We could not find any results for:
Make sure your spelling is correct or try broadening your search.
Customisable watchlists with full streaming quotes from leading exchanges, such as LSE, NASDAQ, NYSE, AMEX, Bovespa, BIT and more.
| Name | Symbol | Market | Type |
|---|---|---|---|
| Citi Fun 24 | LSE:BC93 | London | Medium Term Loan |
| Price Change | % Change | Price | Bid Price | Offer Price | High Price | Low Price | Open Price | Traded | Last Trade | |
|---|---|---|---|---|---|---|---|---|---|---|
| 0.00 | 0.00% | 0 | - |
Hot Features
Premium
RNS Number:4666Z
TransCanada Pipelines Ld
07 March 2006
PART 4
CONTRACTUAL OBLIGATIONS
Obligations and Commitments
Total long-term debt at December 31, 2005 was approximately $10.0 billion
compared to approximately $10.5 billion at December 31, 2004. TCPL's share of
total debt of joint ventures at December 31, 2005 was $978 million compared to
$893 million at December 31, 2004. Total notes payable at December 31, 2005,
including TCPL's proportionate share of the notes payable of joint ventures,
were $962 million compared to $546 million at December 31, 2004. The security
provided by each joint venture, except the capital lease obligations at Bruce
Power, 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. TCPL has provided certain pro-rata guarantees related to the capital
lease obligations of Bruce Power.
Effective January 1, 2005, under new Canadian accounting standards the
shareholders' equity component of preferred securities was classified as
long-term debt.
At December 31, 2005, scheduled principal repayments and interest payments
related to long-term debt and the company's proportionate share of the long-term
debt of joint ventures are as follows.
46 MANAGEMENT'S DISCUSSION AND ANALYSIS
PRINCIPAL REPAYMENTS
Year ended December 31 (millions of dollars)
2006 2007 2008 2009 2010 2011+
Long-term debt 393 604 547 742 416 7,331
Long-term debt of joint 41 28 29 89 286 505
ventures
Total principal 434 632 576 831 702 7,836
repayments
INTEREST PAYMENTS
Year ended December 31 (millions of dollars)
2006 2007 2008 2009 2010 2011+
Interest payments on 806 784 734 682 637 7,320
long-term debt
Interest payments on 70 68 67 64 52 356
long-term debt of joint
ventures
Total interest payments 876 852 801 746 689 7,676
At December 31, 2005, future annual payments, net of sub-lease receipts, under
the company's operating leases for various premises, services, equipment and a
natural gas storage facility are approximately as follows.
OPERATING LEASE PAYMENTS
Year ended December 31 (millions of dollars)
2006 2007 2008 2009 2010 2011+
Minimum lease payments 46 52 54 54 53 646
Amounts recoverable (12 ) (12 ) (12 ) (11 ) (11 ) (13 )
under sub-leases
Net payments 34 40 42 43 42 633
The operating lease agreements for premises, services and equipment expire at
various dates through 2011, with an option to renew certain lease agreements for
five years. The operating lease agreement for the natural gas storage facility
expires in 2030 with lessee termination rights every fifth anniversary
commencing in 2010 and with the lessor having the right to terminate the
agreement every five years commencing in 2015.
At December 31, 2005, the company's future purchase obligations are
approximately as follows.
MANAGEMENT'S DISCUSSION AND ANALYSIS 47
PURCHASE OBLIGATIONS(1)
Year ended December 31 (millions of dollars)
2006 2007 2008 2009 2010 2011+
Gas Transmission
Transportation by 179 175 131 89 79 52
others(2)
Other 253 16 12 3 - -
Power
Commodity purchases(3) 1,163 1,039 881 522 525 4,802
Capital expenditures(4) 534 390 145 70 - -
Other(5) 52 56 32 21 29 92
Corporate
Information technology 16 14 14 14 7 14
and other
Total purchase 2,197 1,690 1,215 719 640 4,960
obligations
(1)
The amounts in this table exclude funding contributions to pension plans and
funding to the APG.
(2)
Rates are based on known 2006 levels. Beyond 2006, demand rates are subject
to change. The contract obligations in the table are based on known or
contracted demand volumes only and exclude commodity charges incurred when
volumes flow. Transportation by others is generally included in the revenue
requirements of the regulated pipelines.
(3)
Commodity purchases include fixed and variable components. The variable
components are estimates and are subject to variability in plant production,
market prices and regulatory tariffs.
(4)
Amounts are estimates and are subject to variability based on timing of
construction and project enhancements.
(5)
Includes estimates of certain amounts which are subject to change depending
on plant fired hours, the consumer price index, actual plant maintenance
costs, plant salaries as well as changes in regulated rates for
transportation.
During 2006, TCPL expects to make funding contributions to the company's
pension plans and other benefit plans in the amount of approximately $95 million
and $7 million, respectively. The expected increase in total funding in 2006
from $74 million in 2005 is due to continued reductions in discount rates used
to calculate plan obligations partially offset by investment performance above
long-term expectations in 2005. During 2006, TCPL's proportionate share of
expected funding contributions to be made by joint ventures to their respective
pension plans and other benefit plans is approximately $27 million and $2
million, respectively.
48 MANAGEMENT'S DISCUSSION AND ANALYSIS
Bruce Power
Included in Power's capital expenditures in the table above is TCPL's share of
Bruce A's signed commitments to third party suppliers for the next five years
for the restart and refurbishment of the currently idle Units 1 and 2, extending
the operating life of Unit 3 by replacing its steam generators and fuel channels
when required and replacing the steam generators on Unit 4, as follows.
Year ended December 31 (millions of dollars)
2006 322
2007 311
2008 142
2009 69
2010 -
844
Aboriginal Pipeline Group
On June 18, 2003, the Mackenzie Delta gas producers, the APG and TCPL reached an
agreement which governs TCPL's role in the Mackenzie Gas Pipeline Project. The
project would result in a natural gas pipeline being constructed from Inuvik,
Northwest Territories, to the northern border of Alberta, where it would connect
with the Alberta System. Under the agreement, TCPL agreed to finance the APG for
its one-third share of project development costs. These costs were originally
estimated to be approximately $90 million, but given extended project delays,
the protracted regulatory process and the projected timing to reach a decision
to construct the pipeline, this share is currently forecast to increase to
approximately $145 million. As at December 31, 2005, TCPL had funded $87 million
(2004 - $60 million) of this loan which is included in other assets. The ability
to recover this investment is dependent upon the outcome of the project.
TCPL and its affiliates have long-term natural gas transportation and natural
gas purchase arrangements as well as other purchase obligations, all of which
are or were transacted at market prices and in the normal course of business.
Guarantees
TCPL had no outstanding guarantees related to the long-term debt of unrelated
third parties at December 31, 2005.
The company, together with Cameco and BPC, has severally guaranteed one-third
of certain contingent financial obligations of Bruce B related to power sales
agreements, operator licenses, the lease agreement, and contractor services. The
terms of the guarantees currently range from 2018 to 2019.
As part of the reorganization of Bruce Power, including the formation of Bruce
A and the commitment to restart and refurbish the Bruce A units, the company,
together with BPC, severally guaranteed one-half of certain contingent financial
obligations of Bruce A related to the refurbishment agreement with the OPA and
cost sharing and sublease agreements with Bruce B. The terms of the guarantees
range from 2019 to 2036.
TCPL's share of the net exposure under these Bruce Power guarantees at December
31, 2005 was estimated to be approximately $652 million of a calculated maximum
of $758 million. The current carrying amount of the liability related to these
guarantees is nil and the fair value is approximately $17 million.
TCPL has guaranteed the equity undertaking of a subsidiary which supports the
payment, under certain conditions, of principal and interest on US$133 million
of public debt obligations of TransGas. The company has a 46.5 per cent interest
in TransGas. Under the terms of the agreement, the company severally with
another major multinational company may be required to fund more than their
proportionate share of debt obligations of TransGas in the event that the
minority shareholders fail to contribute. Any payments made by TCPL under this
agreement convert into share capital of TransGas. The potential exposure is
contingent on the impact of any change of law on TransGas' ability to
MANAGEMENT'S DISCUSSION AND ANALYSIS 49
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. As at December 31, 2005, there was US$54
million remaining in the escrow account. The outstanding funds in the escrow
account represent the full face amount of the potential liability under certain
GTN guarantees and are to be used to satisfy the liability of GTN under these
designated guarantees.
Contingencies
The Canadian Alliance of Pipeline Landowners' Associations and two individual
landowners commenced an action in 2003 under Ontario's Class Proceedings Act,
1992, against TCPL and Enbridge Inc. for damages of $500 million alleged to
arise from the creation of a control zone within 30 metres of the pipeline
pursuant to Section 112 of the NEB Act. The company believes the claim is
without merit and will vigorously defend the action. The company has made no
provision for any potential liability. A liability, if any, would be dealt with
through the regulatory process.
The company and its subsidiaries are subject to various other legal proceedings
and actions arising in the normal course of business. While the final outcome of
such legal proceedings and actions cannot be predicted with certainty, it is the
opinion of management that the resolution of such proceedings and actions will
not have a material impact on the company's consolidated financial position or
results of operations.
FINANCIAL AND OTHER INSTRUMENTS
The company issues short-term and long-term debt, purchases and sells energy
commodities including amounts in foreign currencies, and invests in foreign
operations. These activities result in exposures to interest rates, energy
commodity prices and foreign currency exchange rates. The company utilizes
derivatives to manage the risk that results from these activities.
Derivatives and other instruments must be designated and effective to qualify
for hedge accounting. Derivatives are recorded at their fair value at each
balance sheet date. For cash flow and fair value hedges, gains or losses
relating to derivatives are deferred and recognized in the same period and in
the same financial statement category as the corresponding hedged transactions.
For hedges of net investments in self-sustaining foreign operations, exchange
gains or losses on derivatives, net of tax, and designated foreign currency
denominated debt are offset against the exchange losses or gains arising on the
translation of the financial statements of the foreign operations included in
the foreign exchange adjustment account in Shareholders' Equity. In the event
that a derivative does not meet the designation or effectiveness criteria,
realized and unrealized gains or losses are recognized in income each period in
the same financial statement category as the underlying transaction giving rise
to the exposure being economically hedged. Premiums paid or received with
respect to derivatives that are hedges are deferred and amortized to income over
the term of the hedge.
If a derivative that previously qualified as a hedge is settled, de-designated
or ceases to be effective, the gain or loss at that date is deferred and
recognized in the same period and in the same financial statement category as
the corresponding hedged transactions. If a hedged anticipated transaction is no
longer probable to occur, related deferred gains or losses are recognized in
income in the current period.
The recognition of gains and losses on derivatives for Canadian Mainline,
Alberta System, the Foothills System and the BC System exposures is determined
through the regulatory process.
The fair value of foreign exchange and interest rate derivatives has been
estimated using year-end market rates. The fair value of power, natural gas and
heat rate derivatives has been calculated using estimated forward prices for the
relevant period.
50 MANAGEMENT'S DISCUSSION AND ANALYSIS
Net Investment in Foreign Operations
At December 31, 2005 and 2004, the company had net investments in self
sustaining foreign operations with a U.S. dollar functional currency which
created an exposure to changes in exchange rates. The company uses U.S. dollar
denominated debt and derivatives to hedge this exposure on an after-tax basis.
The fair value for derivatives used to manage the exposure is shown in the table
below.
Asset/(Liability)
2005 2004
Notional or Notional or
Notional Notional
December 31 Accounting Principal Principal
(millions of dollars) Treatment Fair Value Amount Fair Value Amount
U.S. dollar Hedge 119 U.S. 450 95 U.S. 400
cross-currency swaps
(maturing 2006 to 2012)
U.S. dollar forward Hedge 5 U.S. 525 (1 ) U.S. 305
foreign exchange
contracts (maturing
2006)
U.S. dollar options Hedge - U.S. 60 1 U.S. 100
(maturing 2006)
Reconciliation of Foreign Exchange Adjustment (Losses)/Gains
December 31 (millions of dollars) 2005 2004
Balance at January 1 (71 ) (40 )
Translation losses on foreign currency denominated net assets(1) (21 ) (39 )
Gains on derivatives 23 52
Income taxes (21 ) (44 )
Balance at December 31 (90 ) (71 )
(1)
In 2005, includes gains of $80 million (2004 - $101 million) related to
foreign currency denominated debt designated as a hedge.
Foreign Exchange Gains/(Losses)
Foreign exchange gains included in Other Expenses/(Income) for the year ended
December 31, 2005 are $19 million (2004 - $6 million; 2003 - nil).
MANAGEMENT'S DISCUSSION AND ANALYSIS 51
Foreign Exchange and Interest Rate Management Activity
The company manages the foreign exchange and interest rate risks related to its
U.S. dollar denominated debt, and transactions and interest rate exposures of
the Canadian Mainline, the Alberta System and the BC 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)
2005 2004
Notional or Notional or
Notional Notional
December 31 Accounting Principal Principal
(millions of dollars) Treatment Fair Value Amount Fair Value Amount
Foreign Exchange
Cross-currency swaps
(maturing 2010 to Non-hedge (86 ) 363/U.S. 257 (69 ) 363/U.S. 257
2013)
Interest Rate
Interest rate swaps
Canadian dollars
(maturing 2007 Hedge 4 100 7 145
to 2008)
(maturing 2006 Non-hedge 7 374 9 374
to 2009)
11 16
U.S. dollars
(maturing 2007 Non-hedge 5 U.S. 100 7 U.S. 100
to 2009)
52 MANAGEMENT'S DISCUSSION AND ANALYSIS
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)
2005 2004
Notional or Notional or
Notional Notional
December 31 Accounting Principal Principal
(millions of dollars) Treatment Fair Value Amount Fair Value Amount
Foreign Exchange
Options (maturing 2006) Non-hedge 1 U.S. 195 2 U.S. 255
Forward foreign
exchange contracts
(maturing 2006) Hedge 2 U.S. 29 - -
(maturing 2006) Non-hedge 1 U.S. 208 1 U.S. 129
Interest Rate
Options Non-hedge - - - U.S. 50
Interest rate swaps
Canadian dollar
(maturing 2007 to Hedge 1 100 4 100
2009)
(maturing 2006 to Non-hedge 1 423 5 485
2011)
2 9
U.S. dollar
(maturing 2013) Hedge - U.S. 50 3 U.S. 375
(maturing 2006 to Non-hedge 18 U.S. 550 22 U.S. 500
2010)
18 25
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, 2005 was nil (2004 - $1 million).
MANAGEMENT'S DISCUSSION AND ANALYSIS 53
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
value and notional volumes of contracts for differences and the swap, future,
option and heat rate contracts are shown in the tables below.
Power
Asset/(Liability)
2005 2004
Accounting
December 31 (millions of dollars) Treatment Fair Value Fair Value
Power - swaps and contracts for differences
(maturing 2006 to 2011) Hedge (130 ) 7
(maturing 2006 to 2010) Non-hedge 13 (2 )
Gas - swaps, futures and options
(maturing 2006 to 2016) Hedge 17 (39 )
(maturing 2006 to 2008) Non-hedge (11 ) (2 )
Heat rate contracts
(maturing 2006) Non-hedge - (1 )
Notional Volumes
Power (GWh) Gas (Bcf)
Accounting
December 31, 2005 Treatment Purchases Sales Purchases Sales
Power - swaps and contracts for
differences
(maturing 2006 to 2011) Hedge 2,566 7,780 - -
(maturing 2006 to 2010) Non-hedge 1,332 456 - -
Gas - swaps, futures and
options
(maturing 2006 to 2016) Hedge - - 91 69
(maturing 2006 to 2008) Non-hedge - - 15 18
Heat rate contracts
(maturing 2006) Non-hedge - 35 - -
December 31, 2004
Power - swaps and contracts for Hedge 3,314 7,029 - -
differences
Non-hedge 438 - - -
Gas - swaps, futures and options Hedge - - 80 84
Non-hedge - - 5 8
Heat rate contracts Non-hedge - 229 2 -
Certain of the company's joint ventures use power derivatives to manage energy
price risk exposures. The company's proportionate share of the fair value of
these outstanding power sales derivatives at December 31, 2005 was $(38) million
(2004 - nil) and relates to contracts which cover the period 2006 to 2008. The
company's proportionate share of the notional sales volumes associated with this
exposure at December 31, 2005 was 2,058 GWh (2004 - nil).
54 MANAGEMENT'S DISCUSSION AND ANALYSIS
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 and ultimately, shareholder value.
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.
*
Accountability - Business lines are accountable for all risks and the
related returns for their particular businesses.
*
Audit Review - Risk processes 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, financial and counterparty risks and related exposures in
accordance with the company's market risk, interest rate and foreign exchange
risk, and counterparty risk policies. The company's primary market and financial
risks result from volatility in commodity positions and 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 16 to the consolidated financial statements.
MANAGEMENT'S DISCUSSION AND ANALYSIS 55
Risks and Risk Management Related to the Kyoto Protocol
TCPL is in the business of transporting natural gas and generating electricity
to meet the growing energy needs of businesses and consumers throughout North
America. While expanding the company's businesses, TCPL continuously identifies
and takes action to manage issues that could affect the company's ability to
provide consumers with safe, reliable and cost-effective energy supplies. Among
these issues are business risks associated with greenhouse gas emissions.
In Canada, TCPL's fossil-fired power plants, pipeline assets and carbon black
facilities are expected to be covered under legislation for large final
emitters. While the broad elements of the proposed regulations to reduce
greenhouse gas emissions intensities from large industrial emitters have been
established, key policy elements remain outstanding, including details of
compliance options that entities may use to fulfill compliance obligations. At
this time, it is difficult to determine the level of impact to the company's
Canadian assets until these and other key policy elements have been defined.
In 2006, TCPL will continue with its strategy for managing the climate change
issue. This strategy includes activities such as:
*
energy conservation through improvements to overall system efficiency;
*
conducting research and development work designed to reduce greenhouse
gas emissions;
*
gaining experience with flexible market mechanisms;
*
participation in government-led policy forums; and
*
taking part in public awareness initiatives and education programs
focused on climate change and air quality issues.
In addition to these activities, TCPL also ensures that the potential business
risks and opportunities posed by increasing environmental priorities are
considered when making decisions regarding the company's businesses.
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 and those of the Canadian Securities
Administrators, 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.
During the period covered by this report, there has been no change in internal
control over financial reporting that has materially affected, or is reasonably
likely to materially affect, TCPL's internal control over financial reporting.
CEO and CFO Certifications
With respect to the year ending December 31, 2005, TCPL's President and Chief
Executive Officer has provided the New York Stock Exchange with 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 2005 reports filed with the SEC.
Compliance Expenditures
The total cost incurred by TCPL to meet compliance requirements of Sections 302,
404 and 906 of the Sarbanes-Oxley Act of 2002 for the period January 1, 2002 to
December 31, 2005, was estimated to be $9 million, including third party charges
of $3 million.
56 MANAGEMENT'S DISCUSSION AND ANALYSIS
CRITICAL ACCOUNTING POLICY
The company accounts for the impacts of rate regulation in accordance with
generally accepted accounting principles (GAAP) as outlined in Notes 1 and 12 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 as detailed in Note 12 to the consolidated financial statements.
As prescribed by the regulators, the taxes payable method of accounting for
income taxes is used for tollmaking purposes for Canadian regulated natural gas
transmission operations. As permitted by GAAP, this method is also used for
accounting purposes, since there is reasonable expectation that future income
taxes payable will be included in future costs of service and recorded in
revenues at that time. Consequently, future income tax liabilities have not been
recognized as it is expected that when these amounts become payable, they will
be recovered through future rate revenues. In the absence of rate regulation
accounting, GAAP would require the recognition of future income tax liabilities.
If the liability method of accounting had been used, additional future income
tax liabilities in the amount of $1,619 million at December 31, 2005 would have
been recorded.
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, 2005 was $1,017 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, where
applicable, and depreciation expense is 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.
ACCOUNTING CHANGES
Financial Instruments - Disclosure and Presentation
Effective January 1, 2005, the Company adopted the amendment of the Canadian
Institute of Chartered Accountants (CICA) to the existing Handbook Section
"Financial Instruments - Disclosure and Presentation" which provides 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. In accordance with this amendment, TCPL classified the
shareholders' equity component of preferred securities as long-term debt. This
change was applied retroactively with restatement of prior periods. See Note 2
to the consolidated financial statements for the impact of this accounting
change.
Disclosure by Entities Subject to Rate Regulation
In May 2005, the Accounting Standards Board (AcSB) issued Accounting Guideline
AcG-19 "Disclosures by Entities Subject to Rate Regulation" to improve the
quality and consistency of disclosures by entities subject to rate regulation.
MANAGEMENT'S DISCUSSION AND ANALYSIS 57
Under AcG-19, all rate regulated entities are required to disclose general
information about the rate-setting process, its accounting effects and the
operations affected. The new disclosure requirements were effective for fiscal
years ending on or after December 31, 2005. The company adopted these
requirements effective December 31, 2005. See Note 12 to the consolidated
financial statements for disclosures required under AcG-19.
Limited Partnerships
A wholly-owned subsidiary of TCPL serves as the general partner of PipeLines LP.
Effective December 31, 2005, TCPL consolidated limited partnerships when the
general partner controls the strategic operating, financing and investing
activities of the limited partnerships and the limited partners do not have
substantive participating rights. This change was applied retroactively with
restatement of prior periods. There was no impact on previously recorded net
income and the balance sheet and income statement impact was not material.
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 were
effective as of January 1, 2005. Adopting the provisions of this guideline had
no impact on the company's consolidated financial statements.
Non-Monetary Transactions
In June 2005, the AcSB issued the new Handbook Section 3831 "Non-Monetary
Transactions" replacing Section 3830 of the same title. The revised standard
requires all non-monetary transactions to be measured at fair value, subject to
certain exceptions. Commercial substance replaces culmination of the earnings
process as the test for fair value measurement and is a function of the cash
flows expected from the exchanged assets. The new requirements are effective for
non-monetary transactions initiated in periods beginning on or after January 1,
2006. Adopting the provisions of this standard is not expected to have an impact
on the company's consolidated financial statements.
Financial Instruments - Recognition and Measurement
In January 2005, the AcSB issued the new Handbook Section 3855 "Financial
Instruments - Recognition and Measurement" which prescribes that all financial
instruments within the scope of this standard, including derivatives, be
included on a company's balance sheet and measured, either at their fair value
or, in limited circumstances when fair value may not be considered most
relevant, at cost or amortized cost. It also specifies when gains and losses as
a result of changes in fair value are to be recognized in the income statement.
This standard is effective for interim and annual financial statements for
fiscal years beginning on or after October 1, 2006. This standard is
substantially similar to the corresponding requirements under Statement of
Financial Accounting Standards (SFAS) No. 115 "Accounting for Certain
Investments in Debt and Equity Securities" and SFAS No. 133 "Accounting for
Derivative Instruments and Hedging Activities" which were adopted by the company
for U.S. GAAP purposes, effective January 1, 2001. This new Handbook section
will be adopted by the company as of January 1, 2007 on a prospective basis.
TCPL does not expect the new Canadian requirement to have a significant impact
on the company's consolidated financial statements. See the company's
reconciliation to United States GAAP posted on www.sec.gov/edgar.shtml for the
impact of SFAS No. 133 on the company's consolidated financial statements.
Hedges
In January 2005, the AcSB issued the new Handbook Section 3865 "Hedges" which
specifies the circumstances under which hedge accounting is permissible, how
hedge accounting may be performed, and where the impacts should be recorded. The
provisions of this standard introduce three specific types of hedging
relationships: fair value hedges, cash flow hedges and hedges of a net
investment in self-sustaining foreign operations. This standard is effective for
interim and annual financial statements for fiscal years beginning on or after
October 1, 2006. The standard builds on existing Accounting Guideline AcG-13
"Hedging Relationships" which was adopted by TCPL effective January 1, 2004.
This new Handbook section will be adopted by the company as of January 1, 2007
on a prospective basis. TCPL does not expect the new requirement to have a
significant impact on the company's consolidated financial statements.
58 MANAGEMENT'S DISCUSSION AND ANALYSIS
Comprehensive Income
In January 2005, the AcSB issued the new Handbook Section 1530 "Comprehensive
Income" which requires that an enterprise present comprehensive income and its
components, in a separate financial statement that is displayed with the same
prominence as other financial statements. This Section introduces a new
requirement to present certain gains and losses temporarily outside net income.
This standard is effective for interim and annual financial statements for
fiscal years beginning on or after October 1, 2006. This standard is
substantially similar to the corresponding requirements under SFAS No. 130
"Reporting Comprehensive Income" and SFAS No. 133 "Accounting for Derivative
Instruments and Hedging Activities" which have already been adopted by the
company for U.S. GAAP purposes. This Handbook section will be adopted by the
company as of January 1, 2007 on a prospective basis. TCPL does not expect the
new Canadian requirement to have a significant impact on the company's
consolidated financial statements. See the company's reconciliation to United
States GAAP posted on www.sec.gov/edgar.shtml for the impact of SFAS No. 130 and
SFAS No. 133 on the company's consolidated financial statements.
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 Paiton Energy,
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. It is the intention of the company to continue with its
plan to dispose of these investments. Paiton Energy was sold in November 2005
and the gain on sale was recorded in the Power segment.
In 2005, the company reviewed the provision for loss on discontinued operations
and concluded that the provision was adequate.
In 2004 and 2003, the company recognized in income $52 million and $50 million,
respectively, related to the original $102 million after-tax deferred gain on
the sale of Gas Marketing.
MANAGEMENT'S DISCUSSION AND ANALYSIS 59
SUBSIDIARIES AND INVESTMENTS
TCPL and its subsidiaries and investments that hold significant operating assets
are noted below.
Subsidiary Investment Major Operating Assets Organized Effective
Under the Laws Percentage
of Ownership by TCPL
(1)
TransCanada PipeLines Limited Canadian Mainline and Canada 100
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
TransCanada Hydro Northeast Inc. TC Hydro Delaware 100
Gas Transmission Northwest Corporation GTN California 100
TransCanada Power Marketing Ltd. U.S. Power assets Delaware 100
Great Lakes Gas Transmission Limited Great Lakes Delaware 50
Partnership
Iroquois Gas Transmission System L.P. Iroquois Delaware 44.5
Portland Natural Gas Transmission System Portland Maine 61.7
Partnership
TC PipeLines, LP TC PipeLines, LP assets Delaware 13.4
Northern Border Pipeline Company Northern Border Texas 4
Tuscarora Gas Transmission Company Tuscarora Nevada 7.6
TransCanada Energy Ltd. Canadian Power assets Canada 100
Bruce Power A L.P. Bruce A Units 1 to 4 Ontario 47.9
Bruce Power L.P. Bruce B Units 5 to 8 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
(1)
Percentage ownership represents the effective common share ownership as at
December 31, 2005.
60 MANAGEMENT'S DISCUSSION AND ANALYSIS
SELECTED THREE YEAR CONSOLIDATED FINANCIAL DATA(1)
(millions of dollars except per share amounts)
2005 2004 2003
Income Statement
Revenues 6,124 5,497 5,636
Net income applicable to common shares
Continuing operations 1,208 978 801
Discontinued operations - 52 50
Total 1,208 1,030 851
Balance Sheet
Total assets 24,113 22,421 20,884
Long-term debt 9,640 9,749 9,516
Non-recourse debt of joint ventures 937 808 741
Preferred securities 536 554 598
Per Common Share Data
Net income - Basic and Diluted
Continuing operations $2.50 $2.03 $1.66
Discontinued operations - 0.11 0.11
$2.50 $2.14 $1.77
Dividends declared(2) $1.23 $1.17 $1.08
(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, Note 2 and Note 24 of
TCPL's 2005 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.
MANAGEMENT'S DISCUSSION AND ANALYSIS 61
SELECTED QUARTERLY CONSOLIDATED FINANCIAL DATA(1)
2005
(millions of dollars except per share amounts) Fourth Third Second First
Revenues 1,771 1,494 1,449 1,410
Net income applicable to common shares
Continuing operations 349 428 199 232
Discontinued operations - - - -
349 428 199 232
Per Common Share Data
Net income - Basic and Diluted
Continuing operations $0.72 $0.89 $0.41 $0.48
Discontinued operations - - - -
$0.72 $0.89 $0.41 $0.48
2004
Fourth Third Second First
Revenues 1,480 1,311 1,347 1,359
Net income applicable to common shares
Continuing operations 184 192 388 214
Discontinued operations - 52 - -
184 244 388 214
Per Common Share Data
Net income - 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
(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, Note 2 and Note 24 of
TCPL's 2005 audited consolidated financial statements.
62 MANAGEMENT'S DISCUSSION AND ANALYSIS
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 net earnings during
any particular fiscal year remain relatively 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 builds, owns and operates electrical power
generation plants and sells electricity, 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 2005 and 2004 quarterly net earnings are as
follows.
*
First quarter 2004 net earnings included approximately $12 million of
income tax refunds and related interest.
*
Second quarter 2004 net earnings included after-tax 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 Generic Cost of
Capital 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 carry forwards.
*
In fourth quarter 2004, TCPL completed the acquisition of GTN and
recorded $14 million of net 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.
*
In first quarter 2005, net earnings included a $48 million after-tax
gain related to the sale of PipeLines LP units. Power earnings included
a $10 million after-tax cost for the restructuring of natural gas supply
contracts by OSP. In addition, Bruce Power's equity income was lower
than previous quarters due to the impact of planned maintenance outages
and the increase in operating costs as a result of moving to a six-unit
operation.
*
Second quarter 2005 net earnings included $21 million ($13 million
related to 2004 and $8 million related to the six months ended June 30,
2005) with respect to the NEB's decision on the Canadian Mainline's 2004
Tolls and Tariff Application (Phase II). On April 1, 2005, TCPL
completed the acquisition of the TC Hydro hydroelectric generation
assets from USGen. Bruce Power's equity income was lower than previous
quarters due to the continuing impact of planned maintenance outages and
an unplanned maintenance outage on Unit 6 relating to a transformer
fire.
*
In third quarter 2005, net earnings included a $193 million after-tax
gain related to the sale of the company's ownership interest in Power
LP. In addition, Bruce Power's equity income increased from prior
quarters due to higher realized power prices and slightly higher
generation volumes.
*
In fourth quarter 2005, net earnings included a $115 million after-tax
gain on sale of Paiton Energy. In addition, Bruce A was formed and Bruce
Power's results were proportionately consolidated, effective October 31.
MANAGEMENT'S DISCUSSION AND ANALYSIS 63
FOURTH QUARTER 2005 HIGHLIGHTS
SEGMENT RESULTS-AT-A-GLANCE
Three months ended December 31 (millions of dollars)
2005 2004
Gas Transmission 160 157
Power
Excluding gains 82 31
Gain on sale of Paiton Energy 115 -
197 31
Corporate (8 ) (4 )
Net income applicable to common shares(1) 349 184
(1)Net income applicable to common shares
Excluding gain 234 184
Gain on sale of Paiton Energy 115 -
349 184
Net income applicable to common shares for fourth quarter 2005 of $349 million
increased by $165 million compared to $184 million for fourth quarter 2004. This
increase was due to significantly higher net earnings from the Power business,
including an after-tax gain of $115 million from the sale of Paiton Energy.
Excluding the $115 million gain related to the sale of Paiton Energy, net
earnings for fourth quarter 2005 increased $50 million compared to fourth
quarter 2004, to $234 million. This was due to increases of $51 million and $3
million in net earnings from the Power and Gas Transmission businesses,
respectively, partially offset by an increase of $4 million in net expenses in
Corporate.
The increase in Power's net earnings was primarily due to higher operating and
other income from Bruce Power and Eastern Operations. Bruce Power's contribution
to operating and other income increased by $48 million in fourth quarter 2005
compared to fourth quarter 2004, primarily due to higher realized power prices
on uncontracted volumes sold into Ontario's wholesale spot market, higher
generation volumes and an increased ownership interest in the Bruce A facilities
effective October 31, 2005.
Western Operations' operating and other income was $8 million higher in fourth
quarter 2005 compared to fourth quarter 2004 primarily due to increased margins
in fourth quarter 2005 as a result of higher market heat rates on uncontracted
volumes of power sold. Partially offsetting this increase were lower
contributions from the Bear Creek cogeneration facility which remained on an
unplanned outage throughout the quarter.
Eastern Operations' operating and other income was $37 million higher in fourth
quarter 2005 compared to fourth quarter 2004 primarily due to contributions from
TC Hydro, acquired on April 1, 2005, and from the Grandview cogeneration
facility placed into service in January 2005. Partially offsetting these
increases was a fourth quarter 2004 positive impact due to a restructuring
transaction relating to OSP power purchase contracts and the loss of operating
income associated with the expiration of certain long-term sales contracts in
2004.
General, administrative, support costs and other increased $9 million in fourth
quarter 2005 compared to fourth quarter 2004 primarily due to higher business
development costs expensed in 2005 and the positive impact in fourth quarter
2004 of the recognition of unrealized foreign exchange gains on Power LP's U.S.
dollar denominated debt.
64 MANAGEMENT'S DISCUSSION AND ANALYSIS
For fourth quarter 2005, Gas Transmission's net income was $160 million
compared to $157 million in fourth quarter 2004. The $3 million increase was due
to a $6 million increase in net income from the Other Gas Transmission
businesses partially offset by a $3 million reduction in income from
Wholly-Owned Pipelines. The reduction in income from Wholly-Owned Pipelines was
primarily due to a decline in the Canadian Mainline and the Alberta System net
income. These decreases were partially offset by higher net income during the
quarter from TCPL's investment in GTN which was acquired on November 1, 2004.
The increase in net income from Other Gas Transmission was primarily due to
lower project development costs expensed in fourth quarter 2005 resulting from
capitalization of costs of the Broadwater and Keystone projects in 2005 and
higher income from Gas Pacifico. These increases were partially offset by lower
income from Great Lakes and Ventures LP.
Net expenses, after tax, in Corporate for fourth quarter 2005 were $8 million
compared to $4 million for the corresponding period in 2004. The $4 million
increase in net expenses was primarily due to increased net interest costs
offset by an income tax refund received in fourth quarter 2005 relating to prior
years.
SHARE INFORMATION
As at February 27, 2006, TCPL had 483,344,109 issued and outstanding 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, 2005, 2004, 2003, 2002, 2001 and 2000 is found under the heading "Six-Year
Financial Highlights" on pages 107 and 108 of this report.
MANAGEMENT'S DISCUSSION AND ANALYSIS 65
GLOSSARY OF TERMS
AcSB Accounting Standards Board
APG Aboriginal Pipeline Group/Mackenzie Valley Aboriginal Pipeline Limited Partnership
Bcf Billion cubic feet
B.C. British Columbia
Bcf/d Billion cubic feet per day
Boston Edison Boston Edison Company
BPC BPC Generation Infrastructure Trust
Broadwater Broadwater Energy project
Bruce A Bruce Power A L.P.
Bruce B Bruce Power L.P.
Bruce Power Bruce A and Bruce B, collectively
Calpine Calpine Corporation and certain of its subsidiaries
Cameco Cameco Corporation
CAPP Canadian Association of Petroleum Producers
Cartier Wind Cartier Wind Energy
CBM Coalbed methane
CFE Comision Federal de Electricdad
CICA Canadian Institute of Chartered Accountants
CPPL ConocoPhillips Pipe Line Company
CrossAlta CrossAlta Gas Storage & Services Ltd.
DBRS Dominion Bond Rating Service Limited
Debentures Senior Unsecured Debentures
disclosure Disclosure controls and procedures
controls
EPCOR EPCOR Utilities Inc.
EUB Alberta Energy and Utilities Board
FERC Federal Energy Regulatory Commission
Foothills Foothills Pipe Lines Ltd.
FT Firm transportation
GAAP Generally accepted accounting principles
Gas Pacifico Gasoducto del Pacifico
GCOC Generic cost of capital
GJ Gigajoules
GRA General Rate Application
Great Lakes Great Lakes Gas Transmission System
GTN Gas Transmission Northwest System and the North Baja System, collectively
GTNC Gas Transmission Northwest Corporation
GUA Gas Utilities Act (Alberta)
GWh Gigawatt hours
Hydro-Quebec Hydro-Quebec Distribution
IID Imperial Irrigation District
INNERGY INNERGY Holdings S.A.
Iroquois Iroquois Gas Transmission System
Irving Irving Oil
Keystone Keystone oil pipeline
pipeline
km Kilometres
LNG Liquefied natural gas
Millennium Millennium Pipeline Project
mmcf/d Million cubic feet per day
Moody's Moody's Investors Service
MOU Memorandum of Understanding
MW Megawatt
MWh Megawatt hour
NEB National Energy Board
Net earnings Net income from continuing operations
Northern Northern Border Pipeline Company
Border
NPA Northern Pipeline Act
OM&A Operating, maintenance and administration
OPA Ontario Power Authority
OSP Ocean State Power
PG&E Pacific Gas & Electric Company
Paiton Energy P.T. Paiton Energy Company
PipeLines LP TC PipeLines, LP
PJ Petajoules
Portland Portland Natural Gas Transmission System
Portlands Portlands Energy Centre L.P.
Energy
Power LP TransCanada Power, L.P.
PPA Power purchase arrangement
ROE Rate of return on common equity
SFAS Statement of Financial Accounting Standards
Shell Shell US Gas & Power LLC
STFT Short-term firm transportation service
TC Hydro Hydroelectric generation assets acquired from USGen
Tcf Trillion cubic feet
TCPL or the TransCanada PipeLines Limited
company
TCPM TransCanada Power Marketing Limited
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
WCSB Western Canada Sedimentary Basin
66 MANAGEMENT'S DISCUSSION AND ANALYSIS
Report of The consolidated financial statements included in this report are the
Management 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 2005
to 2004 and should be read in conjunction with the consolidated
financial statements and accompanying notes. In addition, significant
changes between 2004 and 2003 are highlighted.
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 68
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 27, 2006
TRANSCANADA PIPELINES LIMITED 67
Auditors' To the Shareholder of TransCanada PipeLines Limited
Report
We have audited the consolidated balance sheets of TransCanada PipeLines
Limited as at December 31, 2005 and 2004 and the consolidated statements
of income, retained earnings and cash flows for each of the years in the
three-year period ended December 31, 2005. 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, 2005 and 2004 and the results of its operations and its
cash flows for each of the years in the three-year period ended December
31, 2005 in accordance with Canadian generally accepted accounting
principles.
Chartered Accountants
Calgary, Canada
February 27, 2006
TransCanada
PipeLines Limited
68 CONSOLIDATED FINANCIAL STATEMENTS
TRANSCANADA PIPELINES LIMITED
CONSOLIDATED INCOME
Year ended December 31 2005 2004 2003
(millions of dollars)
Revenues 6,124 5,497 5,636
Operating Expenses
Cost of sales 1,168 940 979
Other costs and expenses 1,889 1,615 1,666
Depreciation 1,017 948 917
4,074 3,503 3,562
Operating Income 2,050 1,994 2,074
Other Expenses/(Income)
Financial charges (Note 9) 837 860 878
Financial charges of joint ventures (Note 10) 66 63 80
Equity income (Note 7) (247 ) (213 ) (206 )
Interest income and other (63 ) (59 ) (60 )
Gains on sale of assets (Note 8) (445 ) (204 ) -
148 447 692
Income from Continuing Operations before Income Taxes 1,902 1,547 1,382
and Non-Controlling Interests
Income Taxes (Note 18)
Current 550 414 284
Future 60 77 230
610 491 514
Non-Controlling Interests (Note 14) 62 56 45
Net Income from Continuing Operations 1,230 1,000 823
Net Income from Discontinued Operations (Note 24) - 52 50
Net Income 1,230 1,052 873
Preferred Share Dividends 22 22 22
Net Income Applicable to Common Shares 1,208 1,030 851
Net Income Applicable to Common Shares
Continuing operations 1,208 978 801
Discontinued operations - 52 50
1,208 1,030 851
The accompanying notes to the consolidated financial statements are an integral
part of these statements.
CONSOLIDATED FINANCIAL STATEMENTS 69
TRANSCANADA PIPELINES LIMITED
CONSOLIDATED CASH FLOWS
Year ended December 31 2005 2004 2003
(millions of dollars)
Cash Generated from Operations
Net income from continuing operations 1,230 1,000 823
Depreciation 1,017 948 917
Gains on sale of assets, net of current tax (Note 8) (318 ) (204 ) -
Equity income in excess of distributions received (Note (71 ) (113 ) (117 )
7)
Future income taxes 60 77 230
Non-controlling interests 62 56 45
Funding of employee future benefits in excess of (9 ) (29 ) (65 )
expense
Other (21 ) (34 ) (11 )
Funds generated from operations 1,950 1,701 1,822
(Increase)/decrease in operating working capital (Note (48 ) 28 93
22)
Net cash provided by operations 1,902 1,729 1,915
Investing Activities
Capital expenditures (754 ) (530 ) (395 )
Acquisitions, net of cash acquired (Note 8) (1,317 ) (1,516 ) (570 )
Disposition of assets, net of current tax (Note 8) 671 410 -
Deferred amounts and other 65 (12 ) (131 )
Net cash used in investing activities (1,335 ) (1,648 ) (1,096 )
Financing Activities
Dividends on common and preferred shares (608 ) (574 ) (532 )
Distributions paid to non-controlling interests (52 ) (65 ) (57 )
Advances from parent (36 ) 35 46
Notes payable issued/(repaid), net 416 179 (62 )
Long-term debt issued 799 1,090 930
Reduction of long-term debt (1,113 ) (1,005 ) (753 )
Long-term debt of joint ventures issued 38 217 60
Reduction of long-term debt of joint ventures (80 ) (112 ) (72 )
Common shares issued (Note 16) 80 - 18
Partnership units of joint ventures issued - 88 -
Redemption of junior subordinated debentures - - (218 )
Net cash used in financing activities (556 ) (147 ) (640 )
Effect of Foreign Exchange Rate Changes on Cash and 11 (87 ) (54 )
Short-Term Investments
Increase/(Decrease) in Cash and Short-Term Investments 22 (153 ) 125
Cash and Short-Term Investments
Beginning of year 190 343 218
Cash and Short-Term Investments
End of year 212 190 343
The accompanying notes to the consolidated financial statements are an integral
part of these statements.
70 CONSOLIDATED FINANCIAL STATEMENTS
TRANSCANADA PIPELINES LIMITED
CONSOLIDATED BALANCE SHEET
December 31 2005 2004
(millions of dollars)
ASSETS
Current Assets
Cash and short-term investments 212 190
Accounts receivable 796 616
Inventories 281 174
Other 277 120
1,566 1,100
Long-Term Investments (Note 7) 400 1,098
Plant, Property and Equipment (Notes 4, 9 and 10) 20,038 18,764
Other Assets (Note 5) 2,109 1,459
24,113 22,421
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Notes payable (Note 19) 962 546
Accounts payable 1,536 1,215
Accrued interest 222 214
Current portion of long-term debt (Note 9) 393 774
Current portion of long-term debt of joint ventures (Note 10) 41 85
3,154 2,834
Deferred Amounts (Note 11) 1,196 783
Future Income Taxes (Note 18) 703 509
Long-Term Debt (Note 9) 9,640 9,749
Long-Term Debt of Joint Ventures (Note 10) 937 808
Preferred Securities (Note 13) 536 554
16,166 15,237
Non-Controlling Interests (Note 14) 394 311
Shareholders' Equity
Preferred shares (Note 15) 389 389
Common shares (Note 16) 4,712 4,632
Contributed surplus 275 270
Retained earnings 2,267 1,653
Foreign exchange adjustment (Note 17) (90 ) (71 )
7,553 6,873
Commitments, Contingencies and Guarantees (Note 23)
24,113 22,421
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
CONSOLIDATED FINANCIAL STATEMENTS 71
TRANSCANADA PIPELINES LIMITED
CONSOLIDATED RETAINED EARNINGS
Year ended December 31 2005 2004 2003
(millions of dollars)
Balance at beginning of year 1,653 1,185 854
Net income 1,208 1,052 873
Preferred share dividends (22 ) (22 ) (22 )
Common share dividends (572 ) (562 ) (520 )
2,267 1,653 1,185
The accompanying notes to the consolidated financial statements are an integral
part of these statements.
72 CONSOLIDATED FINANCIAL STATEMENTS
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./United States border and to the Saskatchewan/ U.S. border (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 North America.
In addition, Gas Transmission investigates and develops new natural gas and
crude oil transmission, natural gas storage and liquefied natural gas
regasification facilities in North America.
Power
The Power segment builds, owns and operates electrical power generation plants,
and sells electricity. Power also holds the Company's investments in other
electrical power generation plants. This business operates in Canada and the
U.S. as follows:
TCPL owns and operates:
*
hydroelectric generation assets located in New Hampshire, Vermont and
Massachusetts (TC Hydro);
*
a natural gas-fired, combined-cycle Ocean State Power (OSP) plant in
Burrillville, Rhode Island;
*
natural gas-fired cogeneration plants in Alberta at Carseland, Redwater,
Bear Creek and MacKay River;
*
the Grandview natural gas-fired cogeneration plant near Saint John, New
Brunswick; and
*
a waste-heat fuelled cogeneration power plant at the Cancarb facility in
Medicine Hat, Alberta.
TCPL owns but does not operate:
*
a 47.9 per cent partnership interest and a 31.6 per cent partnership
interest in the nuclear power generation facilities of Bruce Power A
L.P. (Bruce A) and Bruce Power L.P. (Bruce B), respectively
(collectively Bruce Power), located near Lake Huron, Ontario.
TCPL has long-term power purchase arrangements (PPAs) in place for:
*
100 per cent of the production of the Sundance A and 50 per cent,
through a partnership, of the production of the Sundance B power
facilities near Wabamun, Alberta; and
*
100 per cent of the production of the Sheerness power facility near
Hanna, Alberta.
TCPL has under construction:
*
the Becancour natural gas-fired cogeneration plant near Trois-Rivieres,
Quebec; and
*
six Cartier Wind Energy projects in Quebec, owned 62 per cent by
TransCanada.
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). Amounts are stated in Canadian dollars unless otherwise indicated.
Certain comparative figures have been reclassified to conform with the current
year's presentation.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 73
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
The consolidated financial statements include the accounts of TransCanada
PipeLines Limited and its subsidiaries as well as its proportionate share of the
accounts of its joint ventures. 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). 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).
These natural gas transmission operations are regulated with respect to the
determination of revenues, tolls, construction and operations. 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. The impact of rate regulation on TCPL is provided in Note 12.
Revenue Recognition
Gas Transmission
In the Gas Transmission business, revenues from the Canadian rate-regulated
operations are recognized in accordance with the decisions made by the NEB and
EUB. Revenues from the U.S. rate-regulated operations are recorded in accordance
with FERC rules and regulations. Revenues from non-regulated operations are
recorded when products have been delivered or services have been performed.
Power
The majority of revenues from the Power business are derived from the sale of
electricity from energy marketing and trading activities and are recorded in the
month of delivery. Revenues from the Power business are also derived from the
sale of unutilized natural gas fuel and energy derivative contracts, including
financial swaps, futures contracts and options.
Dilution Gains
Dilution gains which result from the sale of units by limited partnerships in
which TCPL has an ownership interest are recognized immediately in net income.
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 consisting of natural gas in storage, uranium, materials and
supplies, including spare parts, are carried at the lower of average cost or net
realizable value.
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.
74 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Power
Major power generation plant, equipment and structures in the Power business are
recorded at cost and depreciated on a straight-line basis over estimated service
lives at average annual rates ranging from two to ten per cent. Nuclear assets
under capital lease are initially recorded at the present value of minimum lease
payments at the inception of the lease and amortized on a straight-line basis
over the shorter of their useful life or remaining lease term. Other equipment
is depreciated at various rates. The cost of major overhauls of equipment is
capitalized and depreciated over the estimated service lives. Interest is
capitalized on projects under construction.
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
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 ten
to 19 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 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
the time payable. The liability method of accounting for income taxes is used
for the remainder of the Company's operations. Under this method, future tax
assets and liabilities are recognized for the future tax consequences
attributable to differences between the financial statement carrying amounts of
existing assets and liabilities and their respective tax bases. Future income
tax assets and liabilities are measured using enacted or substantively enacted
tax rates expected to apply to taxable income in the years in which temporary
differences are expected to be recovered or settled. Changes to these balances
are recognized in income in the period in which they occur.
Canadian income taxes are not provided on the unremitted earnings of foreign
investments which the Company does not intend to repatriate in the foreseeable
future.
Foreign Currency Translation
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.
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 and Hedging Activities
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.
Derivatives and other instruments must be designated and effective to qualify
for hedge accounting. Derivatives are recorded at their fair value at each
balance sheet date. For cash flow and fair value hedges, gains or losses
relating to derivatives are deferred and recognized in the same period and in
the same financial statement category as the corresponding hedged transactions.
For hedges of net investments in self-sustaining foreign operations, exchange
gains or losses on derivatives, net of tax, and designated foreign currency
denominated debt are offset against the exchange losses or gains arising on the
translation of the financial statements of the foreign operations included in
the foreign exchange adjustment account in Shareholders' Equity. In the event
that a derivative does not meet the designation or effectiveness criteria,
realized and unrealized gains or losses are recognized in income each period in
the same financial statement category as the underlying transaction giving rise
to the exposure being economically hedged. Premiums paid or received with
respect to derivatives that are hedges are deferred and amortized to income over
the term of the hedge.
If a derivative that previously qualified as a hedge is settled, de-designated
or ceases to be effective, the gain or loss at that date is deferred and
recognized in the same period and in the same financial statement category as
the corresponding hedged transactions. If a hedged anticipated transaction is no
longer probable to occur, related deferred gains or losses are recognized in
income in the current period.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 75
The recognition of gains and losses on derivatives for Canadian Mainline,
Alberta System, the BC System and the Foothills System exposures is determined
through the regulatory process.
Asset Retirement Obligation
The Company recognizes the fair value of a liability for an asset retirement
obligation, where a legal obligation exists, 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 and the liability is
accreted at the end of each period through charges to operating expenses.
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 has broad-based, medium-term employee incentive plans, which grant
units to each eligible employee and are payable in cash at the date of vesting.
The expense related to these incentive plans is accounted for on an accrual
basis. Under these plans, units vest when certain conditions are met, including
the employee's continued employment during a specified period and achievement of
specified corporate performance targets.
Certain of the Company's joint ventures sponsor DB Plans and other
post-employment benefit plans. The Company records its proportionate share of
expenses, funding contributions and accrued benefit assets and liabilities
related to these plans.
NOTE 2 ACCOUNTING CHANGES
Financial Instruments-Disclosure and Presentation
Effective January 1, 2005, the Company adopted the amendment of the Canadian
Institute of Chartered Accountants (CICA) to the existing Handbook Section
"Financial Instruments-Disclosure and Presentation", which provides guidance for
classifying certain financial instruments that embody obligations that may be
settled by issuance of the issuer's equity shares as debt when the instrument
does not establish an ownership relationship. In accordance with this amendment,
TCPL reclassified the Shareholders' Equity component of preferred securities as
long-term debt.
This accounting change was applied retroactively with restatement of prior
periods. The impact of this change on TCPL's net income in prior years was nil.
The impact of the accounting change on the Company's consolidated balance sheet
as at December 31, 2004 is as follows.
(millions of dollars) Increase/(Decrease )
Deferred amounts(1) 135
Preferred securities 535
Shareholders' Equity
Preferred securities (670 )
Total liabilities and shareholders' equity -
(1)
Regulatory deferral.
Limited Partnerships
A wholly-owned subsidiary of TCPL serves as the general partner of TC PipeLines,
LP (PipeLines LP). Effective December 31, 2005, TransCanada consolidated
limited partnerships when the general partner controls the strategic operating,
financing and investing activities of the limited partnerships and the limited
partners do not have substantive participating rights. This change was applied
retroactively. There was no impact on previously recorded net income and the
balance sheet and income statement impact was not material.
76 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 3 SEGMENTED INFORMATION
NET INCOME/(LOSS)(1)
Year ended December 31, 2005 (millions of Gas Power Corporate Total
dollars) Transmission
Revenues 4,163 1,961 - 6,124
Cost of sales(2) - (1,168 ) - (1,168 )
Other costs and expenses (1,380 ) (505 ) (4 ) (1,889 )
Depreciation (938 ) (79 ) - (1,017 )
Operating income/(loss) 1,845 209 (4 ) 2,050
Financial and preferred equity charges and (788 ) (2 ) (131 ) (921 )
non-controlling interests
Financial charges of joint ventures (57 ) (9 ) - (66 )
Equity income 79 168 - 247
Interest income and other 25 5 33 63
Gains on sale of assets 82 363 - 445
Income taxes (502 ) (173 ) 65 (610 )
Continuing operations 684 561 (37 ) 1,208
Discontinued operations -
Net Income Applicable to Common Shares 1,208
Year ended December 31, 2004 (millions of
dollars)
Revenues 3,929 1,568 - 5,497
Cost of sales(2) - (940 ) - (940 )
Other costs and expenses (1,228 ) (384 ) (3 ) (1,615 )
Depreciation (876 ) (72 ) - (948 )
Operating income/(loss) 1,825 172 (3 ) 1,994
Financial and preferred equity charges and (848 ) (9 ) (81 ) (938 )
non-controlling interests
Financial charges of joint ventures (59 ) (4 ) - (63 )
Equity income 83 130 - 213
Interest income and other 8 14 37 59
Gains on sale of assets 7 197 - 204
Income taxes (430 ) (104 ) 43 (491 )
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 3,968 1,668 - 5,636
Cost of sales(2) - (979 ) - (979 )
Other costs and expenses (1,274 ) (385 ) (7 ) (1,666 )
Depreciation (834 ) (82 ) (1 ) (917 )
Operating income/(loss) 1,860 222 (8 ) 2,074
Financial and preferred equity charges and (845 ) (11 ) (89 ) (945 )
non-controlling interests
Financial charges of joint ventures (79 ) (1 ) - (80 )
Equity income 107 99 - 206
Interest income and other 17 14 29 60
Income taxes (438 ) (103 ) 27 (514 )
Continuing operations 622 220 (41 ) 801
Discontinued operations 50
Net Income Applicable to Common Shares 851
(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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 77
TOTAL ASSETS
December 31 (millions of dollars) 2005 2004
Gas Transmission 18,252 18,720
Power 4,923 2,802
Corporate 938 899
24,113 22,421
GEOGRAPHIC INFORMATION
Year ended December 31 (millions of dollars) 2005 2004 2003
Revenues(3)
Canada - domestic 3,499 3,214 3,324
Canada - export 1,160 1,261 1,293
United States 1,465 1,022 1,019
6,124 5,497 5,636
(3)
Revenues are attributed to countries based on country of origin of product
or service.
PLANT, PROPERTY AND EQUIPMENT
December 31 (millions of dollars) 2005 2004
Canada 15,647 14,757
United States 4,306 4,007
Mexico 85 -
20,038 18,764
CAPITAL EXPENDITURES
Year ended December 31 (millions of dollars) 2005 2004 2003
Gas Transmission 377 241 260
Power 373 285 132
Corporate 4 4 3
754 530 395
78 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 4 PLANT, PROPERTY AND EQUIPMENT
2005 2004
December 31 (millions Accumulated Net Book Accumulated Net Book
of dollars) Cost Depreciation Value Cost Depreciation Value
Gas Transmission
Canadian Mainline
Pipeline 8,701 3,665 5,036 8,695 3,421 5,274
Compression 3,341 1,066 2,275 3,322 947 2,375
Metering and other 359 134 225 366 125 241
12,401 4,865 7,536 12,383 4,493 7,890
Under construction 15 - 15 16 - 16
12,416 4,865 7,551 12,399 4,493 7,906
Alberta System
Pipeline 5,020 2,203 2,817 4,978 2,055 2,923
Compression 1,493 676 817 1,496 599 897
Metering and other 799 247 552 861 262 599
7,312 3,126 4,186 7,335 2,916 4,419
Under construction 25 - 25 20 - 20
7,337 3,126 4,211 7,355 2,916 4,439
GTN(1)
Pipeline 1,381 60 1,321 1,417 8 1,409
Compression 507 15 492 526 2 524
Metering and other 90 - 90 101 2 99
1,978 75 1,903 2,044 12 2,032
Under construction 18 - 18 17 - 17
1,996 75 1,921 2,061 12 2,049
Foothills System
Pipeline 815 377 438 815 346 469
Compression 373 128 245 373 114 259
Metering and other 75 31 44 78 35 43
1,263 536 727 1,266 495 771
Joint Ventures and 3,491 1,127 2,364 3,293 1,073 2,220
other(2)
26,503 9,729 16,774 26,374 8,989 17,385
Power(3)
Nuclear(4) 1,265 143 1,122
Natural gas 1,121 347 774 1,333 374 959
Hydro 598 9 589 61 1 60
Other 67 36 31 67 32 35
3,051 535 2,516 1,461 407 1,054
Under construction 721 - 721 288 - 288
3,772 535 3,237 1,749 407 1,342
Corporate 73 46 27 124 87 37
30,348 10,310 20,038 28,247 9,483 18,764
(1)
Gas Transmission Northwest System and North Baja System (collectively GTN).
(2)
The December 31, 2005 net book value includes $235 million of plant,
property and equipment under construction (2004 - $20 million).
(3)
Certain Power generation facilities are accounted for as assets under
operating leases. At December 31, 2005, the net book value of these
facilities was $87 million (2004 - $70 million). In 2005, revenues of $23
million (2004 - $7 million) were recognized through the sale of electricity
under the related PPAs.
(4)
Assets under capital lease relating to Bruce Power. The Company
proportionately consolidated its ownership interest in Bruce Power, on a
prospective basis, effective October 31, 2005.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 79
NOTE 5 OTHER ASSETS
December 31 (millions of dollars) 2005 2004
Derivative contracts 209 180
Hedging deferrals 118 50
PPAs - Canada(1) 825 274
PPAs - U.S.(1) - 98
Pension and other benefit plans 304 253
Regulatory assets 183 174
Loans and advances(2) 91 135
Goodwill 57 58
Debt issue costs 48 50
Other 274 187
2,109 1,459
(1)
The following amounts related to the PPAs are included in the consolidated
financial statements.
2005 2004
December 31 Accumulated Net Book Accumulated Net Book
(millions of Cost Amortization Value Cost Amortization Value
dollars)
PPAs - Canada 915 90 825 345 71 274
PPAs - U.S. - - - 102 4 98
The
aggregate amortization expense with respect to the PPAs was $24 million for
the year ended December 31, 2005 (2004 - $24 million; 2003 - $37 million).
The amortization expense with respect to the PPAs approximates: 2006 - $58
million; 2007 - $58 million; 2008 - $58 million; 2009 - $58 million; and
2010 - $58 million. In August 2005, the Company sold TransCanada Power, L.P.
(Power LP), which included 100 per cent of the PPAs - U.S. Effective
December 31, 2005, the Company acquired the remaining rights and obligations
for the remaining 15 years of the Sheerness PPA for $585 million.
(2)
The December 31, 2004 balance includes a $75 million unsecured note
receivable from Bruce B bearing interest at 10.5 per cent per annum, due
February 14, 2008. Effective October 31, 2005, the Company proportionately
consolidated its investment in Bruce B and this balance is eliminated upon
consolidation. The December 31, 2005 balance includes an $87 million loan
(2004 - $60 million) to the Aboriginal Pipeline Group (APG) to finance the
APG for its one-third share of project development costs related to the
Mackenzie Gas Pipeline Project.
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 2005 2004 2003 2005 2004
Interest
Gas Transmission
Great Lakes 50.0% (1) 73 86 81 375 379
Iroquois 44.5% (1) 29 28 31 190 175
(2)
Trans Quebec & Maritimes 50.0% 13 13 14 73 75
CrossAlta 60.0% (1) 31 20 11 30 24
Foothills (3) - - 19 - -
Other Various 15 12 12 67 67
Power
Bruce A 47.9% (4) 19 563
Bruce B 31.6% (4) 5 434
ASTC Power Partnership 50.0% (5) - - - 88 93
Power LP (6) 25 32 25 - 289
210 191 193 1,820 1,102
(1)
Great Lakes Gas Transmission Limited Partnership (Great Lakes); Iroquois Gas
Transmission System, L.P. (Iroquois); CrossAlta Gas Storage & Services Ltd.
(CrossAlta).
80 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(2)
In June 2005, the Company acquired an additional 3.5 per cent ownership
interest in Iroquois.
(3)
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.
(4)
TCPL acquired a 47.4 per cent ownership interest in Bruce A on October 31,
2005 and a 31.6 per cent ownership interest in Bruce B in February 2003. The
Company increased its ownership interest in Bruce A to 47.9 per cent during
the remainder of 2005 as a result of certain other partners not
participating in capital contributions to Bruce A. The Company
proportionately consolidated its investments in Bruce A and Bruce B, on a
prospective basis, effective October 31, 2005.
(5)
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 TransCanada.
(6)
In April 2004, the Company's interest in Power LP decreased to 30.6 per cent
from 35.6 per cent. In August 2005, the Company sold its 30.6 per cent
interest in Power LP.
Consolidated retained earnings at December 31, 2005 include undistributed
earnings from these joint ventures of $765 million (2004 - $473 million).
Summarized Financial Information of Joint Ventures
Year ended December 31 (millions of dollars) 2005 2004 2003
Income
Revenues 687 572 635
Other costs and expenses (328 ) (240 ) (278 )
Depreciation (93 ) (90 ) (98 )
Financial charges and other (56 ) (51 ) (66 )
Proportionate share of income before income taxes of joint ventures 210 191 193
Year ended December 31 (millions of dollars) 2005 2004 2003
Cash Flows
Operations 346 270 259
Investing activities (133 ) (287 ) (139 )
Financing activities(1) (152 ) 35 (115 )
Effect of foreign exchange rate changes on cash and short-term (1 ) (5 ) (12 )
investments
Proportionate share of increase/(decrease) in cash and short-term 60 13 (7 )
investments of joint ventures
(1)
Financing activities include cash outflows resulting from distributions paid
to TCPL of $201 million (2004 - $158 million; 2003 - $103 million), and cash
inflows resulting from capital contributions paid by TCPL of $92 million
(2004 and 2003 - nil).
December 31 (millions of dollars) 2005 2004
Balance Sheet
Cash and short-term investments 123 63
Other current assets 281 122
Plant, property and equipment 2,707 1,708
Current liabilities (291 ) (155 )
(Deferred amounts)/other assets (net) (45 ) 221
Long-term debt of joint ventures (937 ) (808 )
Future income taxes (18 ) (49 )
Proportionate share of net assets of joint ventures 1,820 1,102
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 81
NOTE 7 LONG-TERM INVESTMENTS
TCPL's Share
Distributions from Equity Income from Equity Equity
Investments Investments Investments
Year Ended December 31 Year Ended December 31 December 31
(millions of Ownership 2005 2004 2003 2005 2004 2003 2005 2004
dollars) Interest
Gas Transmission
Northern Border (1) 76 79 65 61 65 63 315 349
TransGas 46.5% (2) 6 8 8 11 11 27 62 78
Portland 61.7% (3) - - 10 - - 14 - -
Other Various 10 13 6 7 7 3 23 29
Power
Bruce B 31.6% (4) 84 - - 168 130 99 - 642
176 100 89 247 213 206 400 1,098
(1)
The Company consolidates PipeLines LP, which holds a 30.0 per cent interest
in Northern Border Pipeline Company (Northern Border). The amounts presented
represent a 30.0 per cent interest, however, the Company's effective
ownership interest in Northern Border, net of non-controlling interests, is
4.0 per cent as a result of the Company holding a 13.4 per cent interest in
PipeLines LP. The Company's effective ownership interest in Northern Border
was reduced from 10.0 per cent to 4.0 per cent in a series of transactions
related to PipeLines LP in March and April 2005.
(2)
TransGas de Occidente S.A. (TransGas).
(3)
In September 2003, the Company increased its ownership interest in Portland
Natural Gas Transmission System Partnership (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.
(4)
The Company proportionately consolidated its 31.6 per cent ownership
interest in Bruce B, on a prospective basis, effective October 31, 2005.
Consolidated retained earnings at December 31, 2005 include undistributed
earnings from these equity investments of $55 million (2004 - $294 million).
NOTE 8 ACQUISITIONS AND DISPOSITIONS
Acquisitions
Sheerness PPA
Effective December 31, 2005, TCPL acquired the remaining rights and obligations
of the Sheerness PPA from the Alberta Balancing Pool for $585 million. There is
approximately a 15 year term remaining on the PPA.
Bruce Power
In February 2003, the Company acquired a 31.6 per cent partnership interest in
Bruce B for $409 million, which at that time owned the currently idle Bruce A
Units 1 and 2 as well as the currently operating Bruce A Units 3 and 4 and Bruce
B Units 5 to 8. The Company accounted for this as an equity investment. On
October 31, 2005, as part of an agreement to restart the currently idle Bruce A
Units 1 and 2, TCPL acquired a partnership interest in a newly created
partnership, Bruce A, which subleased the Bruce A Units 1 to 4 from Bruce B (the
Bruce A Sublease) and purchased certain other related assets. TCPL incurred a
net cash outlay of $100 million as a result of this transaction and as at
December 31, 2005 held a 47.9 per cent interest in Bruce A. As part of this
reorganization, both Bruce A and Bruce B became jointly controlled entities and
TCPL commenced proportionately consolidating its investments in both Bruce A and
Bruce B, on a prospective basis, effective October 31, 2005.
TC Hydro
In April 2005, TCPL acquired certain hydroelectric generation assets from USGen
New England, Inc. for approximately US$503 million. Substantially all of the
purchase price was allocated to plant, property and equipment. The financial
results from these assets have been included in the Power segment as of the date
of acquisition.
82 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
GTN
In November 2004, TCPL acquired GTN for US$1,728 million, including US$528
million of assumed debt and closing adjustments. The purchase price was
allocated as follows using fair values of the net assets at the date of
acquisition.
Purchase Price Allocation
(millions of U.S. dollars)
Current assets 40
Plant, property and equipment 1,718
Other non-current assets 21
Goodwill 48
Current liabilities (48 )
Long-term debt (528 )
Other non-current liabilities (51 )
1,200
Goodwill, which is attributable to the North Baja System, is re-evaluated on an
annual basis for impairment. Factors that contributed to goodwill include
opportunities for expansion, a strong competitive position, strong demand for
natural gas in the western markets and access to an ample supply of relatively
low-cost natural gas. The goodwill recognized on this transaction is being
amortized for tax purposes over 15 years.
The acquisition was accounted for using the purchase method of accounting. The
financial results of GTN were consolidated with those of TCPL subsequent to the
acquisition date and included in the Gas Transmission segment.
Dispositions
The pre-tax gains on sale of assets are comprised of the following.
Year ended December 31 (millions of dollars) 2005 2004
Gains related to Power LP 245 197
Gain on sale of Paiton Energy(1) 118 -
Gain on sale of PipeLines LP units 82 -
Gain on sale of Millennium(1) - 7
445 204
(1)
PT Paiton Energy Company (Paiton Energy); Millennium Pipeline project
(Millennium).
Power LP
In August 2005, TCPL sold its ownership interest in Power LP to EPCOR Utilities
Inc. (EPCOR) for net proceeds of $523 million and realized an after-tax gain of
$193 million. The net gain was recorded in the Power segment and the Company
recorded a $52 million income tax charge, including $79 million of current
income tax expense, on this transaction. The book value of Power LP's assets and
liabilities disposed of under this sale were $452 million and $174 million,
respectively. EPCOR's acquisition included 14.5 million limited partnership
units of Power LP, representing 30.6 per cent of the outstanding units; 100 per
cent ownership of the general partner of Power LP; and the management and
operations agreements governing the ongoing operation of Power LP's generation
assets.
In April 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 an after-tax gain on sale of $15 million. The net gain was recorded
in the Power segment and the Company recorded a $10 million income tax charge.
At a special meeting held in April 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
eliminated 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.
Paiton Energy
In November 2005, TCPL sold its approximate 11 per cent ownership interest in
Paiton Energy to subsidiaries of The Tokyo Electric Power Company for gross
proceeds of US$103 million ($122 million). The book value of Paiton Energy at
the time of sale was nil and TCPL realized an after-tax gain on sale of $115
million. The net gain was recorded in the Power segment and the Company recorded
a $3 million income tax charge, including $3 million of current income tax
recovery.
PipeLines LP
In March and April 2005, TCPL sold 3,574,200 common units of PipeLines LP for
net proceeds of $153 million and recorded an after-tax gain of $49 million. The
net gain was recorded in the Gas Transmission segment and the company recorded a
$33 million income tax charge, including $51 million of current income tax
expense, on this transaction. Subsequent to these transactions, TCPL continues
to own a 13.4 per cent interest in PipeLines LP represented by a general partner
interest of 2.0 per cent and an 11.4 per cent limited partner interest.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 83
NOTE 9 LONG-TERM DEBT
2005 2004
Weighted Weighted
Average Average
Outstanding Interest Outstanding Interest
Maturity Dates December 31(1) Rate(2) December 31(1) Rate(2)
CANADIAN MAINLINE(4)
First Mortgage Pipe Line Bonds
Pounds Sterling (2005 and 2007 50 16.5% 58 16.5%
2004 - #25)
Debentures
Canadian dollars 2008 to 2020 1,354 10.9% 1,354 10.9%
U.S. dollars (2005 and 2004 2012 to 2021 702 9.5% 722 9.5%
- US$600)(3)
Medium-Term Notes
Canadian dollars 2006 to 2031 1,987 7.1% 2,167 6.9%
U.S. dollars (2005 and 2004 2010 140 6.1% 144 6.1%
- US$120)
4,233 4,445
ALBERTA SYSTEM(5)
Debentures and Notes
Canadian dollars 2007 to 2024 585 11.6% 607 11.6%
U.S. dollars (2005 and 2004 2012 to 2023 437 8.2% 451 8.2%
- US$375)
Medium-Term Notes
Canadian dollars 2006 to 2030 964 6.6% 767 7.4%
U.S. dollars (2005 and 2004 2026 to 2029 272 7.7% 280 7.7%
- US$233)
2,258 2,105
GTN(6)
Unsecured Debentures and Notes 2010 to 2035 466 5.3% 632 7.2%
(2005 - US$400; 2004 - US$525)
FOOTHILLS SYSTEM(4)
Senior Unsecured Notes 2009 to 2014 400 4.9% 400 4.9%
PORTLAND(7)
Senior Secured Notes
U.S. dollars (2005 - 2018 281 5.9% 308 5.9%
US$241; 2004 - US$256)
OTHER
Medium-Term Notes(4)
Canadian dollars 2014 to 2030 542 5.9% 592 6.2%
U.S. dollars (2005 and 2004 2006 to 2025 607 6.9% 627 6.9%
- US$521)
Subordinated Debentures(4)
U.S. dollars (2005 and 2004 2006 66 9.1% 68 9.1%
- US$57)
Unsecured Loans, Debentures
and Notes(3)(8)
U.S. dollars (2005 - 2006 to 2034 1,180 4.8% 1,346 5.0%
US$1,014; 2004 - US$1,119)
2,395 2,633
10,033 10,523
Less: Current Portion of 393 774
Long-Term Debt
9,640 9,749
(1)
Amounts outstanding are stated in millions of Canadian dollars; amounts
denominated in currencies other than Canadian dollars are stated in
millions.
84 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(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: Other U.S. dollar subordinated debentures - 9.0
per cent (2004 - 9.0 per cent); and Other U.S. dollar unsecured loans,
debentures and notes - 4.9 per cent (2004 - 5.1 per cent).
(3)
In 2005, under agreement with shippers, TCPL effectively fixed the exchange
rate on the US$600 million debentures for regulatory purposes. The exchange
differential on the long-term debt at December 31, 2005, is $(2) million and
is included as part of Other U.S. dollar unsecured loans, debentures and
notes.
(4)
Long-term debt of TCPL.
(5)
Long-term debt of NOVA Gas Transmission Ltd. excluding two medium-term notes
held by TCPL: a $300 million note (2004 - nil) and a $233 million note
(US$200 million) (2004 - $241 million (US$200 million)).
(6)
Long-term debt of Gas Transmission Northwest Corporation.
(7)
Long-term debt of Portland.
(8)
Long-term debt of TCPL, excluding $16 million (2004 - $44 million) issued by
PipeLines LP.
Principal Repayments
Principal repayments on the long-term debt of the Company approximate: 2006 -
$393 million; 2007 - $604 million; 2008 - $547 million; 2009 - $742 million; and
2010 - $416 million.
Debt Shelf Programs
At December 31, 2005, $1.2 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 2006, the
Company issued $300 million of five year medium-term notes bearing interest of
4.3 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 eight per cent of the then
outstanding principal plus accrued and unpaid interest on specified repayment
dates. No redemptions have been made to December 31, 2005.
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.
Financial Charges
Year ended December 31 (millions of dollars) 2005 2004 2003
Interest on long-term debt 849 864 867
Interest on short-term debt 23 7 16
Capitalized interest (24 ) (11 ) (9 )
Amortizations and other financial charges (11 ) - 4
837 860 878
The Company made interest payments of $838 million for the year ended December
31, 2005 (2004 - $864 million; 2003 - $903 million).
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 85
NOTE 10 LONG-TERM DEBT OF JOINT VENTURES
2005 2004
Weighted Weighted
Average Average
Outstanding Interest Outstanding Interest
Maturity Dates December 31(1) Rate(2) December 31(1) Rate(2)
Great Lakes
Senior Unsecured Notes
(2005 - US$230; 2004 - 2011 to 2030 268 7.9% 283 7.9%
US$235)
Bruce Power
Capital Lease Obligations 2018 254 7.5%
Iroquois
Senior Unsecured Notes
(2005 - US $165; 2004 - 2010 to 2027 192 7.5% 182 7.5%
US$151)
Bank Loan
(2005 - US$25; 2004 - 2008 29 4.3% 43 2.5%
US$36)
Trans Quebec & Maritimes
Bonds 2009 to 2010 138 6.0% 143 7.3%
Term Loan 2010 29 3.5% 29 3.2%
Power L.P.(3)
Senior Unsecured Notes (2004 - - 70 5.9%
US$58)
Credit Facility - 64 3.2%
Term Loan - 2 11.3%
Other 2006 to 2012 68 6.1% 77 5.8%
978 893
Less: Current Portion of 41 85
Long-Term Debt of Joint
Ventures
937 808
(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, 2005, the effective weighted average interest rates
resulting from swap agreements are as follows: Iroquois bank loan - 5.4 per
cent (2004 - 4.1 per cent).
(3)
In August 2005, the Company sold its ownership interest in Power LP.
The long-term debt of joint ventures is non-recourse to TCPL, except that TCPL
has provided certain pro-rata guarantees related to the capital lease
obligations of Bruce Power. The security provided with respect to the debt 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: 2006 - $34 million; 2007 - $20 million; 2008 - $20 million; 2009 -
$78 million; and 2010 - $273 million.
The Company's proportionate share of principal payments resulting from the
capital lease obligations of Bruce Power approximates: 2006 - $7 million; 2007 -
$8 million; 2008 - $9 million; 2009 - $11 million; and 2010 - $13 million.
86 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Financial Charges of Joint Ventures
Year ended December 31 (millions of dollars) 2005 2004 2003
Interest on long-term debt 60 59 77
Interest on capital lease obligations 3 - -
Interest on short-term debt and other financial charges 1 2 1
Deferrals and amortizations 2 2 2
66 63 80
The Company's proportionate share of the interest payments of joint ventures
was $62 million for the year ended December 31, 2005 (2004 - $58 million; 2003 -
$71 million).
The Company's proportionate share of interest payments from the capital lease
obligations of Bruce Power was $3 million for the year ended December 31, 2005
(2004 and 2003 - nil).
Subject to meeting certain requirements, the Bruce Power capital lease
agreements provide for renewals commencing January 1, 2019. The first renewal is
for a period of one year, and each of the second to thirteenth renewals is for a
period of two years.
NOTE 11 DEFERRED AMOUNTS
December 31 (millions of dollars) 2005 2004
Derivative contracts 212 135
Hedging deferrals 72 53
Regulatory liabilities 597 392
Pensions and other benefit plans 168 82
Deferred revenue 42 58
Asset retirement obligations 33 36
Other 72 27
1,196 783
NOTE 12 REGULATED BUSINESS
Regulatory assets and liabilities represent future revenues which are expected
to be recovered from or refunded to customers in future periods through the
rate-setting process associated with certain costs, incurred in the current
period or in prior periods, and under or over collection of revenues.
Canadian Regulated Operations
Canadian natural gas transmission services are provided under gas transportation
tariffs that provide for cost recovery including return of and return on capital
as approved by the applicable regulatory authorities.
Rates charged by TCPL's wholly-owned and partially-owned Canadian pipelines are
typically set through a process that involves filing an application for a change
in rates with the regulator. Under the regulation, rates are underpinned by the
total annual revenue requirement which includes a specified annual return on
capital, including debt and equity, and all necessary operating expenses, taxes
and depreciation.
TCPL's Canadian regulated pipelines have generally been regulated using a
cost-of-service model, where the forecast costs plus a return on capital equals
the revenues for the upcoming year. To the extent that actual costs are more or
less than the forecast costs, the regulators generally allow the difference to
be deferred to a future period and recovered or refunded in revenues at that
time. Those costs, for which the regulator does not allow the difference between
actual and forecast costs to be deferred, are included in the determination of
net income in the year in which they are incurred.
The Canadian Mainline, the BC System, the Foothills System and the TransQuebec
& Maritimes System (TQM) are regulated by the NEB under the National Energy
Board Act. The Alberta System is regulated by the EUB primarily under the
provisions of the Gas Utilities Act (Alberta) and the Pipeline Act (Alberta).
The NEB and the EUB regulate the construction, operations, tolls and the
determination of revenues of the Canadian natural gas transmission operations.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 87
Canadian Mainline
In February 2005, TCPL and its Canadian Mainline shippers entered into a
negotiated settlement that addresses all elements of the Canadian Mainline's
2005 tolls (2005 Settlement). The 2005 Settlement was approved by the NEB in
April 2005. Pursuant to the 2005 Settlement, the cost of capital of the Canadian
Mainline's 2005 revenue requirement and resulting tolls were determined based on
the RH-2-2004 Phase II proceeding relating to the 2004 cost of capital of the
Canadian Mainline. The RH-2-2004 Phase II decision increased the deemed capital
structure for the Canadian Mainline to 36 per cent from 33 per cent, effective
January 1, 2004. The impact of this has been recognized in 2005. The return on
equity of the Canadian Mainline continues to be based on the NEB's approved rate
of return on common equity (ROE) formula which was established in the RH-2-94
Multi-Pipeline Cost of Capital proceeding.
Under the 2005 Settlement, the Canadian Mainline's operations, maintenance and
administrative (OM&A) costs for 2005 were fixed and variances between the 2005
negotiated and actual level of OM&A costs accrued to TCPL. All other cost and
revenue component variances were treated on a full recovery basis. The allowed
ROE in 2005 was 9.46 per cent.
Alberta System
The Alberta System operates under the 2005-2007 Revenue Requirement Settlement.
This settlement, approved by the EUB in June 2005, encompassed all elements of
the Alberta System's revenue requirement for 2005, 2006 and 2007 and established
methodologies for calculation of the revenue requirement for all three years,
based on the recovery of all cost components and the use of deferral accounts.
Fixed costs are operating costs and certain other costs, including foreign
exchange on interest payments, uninsured losses and amortization of severance
costs. These costs were set for each year for 2005, 2006 and 2007 and any
difference between actual and forecast fixed costs will be included in the
determination of net income in the year in which they are incurred. Costs other
than fixed costs are forecast at the beginning of each year and included in the
calculation of the revenue requirement. Any variance between the forecast and
actual costs incurred will be included in a deferral account and adjusted in the
following year's revenue requirement. The settlement also set the ROE using the
formula for determining the annual generic rate of return on common equity
established in the EUB's General Cost of Capital Decision 2004-052 on a deemed
common equity of 35 per cent for all three years. The allowed ROE in 2005 was
9.50 per cent.
Other Canadian Pipelines
Similar to the Canadian Mainline, the NEB approves pipeline tolls on an annual
cost of service basis for the BC System, Foothills System and TQM. The NEB
allows each pipeline to charge a schedule of tolls based on the estimated cost
of service. This schedule of tolls is used for a current year until a new toll
filing is made for the following year. Differences between the estimated cost of
service and the actual cost of service are included in the following year's
tolls. The ROE for these Canadian pipelines is based on the NEB's approved ROE
formula which was established in the RH-2-94 Multi-Pipeline Cost of Capital
proceeding, being 9.46 per cent in 2005. The deemed equity component of each of
the pipelines' capital structure was set at 30 per cent for 2005.
U.S. Regulated Operations
TCPL's wholly-owned and partially-owned U.S. pipelines, including Great Lakes,
Iroquois, Portland, Northern Border and Tuscarora Gas Transmission System, are
'natural gas companies' operating under the provisions of the Natural Gas Act of
1938 and the Natural Gas Policy Act of 1978, and are subject to the jurisdiction
of the FERC. The Natural Gas Act of 1938 grants the FERC authority over the
construction and operation of pipelines and related facilities. The FERC also
has authority to regulate rates for natural gas transportation in interstate
commerce.
Gas Transmission Northwest System and North Baja System
Rates and tariffs of the Gas Transmission Northwest System and the North Baja
System have been approved by the FERC. These two systems operate under fixed
rate models, whereby maximum and minimum rates for various service types have
been ordered by FERC and under which each of the two systems are permitted to
discount or negotiate rates on a non-discriminatory basis. General rates for
mainline capacity on the Gas Transmission Northwest System were last reviewed by
the FERC in a 1994 rate proceeding. A settlement of the 1994 rate proceeding,
which set rate levels that remain in effect today, was approved by the FERC in
1996. Rates for capacity on the North Baja System were established in the FERC's
initial order certificating construction and operations of its system.
Portland
In 2003, Portland received final approval from FERC of its general rate case
under the Natural Gas Act of 1938. Portland is required to file a general rate
case under the Natural Gas Act of 1938 with a proposed effective date of April
1, 2008.
88 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Regulatory Assets and Liabilities
Year ended December 31 (millions of dollars) Remaining
Recovery/
Settlement
2005 2004 Period
(years)
Regulatory Assets
Unrealized losses on derivatives - Canadian Mainline(1) 43 35 2 - 5
Unrealized losses on derivatives - BC System(1) 33 25 8
Foreign exchange - Alberta System(2) 32 33 24
Contractor claim - Trans Quebec & Maritimes(3) - 16 n/a
Phase II Preliminary Expenditures - Foothills System(4) 23 25 10
Deferred charge on reacquired debt - Gas Transmission Northwest 14 6 4 - 20
System(5)
Transitional other benefit obligations - Canadian Mainline(6) 10 11 11
Other 28 23 3 - 11
Total Regulatory Assets (Other Assets) 183 174
Regulatory Liabilities
Operating and debt service regulatory liabilities(7) 273 146 1
Foreign exchange on long-term debt - Canadian Mainline(2) 202 153 2 - 42
Foreign exchange on long-term debt - Alberta System(2) 59 36 7 - 24
Foreign exchange on long-term debt - BC System(2) 20 16 8
Post-retirement benefits other than pension - Gas Transmission 17 15 n/a
Northwest System(8)
Other 26 26 n/a
Total Regulatory Liabilities (Deferred Amounts) 597 392
(1)
Unrealized losses on derivatives represent the net position of fair value
gains and losses on cross-currency and interest rate swaps which act as
economic hedges. The cross-currency swaps relate to Canadian Mainline and BC
System foreign debt instruments. The Canadian Mainline interest rate swaps
were entered into as a result of the Interest Rate Management Program
approved by the NEB as a component of the 1996 - 1999 Incentive Cost
Recovery and Revenue Settlement. Interest savings or losses are determined
when the interest swaps are settled. In the absence of rate regulation
accounting, Canadian GAAP would require the inclusion of these fair value
losses in the operating results as they were not documented as hedges for
accounting purposes. In the absence of rate regulation accounting, pre-tax
operating results for 2005 would have been $8 million lower for each of the
Canadian Mainline and the BC System.
(2)
The foreign exchange reserve account in the Alberta System, as approved by
the EUB, is designed to facilitate the recovery or refund of foreign
exchange gains and losses over the life of the foreign currency debt issues.
Each year, the estimated gain/(loss) on foreign currency debt is amortized
over the remaining years of the longest outstanding U.S. debt issue. The
annual amortization amount is included in the determination of tolls for the
year. The foreign exchange on long-term debt on the Canadian Mainline,
Alberta System and BC System represent the variance resulting from
re-valuing foreign currency denominated debt instruments from their historic
foreign exchange rate to the current foreign exchange rate. Foreign exchange
gains/(losses) realized when foreign debt matures or is redeemed early are
expected to be recovered through the determination of future tolls. In the
absence of rate regulation accounting, GAAP would have required the
inclusion of these unrealized gains or losses either on the balance sheet or
income statement depending on whether the foreign debt is designated as a
hedge of the Company's net investment in foreign assets.
(3)
As at December 31, 2004, Trans Quebec & Maritimes had deferred $32 million
related to a contractor claim regarding cost overruns on an extension
project to Portland. TCPL's share of this deferral was $16 million. In 2005,
the NEB approved Trans Quebec & Maritimes 2005 tolls application as filed
which allowed for this amount to be capitalized in 2005. This amount would
have been capitalized under GAAP.
(4)
Phase II Preliminary Expenditures are costs incurred by Foothills System
prior to 1981 related to development of Canadian facilities to deliver
Alaskan natural gas that have been approved by the regulator for collection
through straight-line amortization over the period November 1, 2002 to
December 31, 2015. In the absence of rate regulation accounting, GAAP would
have required these costs to be expensed in the year incurred, increasing
pre-tax operating results in 2005 by $2 million.
(5)
Deferred charge on reacquired debt includes the unamortized debt issuance
costs and premiums or discounts on Gas Transmission Northwest System debt
that was reacquired prior to its original maturity date, along with any
costs incurred or gains realized on reacquiring this debt. These amounts
continue to be amortized over the original life of the debt that has been
reacquired. In the absence of rate regulation accounting, GAAP would require
the inclusion of these costs in the operating results to the extent that the
debt has not been renegotiated. Consequently, pre-tax operating results in
2005 are $8 million higher than would have been reported in the absence of
rate regulation accounting.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 89
(6)
The regulatory asset with respect to the transitional other benefit
obligations is being amortized over 17 years, starting January 1, 2000.
Amortization will be completed by December 31, 2016, at which time the full
transitional obligation will have been recovered through tolls. In the
absence of rate regulation accounting, pre-tax operating results would have
been $1 million higher.
(7)
Operating and debt service regulatory liabilities represent the accumulation
of cost and revenue variances approved by the regulatory authority for
inclusion in determination of the tolls for the immediately following
calendar year. In the absence of rate regulation accounting, GAAP may
require the inclusion of these variances in the operating results of the
year in which the variances were incurred. Pre-tax operating results for
2005 are the same as would have been the case in the absence of rate
regulation accounting.
(8)
In Gas Transmission Northwest System's rates, an amount is recovered for
post-retirement benefits other than pension (PBOP). This regulatory
liability represents the difference between the amount collected in rates
and the amount of PBOP expense determined under GAAP. In the absence of rate
regulation accounting, GAAP would require the inclusion of this amount in
operating results and pre-tax operating results in 2005 would have been $2
million higher than reported.
As prescribed by the regulators, the taxes payable method of accounting for
income taxes is used for tollmaking purposes for Canadian regulated natural gas
transmission operations. As permitted by GAAP, this method is also used for
accounting purposes, since there is reasonable expectation that future income
taxes payable will be included in future costs of service and recorded in
revenues at that time. Consequently, future income tax liabilities have not been
recognized as it is expected that when these amounts become payable, they will
be recovered through future rate revenues. In the absence of rate regulation
accounting, GAAP would require the recognition of future income tax liabilities.
If the liability method of accounting had been used, additional future income
tax liabilities in the amount of $1,619 million at December 31, 2005 (2004 -
$1,692 million) would have been recorded. For the U.S. natural gas transmission
operations, the liability method of accounting is used for both accounting and
tollmaking purposes, whereby future income tax assets and liabilities are
recognized based on the differences between financial statement carrying amounts
and the tax basis of such assets and liabilities. As this method is also used
for tollmaking purposes for the U.S. natural gas transmission operations, the
current year's revenues include a tax provision which is calculated based on the
liability method of accounting and therefore, there is no recognition of a
related regulatory asset or liability.
NOTE 13 PREFERRED SECURITIES
The US$460 million (2005 - $536 million; 2004 - $554 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.
NOTE 14 NON-CONTROLLING INTERESTS
The Company's non-controlling interests included in the consolidated balance
sheet are as follows.
December 31 (millions of dollars) 2005 2004
Non-controlling interest in PipeLines LP 318 235
Other 76 76
394 311
The Company's non-controlling interests included in the consolidated income
statement are as follows.
Year ended December 31 (millions of dollars) 2005 2004 2003
Non-controlling interest in PipeLines LP 52 46 43
Other 10 10 2
62 56 45
At December 31, 2005, the non-controlling interest in PipeLines LP is 86.6 per
cent. Other non-controlling interests at December 31, 2005 include the 38.3 per
cent non-controlling interest in Portland. Revenues received from PipeLines LP
and Portland with respect to services provided by TCPL for the year ended
December 31, 2005 were $1 million (2004-$1 million; 2003 - $1 million) and $6
million (2004 - $4 million; 2003 - nil), respectively.
90 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 15 PREFERRED SHARES
Redemption
Number of Dividend Rate Price
December 31 Shares Per Share Per Share 2005 2004
(thousands) (millions of (millions 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 16 COMMON SHARES
Number
of Shares Amount
(thousands) (millions of
dollars)
Outstanding at January 1, 2003 479,502 4,614
Exercise of options 1,166 18
Outstanding at December 31, 2003 and 2004 480,668 4,632
Issued for cash or cash equivalent 2,676 80
Outstanding at December 31, 2005 483,344 4,712
Common Shares Issued and Outstanding
The Company is authorized to issue an unlimited number of common shares of no
par value.
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, 2005, under the most restrictive
provisions, approximately $1.6 billion was available for the payment of
dividends on common shares.
NOTE 17 RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
The Company issues short-term and long-term debt, purchases and sells energy
commodities, including amounts in foreign currencies, and invests in foreign
operations. These activities result in exposures to changing interest rates,
energy commodity prices and foreign currency exchange rates. The Company uses
derivatives to manage the risk that results from these activities.
The fair value of foreign exchange and interest rate derivatives has been
calculated using year-end market rates. The fair value of power, natural gas and
heat rate derivatives has been calculated using estimated forward prices for the
relevant period.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 91
Net Investment in Foreign Operations
At December 31, 2005 and 2004, the Company had net investments in self
sustaining foreign operations with a U.S. dollar functional currency which
created an exposure to changes in exchange rates. The Company uses U.S. dollar
denominated debt and derivatives to hedge this exposure on an after-tax basis.
The fair value for derivatives used to manage the exposure is shown in the table
below.
2005 2004
Notional or Notional or
Notional Notional
Asset/(Liability) Accounting Principal Principal
December 31 (millions of Treatment Fair Value Amount Fair Value Amount
dollars)
U.S. dollar cross-currency
swaps
(maturing 2006 to 2012) Hedge 119 U.S. 450 95 U.S. 400
U.S. dollar forward foreign
exchange contracts
(maturing 2006) Hedge 5 U.S. 525 (1 ) U.S. 305
U.S. dollar options
(maturing 2006) Hedge - U.S. 60 1 U.S. 100
Reconciliation of Foreign Exchange Adjustment (Losses)/Gains
December 31 (millions of dollars) 2005 2004
Balance at January 1 (71 ) (40 )
Translation losses on foreign currency denominated net assets(1) (21 ) (39 )
Gains on derivatives 23 52
Income taxes (21 ) (44 )
Balance at December 31 (90 ) (71 )
(1)
In 2005, includes gains of $80 million (2004 - $101 million) related to
foreign currency denominated debt designated as a hedge.
Foreign Exchange Gains/(Losses)
Foreign exchange gains included in Other Expenses/(Income) for the year ended
December 31, 2005 are $19 million (2004 - $6 million; 2003 - nil).
Foreign Exchange and Interest Rate Management Activity
The Company manages the foreign exchange and interest rate risks related to its
U.S. dollar denominated debt, and transactions and interest rate exposures of
the Canadian Mainline, the Alberta System and the BC System through the use of
foreign currency and interest rate
92 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
2005 2004
Notional or Notional or
Notional Notional
Asset/(Liability) Accounting Principal Principal
December 31 (millions of Treatment Fair Value Amount Fair Value Amount
dollars)
Foreign Exchange
Cross-currency swaps Non-hedge (86 ) 363/U.S. 257 (69 ) 363/U.S. 257
(maturing 2010 to 2013)
Interest Rate
Interest rate swaps
Canadian dollars
(maturing 2007 to Hedge 4 100 7 145
2008)
(maturing 2006 to Non-hedge 7 374 9 374
2009)
11 16
U.S. dollars
(maturing 2007 to Non-hedge 5 U.S. 100 7 U.S. 100
2009)
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.
2005 2004
Notional or Notional or
Notional Notional
Asset/(Liability) Accounting Principal Principal
December 31 (millions of Treatment Fair Value Amount Fair Value Amount
dollars)
Foreign Exchange
Options (maturing 2006) Non-hedge 1 U.S. 195 2 U.S. 255
Forward foreign exchange
contracts
(maturing 2006) Hedge 2 U.S. 29 - -
(maturing 2006) Non-hedge 1 U.S. 208 1 U.S. 129
Interest Rate
Options Non-hedge - - - U.S. 50
Interest rate swaps
Canadian dollar
(maturing 2007 to Hedge 1 100 4 100
2009)
(maturing 2006 to Non-hedge 1 423 5 485
2011)
2 9
U.S. dollar
(maturing 2013) Hedge - U.S. 50 3 U.S. 375
(maturing 2006 to Non-hedge 18 U.S. 550 22 U.S. 500
2010)
18 25
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
these outstanding derivatives at December 31, 2005 was nil (2004 - $1 million).
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 93
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
value and notional volumes of contracts for differences and the swap, future,
option and heat rate contracts are shown in the tables below.
Power
2005 2004
Asset/(Liability) Accounting Treatment Fair Value Fair Value
December 31 (millions of dollars)
Power - swaps and contracts for differences
(maturing 2006 to 2011) Hedge (130 ) 7
(maturing 2006 to 2010) Non-hedge 13 (2 )
Gas - swaps, futures and options
(maturing 2006 to 2016) Hedge 17 (39 )
(maturing 2006 to 2008) Non-hedge (11 ) (2 )
Heat rate contracts
(maturing 2006) Non-hedge - (1 )
Power (GWh)(1) Gas (Bcf)(1)
Notional Volumes Accounting Purchases Sales Purchases Sales
December 31, 2005 Treatment
Power - swaps and contracts for
differences
(maturing 2006 to 2011) Hedge 2,566 7,780 - -
(maturing 2006 to 2010) Non-hedge 1,332 456 - -
Gas - swaps, futures and options
(maturing 2006 to 2016) Hedge - - 91 69
(maturing 2006 to 2008) Non-hedge - - 15 18
Heat rate contracts
(maturing 2006) Non-hedge - 35 - -
December 31, 2004
Power - swaps and contracts for Hedge 3,314 7,029 - -
differences
Non-hedge 438 - - -
Gas - swaps, futures and options Hedge - - 80 84
Non-hedge - - 5 8
Heat rate contracts Non-hedge - 229 2 -
(1)
Gigawatt hours (GWh); billion cubic feet (Bcf).
Certain of the Company's joint ventures use power derivatives to manage energy
price risk exposures. The Company's proportionate share of the fair value of
these outstanding power sales derivatives at December 31, 2005 was $(38) million
(2004 - nil) and relates to contracts which cover the period 2006 to 2008. The
Company's proportionate share of the notional sales volumes associated with this
exposure at December 31, 2005 was 2,058 GWh (2004 - nil).
94 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Fair Value of Financial Instruments
The fair value of cash and short-term investments and notes payable approximates
their carrying amounts due to the short period to maturity. The fair value of
long-term debt, long-term debt of joint ventures and preferred securities is
determined using market prices for the same or similar issues.
2005 2004
Carrying Fair Carrying Fair
December 31 (millions of dollars) Amount Value Amount Value
Long-Term Debt
Canadian Mainline 4,233 5,327 4,445 5,473
Alberta System 2,258 2,858 2,105 2,668
GTN 466 470 632 627
Foothills System 400 415 400 413
Portland 281 292 308 328
Other 2,395 2,486 2,633 2,731
Long-Term Debt of Joint Ventures 978 1,101 893 1,003
Preferred Securities 536 554 554 572
The fair value is provided solely for information purposes and is not recorded
in the consolidated balance sheet.
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, 2005, for foreign currency and interest rate
derivatives, total credit risk and the largest credit exposure to a single
counterparty were $127 million and $44 million, respectively. At December 31,
2005, for power, natural gas and heat rate derivatives, total credit risk and
the largest credit exposure to a single counterparty were $63 million and $39
million, respectively.
This information is provided by RNS
The company news service from the London Stock Exchange
MORE TO FOLLOW
FR FGGGFZNMGVZZ
1 Year Citi Fun 24 Chart |
1 Month Citi Fun 24 Chart |
It looks like you are not logged in. Click the button below to log in and keep track of your recent history.
Support: +44 (0) 203 8794 460 | support@advfn.com
By accessing the services available at ADVFN you are agreeing to be bound by ADVFN's Terms & Conditions
