income tax expense 508 535 517
Future Income Tax Assets and Liabilities
December 31 (millions of dollars) 2004 2003
Deferred costs 71 50
Deferred revenue 18 29
Alternative minimum tax credits 10 29
Net operating and capital loss carryforwards 7 28
Other 72 24
178 160
Less: Valuation allowance 17 24
Future income tax assets, net of valuation allowance 161 136
Difference in accounting and tax bases of plant, equipment 456 396
and PPAs
Investments in subsidiaries and partnerships 114 108
Unrealized foreign exchange gains on long-term debt 45 15
Other 55 44
Future income tax liabilities 670 563
Net future income tax liabilities 509 427
As permitted by Canadian GAAP, the Company follows the taxes payable method of
accounting for income taxes related to the operations of the Canadian natural
gas transmission operations. If the liability method of accounting had been
used, additional future income tax liabilities in the amount of $1,692 million
at December 31, 2004 (2003 - $1,758 million) would have been recorded and would
be recoverable from future revenues.
Unremitted Earnings of Foreign Investments
Income taxes have not been provided on the unremitted earnings of foreign
investments which the Company does not intend to repatriate in the foreseeable
future. If provision for these taxes had been made, future income tax
liabilities would increase by approximately $57 million at December 31, 2004
(2003 - $54 million).
Income Tax Payments
Income tax payments of $419 million were made during the year ended December
31, 2004 (2003 - $220 million; 2002 - $257 million).
F-32
NOTE 17 NOTES PAYABLE
2004 2003
Outstanding Weighted Outstanding Weighted
December 31 Average December 31 Average
(millions of Interest Rate (millions of Interest Rate
dollars) Per Annum at dollars) Per Annum at
December 31 December 31
Commercial Paper
Canadian dollars 546 2.6% 367 2.7%
Total credit facilities of $2.0 billion at December 31, 2004, were available to
support the Company's commercial paper programs 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, the Company had used approximately $61 million of its
total lines of credit for letters of credit and to support its ongoing
commercial arrangements. If drawn, interest on the lines of credit would be
charged at prime rates of Canadian chartered and U.S. banks and at other
negotiated financial bases. The cost to maintain the unused portion of the lines
of credit is approximately $2 million for the year ended December 31, 2004 (2003
- $2 million).
NOTE 18 ASSET RETIREMENT OBLIGATIONS
At December 31, 2004, the estimated undiscounted cash flows required to settle
the asset retirement obligation with respect to Gas Transmission were $48
million, calculated using an inflation rate of 3 per cent per annum, and the
estimated fair value of this liability was $12 million (2003 - $2 million). The
estimated cash flows have been discounted at rates ranging from 6.0 per cent to
6.6 per cent. At December 31, 2004, the expected timing of payment for
settlement of the obligations ranges from 13 to 25 years. No amount has been
recorded for asset retirement obligations relating to the regulated natural gas
transmission operation assets as it is not possible to make a reasonable
estimate of the fair value of the liability due to the indeterminate timing and
scope of the asset retirements. Management believes it is reasonable to assume
that all retirement costs associated with the regulated pipelines will be
recovered through tolls in future periods.
At December 31, 2004, the estimated undiscounted cash flows required to settle
the asset retirement obligation with respect to the Power business were $128
million, calculated using an inflation rate of 3 per cent per annum, and the
estimated fair value of this liability was $24 million (2003 - $7 million). The
estimated cash flows have been discounted at rates ranging from 6.0 per cent to
6.6 per cent. At December 31, 2004, the expected timing of payment for
settlement of the obligations ranges from 17 to 29 years.
F-33
Reconciliation of Asset Retirement Obligations
(millions of dollars) Gas Power Total
Transmission
Balance at December 31, 2002 2 6 8
Revisions in estimated cash flows - 1 1
Balance at December 31, 2003 2 7 9
New obligations and revisions in estimated cash flows 9 21 30
Removal of Power LP redemption obligations - (5 ) (5 )
Accretion expense 1 1 2
Balance at December 31, 2004 12 24 36
NOTE 19 EMPLOYEE FUTURE BENEFITS
The Company sponsors DB Plans that cover substantially all employees and
sponsored a defined contribution pension plan (DC Plan) which was effectively
terminated at December 31, 2002. Benefits provided under the DB Plans are based
on years of service and highest average earnings over three consecutive years of
employment, and increase annually by a portion of the increase in the Consumer
Products Index. Under the DC Plan, Company contributions were based on the
participating employees' pensionable earnings. As a result of the termination of
the DC Plan, members of this plan were awarded retroactive service credit under
the DB Plans for all years of service. In exchange for past service credit,
members surrendered the accumulated assets in their DC Plan accounts to the DB
Plans as at December 31, 2002. This plan amendment resulted in unamortized past
service costs of $44 million. Past service costs are amortized over the expected
average remaining service life of employees, which is approximately 11 years.
The Company also provides its employees with other post-employment benefits
other than pensions, including termination benefits and defined life insurance
and medical benefits beyond those provided by government-sponsored plans.
Effective January 1, 2003, the Company combined its previously existing other
post-employment benefit plans into one plan for active employees and provided
existing retirees the option of adopting the provisions of the new plan. This
plan amendment resulted in unamortized past service costs of $7 million. Past
service costs are amortized over the expected average remaining life expectancy
of former employees, which is approximately 19 years.
The expense for the DC Plan was nil for the year ended December 31, 2004 (2003
- nil; 2002 - $6 million). In 2004, the Company also expensed $1 million (2003 -
$1 million; 2002 - nil) related to retirement savings plans for its U.S.
employees.
Total cash payments for employee future benefits for 2004, consisting of cash
contributed by the Company to the DB Plans and other benefit plans was $88
million (2003 - $114 million).
F-34
The Company measures its accrued benefit obligations and the fair value of plan
assets for accounting purposes as at December 31 of each year. The most recent
actuarial valuation of the pension plans for funding purposes was as of January
1, 2005, and the next required valuation will be as of January 1, 2006.
Pension Benefit Other Benefit Plans
Plans
(millions of dollars) 2004 2003 2004 2003
Change in Benefit Obligation
Benefit obligation - beginning of year 960 841 106 95
Current service cost 28 25 3 2
Interest cost 58 52 7 6
Employee contributions 2 2 - -
Benefits paid (66 ) (45 ) (4 ) (4 )
Actuarial loss 46 66 (12 ) 7
Acquisition of subsidiary 72 19 23 -
Benefit obligation - end of year 1,100 960 123 106
Change in Plan Assets
Plan assets at fair value - beginning of year 799 621 - -
Actual return on plan assets 97 89 1 -
Employer contributions 84 110 4 4
Employee contributions 2 2 - -
Benefits paid (66 ) (45 ) (4 ) (4 )
Acquisition of subsidiary 54 22 25 -
Plan assets at fair value - end of year 970 799 26 -
Funded status - plan deficit (130 ) (161 ) (97 ) (106 )
Unamortized net actuarial loss 255 263 25 39
Unamortized past service costs 39 41 7 6
Unamortized transitional obligation related to - - - 25
regulated business
Accrued benefit asset/(liability), net of 164 143 (65 ) (36 )
valuation allowance of nil
F-35
The accrued benefit (asset)/liability, net of valuation allowance, is included
in the Company's balance sheet as follows.
Pension Benefit Other Benefit Plans
Plans
2004 2003 2004 2003
Other assets 206 201 3 -
Accounts payable (42 ) (58 ) (5 ) (4 )
Deferred amounts - - (63 ) (32 )
Total 164 143 (65 ) (36 )
Included in the above accrued benefit obligation and fair value of plan assets
at year end are the following amounts in respect of plans that are not fully
funded.
Pension Benefit Other Benefit Plans
Plans
2004 2003 2004 2003
Accrued benefit obligation (1,084 ) (942 ) (100 ) (106 )
Fair value of plan assets 952 778 - -
Funded status - plan deficit (132 ) (164 ) (100 ) (106 )
The Company's expected contributions for the year ended December 31, 2005 are
approximately $67 million for the pension benefit plans and approximately $6
million for the other benefit plans.
The following are estimated future benefit payments, which reflect expected
future service.
(millions of dollars) Pension Other
Benefits Benefits
2005 52 6
2006 53 6
2007 56 7
2008 58 7
2009 60 7
Years 2010 to 2014 343 40
The significant weighted average actuarial assumptions adopted in measuring the
Company's benefit obligations at December 31 are as follows.
Pension Benefit Other Benefit Plans
Plans
2004 2003 2004 2003
Discount rate 5.75% 6.00% 6.00% 6.25%
Rate of compensation increase 3.50% 3.50%
F-36
The significant weighted average actuarial assumptions adopted in measuring the
Company's net benefit plan cost for years ended December 31 are as follows.
Pension Benefit Plans Other Benefit Plans
2004 2003 2002 2004 2003 2002
Discount rate 6.00% 6.25% 6.75% 6.25% 6.50% 6.85%
Expected long-term rate of 6.90% 7.25% 7.52%
return on plan assets
Rate of compensation 3.50% 3.75% 3.50%
increase
The overall expected long-term rate of return on plan assets is based on
historical and projected rates of return for both the portfolio in aggregate and
for each asset class in the portfolio. Assumed projected rates of return are
selected after analyzing historical experience and future expectations of the
level and volatility of returns. Asset class benchmark returns, asset mix and
anticipated benefit payments from plan assets are also considered in the
determination of the overall expected rate of return.
For measurement purposes, a 9.0 per cent annual rate of increase in the per
capita cost of covered health care benefits was assumed for 2005. The rate was
assumed to decrease gradually to 5.0 per cent for 2014 and remain at that level
thereafter. A one percentage point increase or decrease in assumed health care
cost trend rates would have the following effects.
(millions of dollars) Increase Decrease
Effect on total of service and interest cost components 2 (1 )
Effect on post-employment benefit obligation 12 (11 )
F-37
The Company's net benefit cost is as follows.
Pension Benefit Plans Other Benefit Plans
Year ended December 31 2004 2003 2002 2004 2003 2002
(millions of dollars)
Current service cost 28 25 11 3 2 2
Interest cost 58 52 43 7 6 4
Actual return on plan (97 ) (89 ) (9 ) 1 - -
assets
Actuarial loss 46 66 93 (12 ) 7 26
Plan amendment - - 92 - - 7
Elements of net benefit 35 54 230 (1 ) 15 39
cost prior to adjustments
to recognize the long-term
nature of net benefit cost
Difference between expected 39 38 (36 ) (1 ) - -
and actual return on plan
assets
Difference between (32 ) (58 ) (91 ) 13 (6 ) (26 )
actuarial loss recognized
and actual actuarial loss
on accrued benefit
obligation
Difference between 3 3 (92 ) - 1 (7 )
amortization of past
service costs and actual
plan amendments
Amortization of - - - 2 2 2
transitional obligation
related to regulated
business
Net benefit cost recognized 45 37 11 13 12 8
The Company's pension plan weighted average asset allocation at December 31, by
asset category, and weighted average target allocation at December 31, by asset
category, is as follows.
Percentage of Target
Plan Assets Allocation
Asset Category 2004 2003 2004
Debt securities 44% 47% 35% to 60%
Equity securities 56% 53% 40% to 65%
100% 100%
The assets of the pension plan are managed on a going concern basis subject to
legislative restrictions. The plan's investment policy is to maximize returns
within an acceptable risk tolerance. Pension assets are invested in a
diversified manner with consideration given to the demographics of the plan
participants.
F-38
NOTE 20 CHANGES IN OPERATING WORKING CAPITAL
Year ended December 31 (millions of dollars) 2004 2003 2002
Decrease/(increase) in accounts receivable 7 26 (45 )
Decrease/(increase) in inventories - 15 (3 )
Decrease/(increase) in other current assets 33 21 (53 )
(Decrease)/increase in accounts payable - 52 120
(Decrease)/increase in accrued interest (7 ) (2 ) 14
33 112 33
NOTE 21 COMMITMENTS, CONTINGENCIES AND GUARANTEES
Commitments
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.
Year ended December 31 (millions of dollars) Minimum Amounts Net
Lease Recoverable Payments
Payments under
Sub-Leases
2005 37 (9 ) 28
2006 45 (10 ) 35
2007 51 (9 ) 42
2008 53 (9 ) 44
2009 53 (9 ) 44
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. Net rental expense on operating leases for the year ended
December 31, 2004 was $7 million (2003 - $2 million; 2002 - $7 million).
On June 18, 2003, the Mackenzie Delta gas producers, the Aboriginal Pipeline
Group (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. The ability to recover this
investment is dependent upon the outcome of the project.
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.
F-39
The Company and its subsidiaries are subject to various other legal proceedings
and actions arising in the normal course of business. While the final outcome of
such legal proceedings and actions cannot be predicted with certainty, it is the
opinion of Management that the resolution of such proceedings and actions will
not have a material impact on the Company's consolidated financial position or
results of operations.
Guarantees
Upon acquisition of Bruce Power, the Company, together with Cameco Corporation
and BPC Generation Infrastructure Trust, guaranteed on a several pro-rata basis
certain contingent financial obligations of Bruce Power related to operator
licenses, the lease agreement, power sales agreements and contractor services.
TCPL's share of the net exposure under these guarantees at December 31, 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 de Occidente, S.A. (TransGas). The
Company has a 46.5 per cent interest in TransGas. Under the terms of the
agreement, the Company severally with another major multinational company may be
required to fund more than their proportionate share of debt obligations of
TransGas in the event that the minority shareholders fail to contribute. Any
payments made by TCPL under this agreement convert into share capital of
TransGas. The potential exposure is contingent on the impact of any change of
law on TransGas' ability to service the debt. From the issuance of the debt in
1995 to date, there has been no change in applicable law and thus no exposure to
TCPL. The debt matures in 2010. The Company has made no provision related to
this guarantee.
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.
NOTE 22 DISCONTINUED OPERATIONS
The Board of Directors approved plans in previous years to dispose of the
Company's International, Canadian Midstream, Gas Marketing and certain other
businesses. Revenues from discontinued operations for the year ended December
31, 2004 were nil (2003 - $2 million; 2002 - $36 million). Net income from
discontinued operations for the year ended December 31, 2004 was $52 million,
net of $27 million of income taxes (2003 - $50 million, net of $29 million of
income taxes; 2002 - nil). The net income from discontinued operations
recognized in 2003 and 2004 represents the original $102 million after-tax
deferred gain on the disposition of certain of the Gas Marketing operations.
Included in accounts payable at December 31, 2004 was the remaining $55 million
provision for loss on discontinued operations.
F-40
NOTE 23 U.S. GAAP
The Company's consolidated financial statements have been prepared in accordance
with Canadian GAAP, which, in some respects, differ from U.S. GAAP. The effects
of these differences on the Company's financial statements are as follows.
Condensed Statement of Consolidated Income and Comprehensive Income in
Accordance with U.S. GAAP(1)
Year ended December 31 (millions of dollars) 2004 2003 2002
Revenues 4,700 4,919 4,565
Cost of sales 440 592 441
Other costs and expenses 1,638 1,663 1,532
Depreciation 857 819 729
2,935 3,074 2,702
Operating income 1,765 1,845 1,863
Other (income)/expenses
Equity income(1) (353 ) (334 ) (260 )
Other expenses(2) 631 841 850
Income taxes 490 515 499
768 1,022 1,089
Income from continuing operations - U.S. GAAP 997 823 774
Net income from discontinued operations - U.S. GAAP 52 50 -
Income before cumulative effect of the application of 1,049 873 774
accounting changes in accordance with U.S. GAAP
Cumulative effect of the application of accounting changes, - (13 ) -
net of tax(3)
Net Income in Accordance with U.S. GAAP 1,049 860 774
Adjustments affecting comprehensive income under U.S. GAAP
Foreign currency translation adjustment, net of tax (31 ) (54 ) 1
Changes in minimum pension liability, net of tax(4) 72 (2 ) (40 )
Unrealized gain/(loss) on derivatives, net of tax(5) 1 8 (4 )
Comprehensive Income in Accordance with U.S. GAAP 1,091 812 731
F-41
Reconciliation of Income from Continuing Operations
Year ended December 31 (millions of dollars) 2004 2003 2002
Net Income from Continuing Operations in Accordance with 1,031 859 805
Canadian GAAP
U.S. GAAP adjustments
Preferred securities charges(6) (48 ) (57 ) (58 )
Tax impact of preferred securities charges 17 21 22
Unrealized (loss)/gain on foreign exchange and interest (12 ) (9 ) 30
rate derivatives(5)
Tax impact of (loss)/gain on foreign exchange and 4 3 (12 )
interest rate derivatives
Unrealized gain/(loss) on energy marketing contracts(3) 10 28 (21 )
Tax impact of unrealized gain/(loss) on energy marketing (3 ) (10 ) 8
contracts
Equity loss(7) (2 ) (18 ) -
Tax impact of equity loss - 6 -
Income from Continuing Operations in Accordance with U.S. 997 823 774
GAAP
Condensed Statement of Consolidated Cash Flows in Accordance with U.S. GAAP
Year ended December 31 (millions of dollars) 2004 2003 2002
Cash Generated from Operations
Funds generated from continuing operations 1,527 1,619 1,610
Decrease in operating working capital 44 108 40
Net cash provided by continuing operations 1,571 1,727 1,650
Net cash (used in)/provided by discontinued operations (6 ) (17 ) 59
1,565 1,710 1,709
Investing Activities
Net cash used in investing activities (1,304 ) (943 ) (796 )
Financing Activities
Net cash used in financing activities (333 ) (582 ) (990 )
Effect of Foreign Exchange Rate Changes on Cash and (87 ) (52 ) (3 )
Short-Term Investments
(Decrease)/Increase in Cash and Short-Term Investments (159 ) 133 (80 )
Cash and Short-Term Investments
Beginning of year 282 149 229
Cash and Short-Term Investments
End of year 123 282 149
F-42
Condensed Balance Sheet in Accordance with U.S. GAAP(1)
December 31 (millions of dollars) 2004 2003
Current assets 907 1,017
Long-term investments(7)(8) 1,887 1,760
Plant, property and equipment 17,083 15,753
Regulatory asset(9) 2,606 2,721
Other assets 1,235 1,385
23,718 22,636
Current liabilities(10) 2,653 2,179
Deferred amounts(3)(5)(8) 803 827
Long-term debt(5) 9,753 9,494
Deferred income taxes(9) 3,048 3,039
Preferred securities(11) 554 694
Non-controlling interests 76 82
Shareholders' equity 6,831 6,321
23,718 22,636
F-43
Statement of Other Comprehensive Income in Accordance with U.S. GAAP
(millions of dollars) Cumulative Minimum Cash Flow Total
Translation Pension Hedges (SFAS
Account Liability No. 133)
(SFAS No.
87)
Balance at January 1, 2002 13 (56 ) (9 ) (52 )
Changes in minimum pension liability, net - (40 ) - (40 )
of tax of $22(4)
Unrealized loss on derivatives, net of - - (4 ) (4 )
tax of $(1)(5)
Foreign currency translation adjustment, 1 - - 1
net of tax of nil
Balance at December 31, 2002 14 (96 ) (13 ) (95 )
Changes in minimum pension liability, net - (2 ) - (2 )
of tax of $1(4)
Unrealized gain on derivatives, net of - - 8 8
tax of nil(5)
Foreign currency translation adjustment, (54 ) - - (54 )
net of tax of $(64)
Balance at December 31, 2003 (40 ) (98 ) (5 ) (143 )
Changes in minimum pension liability, net - 72 - 72
of tax of $(39)(4)
Unrealized gain on derivatives, net of - - 1 1
tax of $(3)(5)
Foreign currency translation adjustment, (31 ) - - (31 )
net of tax of $(44)
Balance at December 31, 2004 (71 ) (26 ) (4 ) (101 )
(1)
In accordance with U.S. GAAP, the Condensed Statement of Consolidated Income
and Balance Sheet are prepared using the equity method of accounting for
joint ventures. Excluding the impact of other U.S. GAAP adjustments, the use
of the proportionate consolidation method of accounting for joint ventures,
as required under Canadian GAAP, results in the same net income and
shareholders' equity.
(2)
Other expenses included an allowance for funds used during construction of
$3 million for the year ended December 31, 2004 (2003 - $2 million; 2002 -
$4 million).
(3)
Subsequent to October 1, 2003, the energy contracts that were accounted for
as hedges under the provisions of Statement of Financial Accounting
Standards (SFAS) No. 133 qualified as hedges. Substantially all derivative
energy contracts are now accounted for as hedges under both U.S. and
Canadian GAAP. All gains or losses on the contracts that did not qualify as
hedges under SFAS No. 133, and the amounts of any ineffectiveness on the
hedging contracts, are included in income each period. Substantially all of
the amounts recorded in 2004 and 2003 as differences between U.S. and
Canadian GAAP relate to gains and losses on contracts for periods before
they were documented as hedges for purposes of U.S. GAAP and to differences
in accounting with respect to physical energy trading contracts in the U.S.
and Canada.
(4)
Under U.S. GAAP, a net loss recognized pursuant to SFAS No. 87 "Employers'
Accounting for Pensions" as an additional pension liability not yet
recognized as net period pension cost, must be recorded as a component of
comprehensive income. The net amount recognized at December 31 is as
follows.
December 31 (millions of dollars) 2004 2003
Prepaid benefit cost 206 201
Accounts payable (42 ) (58 )
Intangible assets (1 ) (41 )
Accumulated other comprehensive income (40 ) (151 )
Net amount recognized 123 (49 )
F-44
The accumulated benefit obligation for the Company's DB Plans was $943 million
at December 31, 2004 (2003 - $819 million).
(5)
Effective January 1, 2004, all foreign exchange and interest rate
derivatives are recorded in the Company's consolidated financial statements
at fair value under Canadian GAAP. Under the provisions of SFAS No. 133
"Accounting for Derivatives and Hedging Activities", all derivatives are
recognized as assets and liabilities on the balance sheet and measured at
fair value. For derivatives designated as fair value hedges, changes in the
fair value are recognized in earnings together with an equal or lesser
amount of changes in the fair value of the hedged item attributable to the
hedged risk. For derivatives designated as cash flow hedges, changes in the
fair value of the derivative that are effective in offsetting the hedged
risk are recognized in other comprehensive income until the hedged item is
recognized in earnings. Any ineffective portion of the change in fair value
is recognized in earnings each period. Substantially all of the amounts
recorded in 2004 as differences between U.S. and Canadian GAAP, for income
from continuing operations, relate to the differences in accounting
treatment with respect to the hedged item and, for comprehensive income,
relate to cash flow hedges.
During 2004, under the provisions of SFAS 133, net gains of $10 million
(2003 - $47 million; 2002 - $38 million) from the hedges of changes in the
fair value of long-term debt, and net losses of $18 million (2003 - $53
million; 2002 - $20 million) in the fair value of the hedged item were
included in earnings for U.S. GAAP purposes as an adjustment to interest
expense and foreign exchange losses. No amounts of the derivatives' gains or
losses were excluded from the assessment of hedge effectiveness in fair
value hedging relationships.
No amounts were included in income in 2004, 2003 and 2002 with respect to
ineffectiveness of cash flow hedges. For amounts included in other
comprehensive income at December 31, 2004, $2 million (2003 - $9 million;
2002 - $(5) million) relates to the hedging of interest rate risk, $(3)
million (2003 - $5 million; 2002 - $1 million) relates to the hedging of
foreign exchange rate risk, and $2 million (2003 - $(6) million; 2002 - nil)
relates to the hedging of energy price risk. Of these amounts, $2 million is
expected to be recorded in earnings during 2005.
At December 31, 2004, assets of $(29) million (2003 - $91 million) and
liabilities of $(27) million (2003 - $93 million) were (reduced)/added for
U.S. GAAP purposes to reflect the fair value of derivatives and the
corresponding change in the fair value of hedged items.
(6)
Under U.S. GAAP, the financial charges related to preferred securities are
recognized as an expense, rather than dividends.
(7)
Under Canadian GAAP, pre-operating costs incurred during the commissioning
phase of a new project are deferred until commercial production levels are
achieved. After such time, those costs are amortized over the estimated life
of the project. Under U.S. GAAP, such costs are expensed as incurred.
Certain start-up costs incurred by Bruce Power, L.P. (an equity investment)
are required to be expensed under U.S. GAAP.
Under both Canadian GAAP and U.S. GAAP, interest is capitalized on
expenditures relating to construction of development projects actively being
prepared for their intended use. In Bruce Power, L.P. under U.S. GAAP, the
carrying value of development projects against which interest is capitalized
is lower due to the expensing of pre-operating costs.
(8)
Effective January 1, 2003, the Company adopted the provisions of Financial
Interpretation (FIN) 45 that require the recognition of a liability for the
fair value of certain guarantees that require payments contingent on
specified types of future events. The measurement standards of FIN 45 are
applicable to guarantees entered into after January 1, 2003. For U.S. GAAP
purposes, the fair value of guarantees recorded as a liability at December
31, 2004 was $9 million (2003 - $4 million) and relates to the Company's
equity interest in Bruce Power.
(9)
Under U.S. GAAP, the Company is required to record a deferred income tax
liability for its cost-of-service regulated businesses. As these deferred
income taxes are recoverable through future revenues, a corresponding
regulatory asset is recorded for U.S. GAAP purposes.
(10)
Current liabilities at December 31, 2004 include dividends payable of $146
million (2003 - $136 million) and current taxes payable of $260 million
(2003 - $271 million).
(11)
The fair value of the preferred securities at December 31, 2004 was $572
million (2003 - $612 million). The Company made preferred securities charges
payments of $48 million for the year ended December 31, 2004 (2003 - $57
million; 2002 - $58 million).
F-45
Income Taxes
The tax effects of differences between the accounting value and the tax value of
assets and liabilities are as follows.
December 31 (millions of dollars) 2004 2003
Deferred Tax Liabilities
Difference in accounting and tax bases of plant, equipment 1,741 1,813
and PPAs
Taxes on future revenue requirement 914 962
Investments in subsidiaries and partnerships 438 373
Other 140 87
3,233 3,235
Deferred Tax Assets
Net operating and capital loss carryforwards 7 28
Deferred amounts 89 79
Other 106 113
202 220
Less: Valuation allowance 17 24
185 196
Net deferred tax liabilities 3,048 3,039
Other
Effective December 31, 2003, the Company adopted the provisions of FIN 46
(Revised) "Consolidation of Variable Interest Entities" that requires the
consolidation of certain entities that are controlled through financial
interests that indicate control (referred to as 'variable interests'). Adopting
these provisions has had no impact on the U.S. GAAP financial statements of the
Company.
In May 2003, the FASB issued SFAS No. 150 "Accounting for Certain Financial
Instruments with Characteristics of both Liabilities and Equity". This statement
establishes standards for how an issuer classifies and measures in its statement
of financial position certain financial instruments with characteristics of both
liabilities and equity. It requires that an issuer classify a financial
instrument that is within its scope as a liability (or an asset in some
circumstances) because that financial instrument embodies an obligation of the
issuer. Many of those instruments were previously classified as equity. Adopting
the provisions of SFAS No. 150 has had no impact on the U.S. GAAP financial
statements of the Company.
F-46
Summarized Financial Information of Long-Term Investments
The following summarized financial information of long-term investments includes
those investments that are accounted for by the equity method under U.S. GAAP
(including those that are accounted for by the proportionate consolidation
method under Canadian GAAP).
Year ended December 31 (millions of dollars) 2004 2003 2002
Income
Revenues 1,149 1,063 798
Other costs and expenses (575 ) (528 ) (273 )
Depreciation (155 ) (141 ) (146 )
Financial charges and other (66 ) (60 ) (119 )
Proportionate share of income before income taxes of 353 334 260
long-term investments
December 31 (millions of dollars) 2004 2003
Balance Sheet
Current assets 361 385
Plant, property and equipment 3,020 2,944
Current liabilities (248 ) (204 )
Deferred amounts (net) (199 ) (286 )
Non-recourse debt (1,030 ) (1,060 )
Deferred income taxes (17 ) (19 )
Proportionate share of net assets of long-term investments 1,887 1,760
F-47
This information is provided by RNS
The company news service from the London Stock Exchange
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