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| 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 | |
|---|---|---|---|---|---|---|---|---|---|---|
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RNS Number:0978S
TransCanada Pipelines Ld
01 March 2007
PART 4
50 MANAGEMENT'S DISCUSSION AND ANALYSIS
On February 15, 2007, TCPL retired $275 million of 6.05 per cent medium term
notes. In 2006, TCPL retired long-term debt of $729 million and reduced its
notes payable by $495 million. In January 2006, the Company issued $300 million
of 4.3 per cent five-year medium-term notes due 2011. In March 2006, the Company
issued US$500 million of 5.85 per cent 30-year senior unsecured notes due 2036.
In October 2006, TCPL issued $400 million of 4.65 per cent ten-year medium-term
notes due 2016.
In April 2006, PipeLines LP borrowed US$307 million under its unsecured credit
facility to finance the cash portion of the purchase price of its acquisition of
an additional 20 per cent interest in Northern Border. In December 2006, the
credit facility was repaid in full and replaced with a US$410 million syndicated
revolving credit and term loan agreement, of which US$397 million was drawn as
at December 31, 2006. Borrowings under the credit and term loan agreement will
bear interest at the London interbank offered rate plus an applicable margin.
In 2005, TCPL retired long-term debt of $1,113 million and increased its notes
payable by $416 million. In June 2005, Gas Transmission Northwest Corporation
(GTNC) redeemed all of its outstanding US$150 million 7.8 per cent Senior
Unsecured Debentures (Debentures) and US$250 million 7.1 per cent Senior
Unsecured Notes. As a consequence, upon application by GTNC, the Debentures were
de-listed from the New York Stock Exchange and GTNC no longer has any securities
registered under U.S. securities laws. In June 2005, GTNC also completed a
US$400-million multi-tranche private placement of senior debt with a weighted
average interest rate of 5.28 per cent and weighted average life of
approximately 18 years. In 2005, TCPL also issued $300 million of 5.1 per cent
medium-term notes due 2017 under the Company's Canadian shelf prospectus.
In 2004, TCPL retired long-term debt of $1,005 million. The Company issued $200
million of 4.1 per cent medium-term notes due 2009, US$350 million of 5.6 per
cent senior unsecured notes due 2034 and US$300 million of 4.875 per cent senior
unsecured notes due 2015. The Company increased its notes payable by $179
million during 2004.
Financing activities included a net reduction in TCPL's proportionate share of
non-recourse debt of joint ventures of $14 million in 2006 compared to $42
million in 2005 and a net increase of $105 million in 2004.
Dividends on common and preferred shares of $639 million were paid in 2006
compared to $608 million in 2005 and $574 million in 2004.
In January 2007, TransCanada's Board of Directors authorized the issue of common
shares from treasury at a discount to participants in the Company's DRP. Under
this plan, eligible TCPL preferred shareholders may reinvest their dividends to
obtain additional TransCanada common shares. Previously, shares purchased
through the DRP were purchased by TransCanada on the open market and provided to
DRP participants at cost. Commencing with the dividend payable in April 2007,
the shares will be provided to the participants at a two per cent discount.
TransCanada reserves the right to alter the discount or return to purchasing
shares on the open market at any time.
At December 31, 2006, total credit facilities of $2.1 billion were available to
support the Company's commercial paper program and for general corporate
purposes. Of this total, $1.5 billion is a committed five-year term syndicated
credit facility. The facility is extendible on an annual basis and is revolving.
In December 2006, the maturity date of this facility was extended to December
2011. The remaining amounts are either demand or non-extendible facilities.
At December 31, 2006, TCPL had used approximately $190 million of its total
lines of credit for letters of credit to support ongoing commercial
arrangements. If drawn, interest on the lines of credit would be charged at
prime rates of Canadian chartered and U.S. banks or at other negotiated
financial bases.
TCPL's senior unsecured debt is rated A, with a stable outlook, by Dominion Bond
Rating Service Limited (DBRS); A2, with a stable outlook, by Moody's Investors
Service (Moody's); and A-, with a negative outlook, by Standard and Poor's (S&
P). DBRS had placed TCPL's rating under review with developing implications on
December 22, 2006 as a result of the announcement of the acquisition of ANR and
Great Lakes. Moody's and S&P reaffirmed their ratings after the announcement. On
February 22, 2007, DBRS confirmed their rating of TCPL and removed the rating
from being under review. TransCanada's issuer rating assigned by Moody's is A3
with a stable outlook.
MANAGEMENT'S DISCUSSION AND ANALYSIS 51
CONTRACTUAL OBLIGATIONS
Obligations and Commitments
Total long-term debt at December 31, 2006 was approximately $11.5 billion
compared to approximately $10.0 billion at December 31, 2005. TCPL's share of
total debt of joint ventures at December 31, 2006 was $1.3 billion compared to
$1.0 billion at December 31, 2005. Total notes payable at December 31, 2006,
including TCPL's proportionate share of the notes payable of joint ventures,
were $467 million compared to $962 million at December 31, 2005. The security
provided by each joint venture, except for the capital lease obligation 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.
CONTRACTUAL OBLIGATIONS
Year ended December 31 (millions of dollars)
Payments Due by Period
Total Less than 1 - 3 3 - 5 More than
one year years years 5 years
Long-term debt 12,531 750 1,605 1,803 8,373
Capital lease obligations 250 8 20 28 194
Operating leases1 919 39 83 84 713
Purchase obligations 11,871 2,707 3,274 1,403 4,487
Other long-term liabilities 304 10 23 27 244
reflected on the balance sheet
Total contractual obligations 25,875 3,514 5,005 3,345 14,011
(1)
Represents future annual payments, net of sub-lease receipts, for various
premises, services, equipment and a natural gas storage facility. The
operating lease agreements for premises expire at various dates through
2016, with an option to renew certain lease agreements for three to 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, 2006, scheduled principal repayments and interest payments
related to long-term debt and the Company's proportionate share of the long-term
debt and capital lease obligations of joint ventures are as follows.
PRINCIPAL REPAYMENTS
Year ended December 31 (millions of dollars)
Payments Due by Period
Total Less than 1 - 3 3 - 5 More than
one year years years 5 years
Long-term debt 11,503 616 1,396 1,536 7,955
Long-term debt of joint 1,028 134 209 267 418
ventures
Capital lease obligations 250 8 20 28 194
Total principal repayments 12,781 758 1,625 1,831 8,567
52 MANAGEMENT'S DISCUSSION AND ANALYSIS
INTEREST PAYMENTS
Year ended December 31 (millions of dollars)
Payments Due by Period
Total Less than 1 - 3 3 - 5 More than
one year years years 5 years
Interest payments on long-term 11,963 888 1,625 1,411 8,039
debt
Interest payments on long-term 687 86 160 105 336
debt of joint ventures
Total interest payments 12,650 974 1,785 1,516 8,375
At December 31, 2006, the Company's future purchase obligations are
approximately as follows.
PURCHASE OBLIGATIONS(1)
Year ended December 31 (millions of dollars)
Payments Due by Period
Total Less than one 1 - 3 3 - 5 More than 5
year years years years
Pipelines
Transportation by others(2) 648 178 257 126 87
Other 92 92 - - -
Energy
Commodity purchases(3) 8,807 1,396 2,051 1,101 4,259
Capital expenditures(4) 1,875 854 842 118 61
Other(5) 374 169 90 42 73
Corporate
Information technology and 75 18 34 16 7
other
Total purchase obligations 11,871 2,707 3,274 1,403 4,487
(1)
The amounts in this table exclude funding contributions to pension plans and
funding to the APG.
(2)
Rates are based on known 2007 levels. Beyond 2007, demand rates are subject
to change. The contract obligations in the table are based on known or
contracted demand volumes only and exclude commodity charges incurred when
volumes flow.
(3)
Commodity purchases include fixed and variable components. The variable
components are estimates and are subject to variability in plant production,
market prices and regulatory tariffs.
(4)
Represents primarily estimated capital expenditures to construct new Energy
projects. Amounts are estimates and are subject to variability based on
timing of construction and project enhancements. The Company expects to fund
these projects with cash from operations and, if necessary, new debt.
(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 2007, TCPL expects to make funding contributions to the Company's pension
plans and other benefit plans in the amount of approximately $44 million and $5
million, respectively. The expected decrease in total pension and
post-retirement benefits funding in 2007 from $104 million in 2006 is primarily
attributed to the actual return on plan
MANAGEMENT'S DISCUSSION AND ANALYSIS 53
assets for 2006 exceeding investment performance expectations as well as
additional company funding in 2006. These decreases were partially offset by
increases in pension-funding liabilities due to plan experience being different
from expected. During 2007, 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 $33 million and $3 million, respectively.
TCPL has guaranteed the performance of all obligations of PipeLines LP with
respect to its acquisition of a 46.45 per cent interest in Great Lakes pursuant
to the purchase agreement.
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.
Bruce Power
Included in Energy's capital expenditures in the previous table are TCPL's share
of Bruce A's commitments to third party suppliers for the next four 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 the replacement of the steam generators on Unit 4, as
follows.
Year ended December 31 (millions of dollars)
2007 450
2008 164
2009 71
2010 1
2011 -
686
In addition to the Bruce restart and refurbishment, the Company is committed to
capital expenditures of approximately $1.2 billion for the construction of its
Halton Hills, Portlands Energy and remaining Cartier Wind projects, subject to
future appropriations and approvals.
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 MGP 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 pre-development costs. These costs are currently forecasted to be
approximately $145 million by the end of 2007.
Guarantees
TCPL had no outstanding guarantees related to the long-term debt of unrelated
third parties at December 31, 2006.
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 range from 2007 to 2018.
As part of the reorganization of Bruce Power in 2005, 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, 2006 was estimated to be approximately $586 million of a calculated maximum
of $658 million. The current carrying amount of the liability related to these
guarantees is nil and the fair value is approximately $17 million.
54 MANAGEMENT'S DISCUSSION AND ANALYSIS
TCPL has guaranteed the equity undertaking of a subsidiary which supports the
payment, under certain conditions, of principal and interest on US$105 million
of public debt obligations of TransGas de Occidente S.A. (TransGas). The Company
has a 46.5 per cent interest in TransGas. Under the terms of the agreement, the
Company, severally with another major multinational company, may be required to
fund more than their proportionate share of debt obligations of TransGas in the
event that the minority shareholders fail to contribute. Any payments made by
TCPL under this agreement convert into share capital of TransGas. The potential
exposure is contingent on the impact of any change of law on TransGas' ability
to service the debt. From the issuance of the debt in 1995 to date, there has
been no change in applicable law and thus no exposure to TCPL. The debt matures
in 2010 and the Company has made no provision related to this guarantee.
In connection with the acquisition of GTN in 2004, US$241 million of the
purchase price was deposited into an escrow account. As at December 31, 2006,
there was US$24 million remaining in the escrow account, which represented the
full face amount of the potential liability under certain GTN guarantees. In
February 2007, the funds were released and a portion of the monies were used to
satisfy the liability of GTN under these designated guarantees.
Contingencies
The Canadian Alliance of Pipeline Landowners' Associations (CAPLA) 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. In November 2006, TCPL and
Enbridge Inc. were granted a dismissal of the case but CAPLA has appealed that
decision. The Company continues to believe 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 uses
derivatives to manage the exposure that results from these activities. The use
of derivatives is subject to the Company's overall risk management policies and
procedures.
Derivatives and other instruments must be designated and be 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, after tax, and designated foreign currency
denominated debt are offset against the exchange gains or losses 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. 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 likely to occur, related deferred gains or losses are recognized in
income in the current period.
MANAGEMENT'S DISCUSSION AND ANALYSIS 55
The recognition of gains and losses on the derivatives for the Canadian
Mainline, Alberta System, Foothills and the BC System exposures is determined
through the regulatory process. The gains and losses on derivatives accounted
for as part of rate-regulated accounting that do not meet the criteria for hedge
accounting are deferred.
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.
Net Investment in Foreign Operations
At December 31, 2006 and 2005, 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)
2006 2005
December 31 (millions Accounting Fair Value Notional or Fair Value Notional or
of dollars) Treatment Principal Principal
Amount Amount
US dollar
cross-currency swaps
(maturing 2007 to Hedge 58 U.S. 400 119 U.S. 450
2013)
US dollar forward
foreign exchange
contracts
(maturing 2007) Hedge (7 ) U.S. 390 5 U.S. 525
US dollar options
(maturing 2007) Hedge (6 ) U.S. 500 - U.S. 60
Reconciliation of Foreign Exchange Adjustment
December 31 (millions of dollars) 2006 2005
Balance at January 1 (loss) (90 ) (71 )
Translation gains/(losses) on foreign currency denominated net assets(1) 8 (21 )
(Losses)/gains on derivatives (9 ) 23
Income taxes 1 (21 )
Balance at December 31 (loss) (90 ) (90 )
(1)
The amount for 2006 includes gains of $6 million (2005 - $80 million)
related to foreign currency denominated debt designated as a hedge.
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.
56 MANAGEMENT'S DISCUSSION AND ANALYSIS
Asset/(Liability)
2006 2005
December 31 Accounting Fair Value Notional or Fair Value Notional or
(millions of dollars) Treatment Principal Amount Principal
Amount
Foreign Exchange
Cross-currency and
interest-rate swaps
(maturing 2013) Hedge (32 ) 136/U.S. 100 -
(maturing 2010 to Non-hedge (52 ) 227/U.S. 157 (86 ) 363/U.S. 257
2012)
(84 ) (86 )
Interest Rate
Interest rate swaps
Canadian dollars
(maturing 2007 to Hedge 2 100 4 100
2008)
(maturing 2007 to Non-hedge 5 300 7 374
2009)
7 11
US dollars
(maturing 2007 to Non-hedge 4 U.S. 100 5 U.S. 100
2009)
MANAGEMENT'S DISCUSSION AND ANALYSIS 57
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)
2006 2005
December 31 Accounting Fair Value Notional or Fair Value Notional or
(millions of dollars) Treatment Principal Principal
Amount Amount
Foreign Exchange
Options (maturing Non-hedge - U.S. 95 1 U.S. 195
2007)
Forward foreign
exchange contracts
Hedge - - 2 U.S. 29
(maturing 2007) Non-hedge (3 ) U.S. 250 1 U.S. 208
(3 ) 4
Interest Rate
Options (maturing Non-hedge - U.S. 50 - -
2007)
Interest rate swaps
Canadian dollar
(maturing 2007 to Hedge - 150 1 100
2011)
(maturing 2009 to Non-hedge - 164 1 423
2011)
- 2
US dollar
(maturing 2011 to Hedge (2 ) U.S. 350 - U.S. 50
2017)
(maturing 2007 to Non-hedge 9 U.S. 450 18 U.S. 550
2016)
7 18
For the year ended December 31, 2006, the Company had net losses of $1 million
(2005 - net gains of $10 million; 2004 - net gains of $5 million) associated
with interest rate swaps, which included a $6-million loss (2005 - $5-million
loss; 2004 - $7-million gain) relating to a change in mark-to-market positions
on non-hedges. The net losses are included in Financial Charges on the
Consolidated Income Statement.
Foreign exchange gains included in Other Expenses/(Income) for the year ended
December 31, 2006 are $4 million (2005 - $19 million; 2004 - $6 million).
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, 2006 and 2005 was nil.
58 MANAGEMENT'S DISCUSSION AND ANALYSIS
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.
Energy
Asset/(Liability)
2006 2005
December 31 (millions of dollars) Accounting Fair Value Fair Value
Treatment
Power - swaps and contracts for differences
(maturing 2007 to 2011) Hedge (179 ) (130 )
(maturing 2007 to 2010) Non-hedge (7 ) 13
Gas - swaps, futures and options
(maturing 2007 to 2016) Hedge (66 ) 17
(maturing 2007 to 2008) Non-hedge 30 (11 )
Heat rate contracts Non-hedge - -
Notional Volumes
Power (GWh) Gas (Bcf)
December 31, 2006 Accounting Purchases Sales Purchases Sales
Treatment
Power - swaps and contracts
for differences
(maturing 2007 to 2011) Hedge 6,654 12,349 - -
(maturing 2007 to 2010) Non-hedge 1,402 964 - -
Gas - swaps, futures and
options
(maturing 2007 to 2016) Hedge - - 77 59
(maturing 2007 to 2008) Non-hedge - - 11 15
Heat rate contracts Non-hedge - 9 - -
December 31, 2005
Power - swaps and contracts for Hedge 2,566 7,780 - -
differences
Non-hedge 1,332 456 - -
Gas - swaps, futures and options Hedge - - 91 69
Non-hedge - - 15 18
Heat rate contracts Non-hedge - 35 - -
During 2006, the Company recorded net gains of $41 million (2005 - net losses of
$12 million; 2004 - net losses of $1 million) as a result of the non-hedge gas
swaps, futures and options. These net gains were partially offset by losses from
the non-hedge power swaps and contracts of $19 million (2005 - net gains of $16
million; 2004 - net losses of $3 million). The net impact of gains and losses on
non-hedge derivatives for power, gas, and heat rate contracts were net gains of
$22 million (2005 - net gains of $4 million; 2004 - net losses of $4 million)
for the year included in Revenue.
MANAGEMENT'S DISCUSSION AND ANALYSIS 59
At December 31, 2006, the Company had unrealized net losses of $222 million
(2005 - net losses of $111 million) as a result of its energy swaps, futures,
options and contracts that had not settled by year end. There were unrealized
losses from unsettled energy derivatives of $144 million (2005 - $107 million)
included in Accounts Payable and $158 million (2005 - $105 million) included in
Deferred Amounts. These losses were partially offset by unrealized gains of $39
million (2005 - $44 million) included in Other Assets and $41 million (2005 -
$57 million) included in Other Current Assets.
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, 2006 was $55 million
(2005 - $(38) million) and related to contracts which cover the period 2007 to
2010. The Company's proportionate share of the notional sales volumes associated
with this exposure at December 31, 2006 was 4,500 GWh (2005 - 2,058 GWh).
RISKS AND 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 - Individual risks are subject to internal audit review,
with independent reporting to the Audit Committee of TCPL's Board of
Directors.
The processes within TCPL's risk management function are designed to ensure that
risks are properly identified, quantified, reported and managed. Risk management
strategies, policies and limits are designed to ensure TCPL's risk-taking is
consistent with the Company's business objectives and risk tolerance. Risks are
managed within limits ultimately established by the Company's Board of Directors
and implemented by senior management, monitored by risk management personnel and
audited by internal audit personnel.
TCPL manages market, 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 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.
60 MANAGEMENT'S DISCUSSION AND ANALYSIS
Financial Risk Management
TCPL monitors the financial market risk exposures relating to the Company's
investments in foreign currency denominated net assets, regulated and
non-regulated long-term debt portfolios and foreign currency exposure on
transactions. The market risk exposures created by these business activities are
managed by establishing offsetting positions or through the use of derivative
financial instruments.
Counterparty Risk Management
Counterparty risk is the financial loss that the Company would experience if the
counterparty failed to meet its obligations in accordance with the terms and
conditions of its contracts with the Company. Counterparty risk is mitigated by
conducting financial and other assessments to establish a counterparty's
creditworthiness, setting exposure limits and monitoring exposures against these
limits, and, where warranted, obtaining financial assurances.
The Company's counterparty risk management practices and positions are further
described in Note 15 to the consolidated financial statements.
Development Projects and Acquisitions
TCPL continues to focus on growing its Pipelines and Energy operations through
greenfield projects and acquisitions. TCPL defers costs incurred on certain of
its development projects during the period prior to construction when the
project meets specific criteria including an expectation that the project will
proceed to ultimate completion. If an individual project does not proceed, the
related deferred costs would be expensed at that time. With respect to TCPL's
acquisition of existing assets and operations, there is a risk that certain
commercial opportunities and operational synergies may not materialize as
originally expected.
Foreign Exchange
A portion of TCPL's earnings from its Pipelines and Energy operations in the
U.S. are generated in U.S. dollars and are subject to currency fluctuations. The
performance of the Canadian dollar relative to the U.S. dollar could either
positively or negatively impact TCPL's net earnings, although much of this
foreign exchange impact is offset by exposures in certain of TCPL's businesses
as well as through the Company's hedging activities. With the acquisition of ANR
and a greater ownership interest in PipeLines LP, TCPL expects to have a greater
exposure to U.S. dollar fluctuations.
Risks and Risk Management Related to Environmental Regulations
Climate change remains a serious issue for TCPL. The change of government in
Canada in early 2006 resulted in a shift of focus from meeting greenhouse gas
reduction targets to a broader emphasis on clean air as well as greenhouse gas
emissions. The Government of Canada released the Clean Air Act on October 19,
2006. At this time however, the policy framework for the new regulations has not
been released by the federal government and detailed sectoral targets and
timeframes as well as compliance options have not been set. At a provincial
level, the Quebec government has passed legislation for a hydrocarbon royalty on
industrial greenhouse gas emitters. The details as to how the royalty will be
applied have not yet been determined but it is expected these details will be
set in the coming year. In Alberta, the government has indicated it will
continue with its own plan for implementing regulations to manage greenhouse gas
emissions. It is yet to be determined how this effort will tie into a federal
program.
In the U.S., state level initiatives are under way to limit greenhouse gas
emissions, particularly in the northeastern U.S. and California. Details have
not been finalized and the impact to TCPL's U.S.-based assets is uncertain.
Despite this uncertainty, TCPL continues with its programs to manage greenhouse
gas emissions from its assets, and to evaluate new processes and technologies
that result in improved efficiencies and lower greenhouse gas emissions rates.
In addition, TCPL remains involved in policy discussions in those jurisdictions
where policy development is under way and where the Company has operations.
MANAGEMENT'S DISCUSSION AND ANALYSIS 61
CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
Disclosure controls and procedures are designed to provide reasonable assurance
that information required to be disclosed in reports filed with, or submitted
to, securities regulatory authorities is recorded, processed, summarized and
reported within the time periods specified under Canadian and U.S. securities
laws. The information is accumulated and communicated to management, including
the President and Chief Executive Officer and the Chief Financial Officer, to
allow timely decisions regarding required disclosure.
As of December 31, 2006, an evaluation was carried out, under the supervision of
and with the participation of management, including the President and Chief
Executive Officer and Chief Financial Officer, of the effectiveness of TCPL's
disclosure controls and procedures as defined under the rules adopted by the
Canadian securities regulatory authorities and by the U.S. Securities and
Exchange Commission (SEC). Based on that evaluation, the President and Chief
Executive Officer and Chief Financial Officer concluded that the design and
operation of TCPL's disclosure controls and procedures were effective as at
December 31, 2006.
Management's Annual Report on Internal Control over Financial Reporting
Internal control over financial reporting is a process designed by, or under the
supervision of, senior management, and effected by the Board of Directors,
management and other personnel, to provide reasonable assurance regarding the
reliability of financial reporting and preparation of consolidated financial
statements for external purposes in accordance with Canadian GAAP, including a
reconciliation to U.S. GAAP.
Management is responsible for establishing and maintaining adequate internal
control over financial reporting. Internal control over financial reporting, no
matter how well designed, has inherent limitations and can only provide
reasonable assurance with respect to the preparation and fair presentation of
published financial statements. Under the supervision of, and with the
participation of, management, including the President and Chief Executive
Officer and Chief Financial Officer, management conducted an evaluation of the
effectiveness of its internal control over financial reporting based on the
framework in Internal Control - Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission. Based on this assessment,
according to these criteria, management concluded that internal control over
financial reporting is effective as of December 31, 2006 to provide reasonable
assurance regarding the reliability of financial reporting and the preparation
of financial statements for external reporting purposes.
During the year ended December 31, 2006, there has been no change in TCPL's
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, 2006, 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 and the Canadian securities regulators
certifications regarding the quality of TCPL's public disclosures relating to
its fiscal 2006 reports filed with the SEC and the Canadian securities
regulators.
Compliance Expenditures
The total cost incurred by TCPL comply with the requirements of the SEC and
Canadian securities regulatory authorities arising out of the Sarbanes-Oxley Act
of 2002 for the period January 1, 2002 to December 31, 2006, was estimated to be
$14 million, including third party charges of $4 million.
SIGNIFICANT ACCOUNTING POLICIES AND CRITICAL ACCOUNTING ESTIMATES
Since determining the value 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.
62 MANAGEMENT'S DISCUSSION AND ANALYSIS
Regulated Accounting
The Company accounts for the impacts of rate regulation in accordance with GAAP
as outlined in Notes 1 and 11 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 11 to the consolidated
financial statements.
Derivative Accounting
The Company enters into the following financial instruments to manage its risk
exposure:
*
power, natural gas and heat rate derivatives for overall management of
its commodity price exposure;
*
foreign currency and interest rate derivatives to manage its foreign
exchange and interest rate risks related to its U.S. dollar denominated
debt and transactions and interest rate exposures; and
*
U.S. dollar denominated debt and U.S dollar swaps, forwards and options
to hedge the exposure on an after-tax basis of net investments in self
sustaining foreign operations with a U.S. dollar functional currency.
Derivatives are recorded at their fair value at each balance sheet date.
Derivatives and other instruments must be designated and be effective to qualify
for hedge accounting. 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.
Unrealized long-term gains and losses are included in Other Assets and Deferred
Amounts, respectively. Unrealized current gains and losses are included in Other
Current Assets and Accounts Payable, respectively. For hedges of net investments
in self-sustaining foreign operations, exchange gains or losses on derivatives,
after 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.
Assessment of effectiveness for those derivatives classified as hedges occurs at
inception and on an ongoing basis. The determination of whether a derivative
contract qualifies as a cash flow hedge includes an analysis of historical
market price information to assess whether the derivatives are expected to be
highly effective in achieving offsetting cash flows attributable to the hedged
risk. 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 category as the underlying
transaction giving rise to the exposure being economically hedged. If an
anticipated transaction is hedged and the transaction is no longer probable to
occur, the related deferred gains or losses are recognized in income in the
current period.
The recognition of gains and losses on derivatives for the Canadian Mainline,
Alberta System, Foothills and the BC System exposures is determined through the
regulatory process. Certain of the realized gains and losses on these
derivatives are shared with shippers on predetermined terms. The gains and
losses on derivatives accounted for as part of rate-regulated accounting that do
not meet the criteria for hedge accounting are deferred.
The fair value for derivative contracts is determined based on the nature of the
transactions and the market in which transactions are executed. Assumptions and
judgements about counterparty performance and credit considerations are
incorporated in the determination of fair value.
The Company estimates the fair value of derivative contracts by using readily
available price quotes in similar markets and other market analyses. The number
of transactions executed without quoted market prices is limited. The fair value
of all derivative contracts is continually subject to change as the underlying
commodity market changes and TCPL's
MANAGEMENT'S DISCUSSION AND ANALYSIS 63
assumptions and judgments change. 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 is calculated using
estimated forward prices for the relevant period.
The chart below shows the effect that a one dollar change in the price of power
(per MWh) or gas (per GJ) would have on the calculation of the fair values of
derivatives as recorded on the balance sheet.
Increase $1 Decrease $1
(millions of dollars) Effect on fair value Effect on fair value
Western Power Operations - power -8 +8
Eastern Power Operations - power +2 -3
Eastern Power Operations - gas +19 -19
Depreciation and Amortization Expense
TCPL's plant, property and equipment are depreciated on a straight-line basis
over their estimated useful lives. Pipeline and compression equipment are
depreciated at annual rates from two to six per cent. Major power generation and
natural gas storage plant, equipment and structures in the Energy business are
depreciated at average annual rates ranging from two to ten per cent. Nuclear
power generation assets under capital lease are amortized over the shorter of
their useful life or the remaining terms of their lease. Other equipment is
depreciated at various rates.
Depreciation expense for the year ended December 31, 2006 was $1,059 million and
primarily impacts the Pipelines and Energy segments of the Company. In
Pipelines, 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 Pipelines 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
Non-Monetary Transactions
Effective for non-monetary transactions initiated in periods beginning on or
after January 1, 2006, the new Handbook Section 3831 "Non-Monetary Transactions"
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. Adopting the provisions of this
standard in 2006 did not have an impact on the Company's consolidated financial
statements.
Financial Instruments - Recognition and Measurement
Effective for interim and annual financial statements beginning on or after
October 1, 2006, the new Handbook Section 3855 "Financial Instruments -
Recognition and Measurement" prescribes that all financial instruments within
the scope of this standard, including derivatives, be included on a company's
balance sheet. Contracts that can be settled by receipt or delivery of a
commodity will also be included in the scope of the section. These financial
instruments must be measured, either at their fair value or, in limited
circumstances when fair value may not be considered the most relevant
measurement method, 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 new Handbook section will be adopted by the Company as of
January 1, 2007 on a prospective basis. TCPL does not expect this new
requirement to have a significant impact on the Company's consolidated financial
statements.
64 MANAGEMENT'S DISCUSSION AND ANALYSIS
Hedges
Effective for interim and annual financial statements for fiscal years beginning
on or after October 1, 2006, the new Handbook Section 3865 "Hedges" 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 new Handbook section will
be adopted by the Company as of January 1, 2007 on a prospective basis. TCPL
does not expect this new requirement to have a significant impact on the
Company's consolidated financial statements.
Comprehensive Income
Effective for interim and annual financial statements for fiscal years beginning
on or after October 1, 2006, the new Handbook Section 1530 "Comprehensive
Income" 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 Handbook section will be adopted by the Company as of January 1, 2007 on a
prospective basis. Beginning first quarter 2007, TCPL's financial statements
will include a Statement of Comprehensive Income and a Statement of Accumulated
Comprehensive Income.
SELECTED QUARTERLY CONSOLIDATED FINANCIAL DATA(1)
2006
(millions of dollars except per share amounts) Fourth Third Second First
Revenues 2,091 1,850 1,685 1,894
Net Income Applicable to Common Shares
Continuing operations 268 293 244 244
Discontinued operations - - - 28
268 293 244 272
Per Common Share Data
Net income - Basic and Diluted
Continuing operations $0.56 $0.60 $0.51 $0.50
Discontinued operations - - - 0.06
$0.56 $0.60 $0.51 $0.56
2005
(millions of dollars except per share amounts) Fourth Third Second First
Revenues 1,771 1,494 1,449 1,410
Net Income
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
(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 Notes 1 and 22 of TCPL's 2006
audited consolidated financial statements included in TCPL's 2006 Annual
Report.
MANAGEMENT'S DISCUSSION AND ANALYSIS 65
Factors Impacting Quarterly Financial Information
In Pipelines, 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, seasonal fluctuations in short-term throughput volumes on U.S.
pipelines and items outside of the normal course of operations.
In Energy, which consists primarily of the Company's investments in electrical
power generation plants and natural gas storage facilities, 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 2006 and 2005 quarterly net earnings are as
follows.
*
In first quarter 2005, net earnings included a $48-million after-tax
gain related to the sale of PipeLines LP units. Energy 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 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 hydroelectric generation assets from USGen. Bruce Power's income from
equity investments 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 income from equity investments 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 the sale of Paiton Energy. In addition, Bruce A was formed and
Bruce Power's results were proportionately consolidated, effective
October 31, 2005.
*
In first quarter 2006, net earnings included an $18-million after tax
($29-million pre-tax) bankruptcy settlement from a former shipper on the
Gas Transmission Northwest System.
*
In second quarter 2006, net earnings included $33 million of future
income tax benefits as a result of reductions in Canadian federal and
provincial corporate income tax rates. Net earnings also included a
$13-million after-tax gain related to the sale of the Company's interest
in Northern Border Partners, L.P.
*
In third quarter 2006, net earnings included an income tax benefit of
approximately $50 million as a result of the resolution of certain
income tax matters with taxation authorities and changes in estimates.
*
In fourth quarter 2006, net earnings included approximately $12 million
related to income tax refunds and related interest.
66 MANAGEMENT'S DISCUSSION AND ANALYSIS
FOURTH QUARTER 2006 HIGHLIGHTS
SEGMENT RESULTS-AT-A-GLANCE
Three months ended December 31
(millions of dollars) 2006 2005
Pipelines 126 155
Energy
Excluding gains 132 87
Gain on sale of Paiton Energy - 115
132 202
Corporate 10 (8 )
Net Income Applicable to Common Shares(1) 268 349
(1)Net Income Applicable to Common Shares
Excluding gain 268 234
Gain on sale of Paiton Energy - 115
268 349
Net income for fourth quarter 2006 of $268 million decreased by $81 million
compared to $349 million for fourth quarter 2005. This decrease was primarily
due to an after-tax gain of $115 million from the sale of Paiton Energy in
fourth quarter 2005.
Excluding the $115-million gain related to the sale of Paiton Energy, net income
for fourth quarter 2006 increased $34 million compared to fourth quarter 2005.
This was primarily due to increases of $45 million and $18 million in net
earnings from Energy and Corporate, respectively, partially offset by a decrease
of $29 million in net earnings from the Pipelines business.
For fourth quarter 2006, Pipeline's net income decreased $29 million compared to
fourth quarter 2005 due to a $22-million reduction in net earnings from Wholly
Owned Pipelines and a $7-million decrease in net earnings from the Other
Pipelines businesses. Wholly Owned Pipelines' net earnings decreased primarily
due to a lower ROE and lower average investment bases in the Canadian Mainline
and the Alberta System. Net earnings from GTN decreased due to increased
operating costs and lower transportation revenues. Net earnings for TCPL's Other
Pipelines decreased primarily due to higher project development and support
costs and the impact of a weaker U.S. dollar.
Excluding the gain of $115 million in 2005, Energy's net earnings increased $45
million in fourth quarter 2006, compared to fourth quarter 2005, due to higher
operating income from Western Power Operations, Natural Gas Storage and Bruce
Power. Partially offsetting these increases were lower operating income from
Eastern Power Operations and higher general, administrative and support costs.
Bruce Power's contribution to operating income increased $6 million in fourth
quarter 2006, compared to fourth quarter 2005, primarily due to an increased
ownership interest in the Bruce A facilities and the positive impact of higher
generation volumes, partially offset by lower overall realized prices and higher
operating expenses.
Western Power Operations' operating income was $76 million higher in fourth
quarter 2006, compared to fourth quarter 2005, primarily due to incremental
earnings from the December 31, 2005 acquisition of the 756 MW Sheerness PPA and
increased margins from a combination of higher overall realized power prices and
higher market heat rates on sales of uncontracted power volumes.
MANAGEMENT'S DISCUSSION AND ANALYSIS 67
Eastern Power Operations' operating income was $13 million lower in fourth
quarter 2006, compared to fourth quarter 2005, primarily due to record hurricane
activity in the Gulf of Mexico in 2005 which caused a significant increase in
certain commodity prices and increased hydro generation volumes. As a result,
higher profits were earned in 2005 from increased generation volumes as a result
of unusually high water flows through the TC Hydro facilities, increased margins
on the natural gas purchased and resold under the OSP gas supply contracts and
higher prices realized on power sold into the spot market. The
quarter-over-quarter decrease was partially offset by incremental income earned
in 2006 from the startup of the 550 MW Becancour cogeneration plant in September
2006 and the first wind farm of the Cartier Wind project in November 2006.
Natural Gas Storage operating income increased $13 million in fourth quarter
2006, compared to fourth quarter 2005, primarily due to higher contributions
from CrossAlta as a result of increased storage capacity and higher natural gas
storage spreads.
General, administrative, support costs and other of the Energy business
increased $8 million in fourth quarter 2006, compared to fourth quarter 2005,
primarily due to higher business development costs associated with growing the
Energy business.
Corporate's net earnings increased $18 million to $10 million in fourth quarter
2006 primarily due to income tax refunds and related interest of approximately
$12 million and other positive income tax adjustments.
SHARE INFORMATION
At February 22, 2007, 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 other continuous disclosure documents, is available on
SEDAR at www.sedar.com under TransCanada PipeLines Limited.
Other selected consolidated financial information for the years ended December
31, 2006, 2005, 2004, 2003, 2002, 2001 and 2000 is found under the heading
"Seven-Year Financial Highlights" on pages 111 and 112 of this Annual Report.
68 MANAGEMENT'S DISCUSSION AND ANALYSIS
GLOSSARY OF TERMS
ACES Accelerated Clean Energy Supply
ANR The American Natural Resources Company and the ANR Storage Company, collectively
APG Aboriginal Pipeline Group
B.C. British Columbia
Bcf Billion cubic feet
Bcf/d Billion cubic feet per day
BPC BPC Generation Infrastructure Trust
Broadwater Broadwater Energy project
Bruce A Bruce Power A L.P.
Bruce B Bruce Power L.P.
Bruce Power The collective investments in Bruce A and Bruce B
Cacouna Cacouna Energy project
Calpine Calpine Corporation and certain of its subsidiaries
Cameco Cameco Corporation
CAPLA Canadian Alliance of Pipeline Landowners' Associations
CAPP Canadian Association of Petroleum Producers
CPPL ConocoPhillips Pipe Line Company
CrossAlta CrossAlta Gas Storage & Services Ltd.
DBRS Dominion Bond Rating Service Limited
DRP Dividend Reinvestment and Share Purchase Plan
EPCOR EPCOR Utilities Inc.
EUB Alberta Energy and Utilities Board
FCM Forward Capacity Market
FERC Federal Energy Regulatory Commission
Foothills Foothills Pipe Lines Ltd.
FT Firm transportation
GAAP Generally accepted accounting principles
Gas Pacifico Gasoducto del Pacifico S.A.
GJ Gigajoule
GRA General Rate Application
Great Lakes Great Lakes Gas Transmission Limited Partnership
GTA Greater Toronto Area
GTN Gas Transmission Northwest System and the North Baja system, collectively
GTNC Gas Transmission Northwest Corporation
GWh Gigawatt hours
INNERGY INNERGY Holdings S.A.
Iroquois Iroquois Gas Transmission System, L.P.
JRP Joint Review Panel
Keystone TransCanada Keystone Pipeline GP Ltd.
km Kilometres
LNG Liquefied natural gas
MD&A Management's Discussion and Analysis
MGP Mackenzie Gas Pipeline
Millennium Millennium Pipeline project
Mirant Mirant Corporation and certain of its subsidiaries
mmcf/d Million cubic feet per day
Moody's Moody's Investors Service
MW Megawatt
MWh Megawatt hour
NBV Net book value
NEB National Energy Board
Net earnings Net income from continuing operations
NEPOOL New England Power Pool
NGLs Natural gas liquids
Northern Border Northern Border Pipeline Company
NPA Northern Pipeline Act of Canada
OM&A Operating, maintenance and administration
OPA Ontario Power Authority
OSP Ocean State Power
Paiton Energy P.T. Paiton Energy Company
PG&E Pacific Gas & Electric Company
PipeLines LP TC PipeLines, LP
Portland Portland Natural Gas Transmission System
Portlands Energy Portlands Energy Centre L.P.
Power LP TransCanada Power, L.P.
PPA Power purchase arrangement
ROE Rate of return on common equity
S&P Standard & Poor's
SEC U.S. Securities and Exchange Commission
Shell Shell US Gas & Power LLC
TBO Transportation by Others
TCPL or the TransCanada PipeLines Limited
Company
TCPM TransCanada Power Marketing Ltd.
TQM Trans Quebec & Maritimes System
TransCanada TransCanada Corporation
TransGas TransGas de Occidente S.A.
Tuscarora Tuscarora Gas Transmission Company
U.S. United States
USGen USGen New England, Inc.
Ventures LP TransCanada Pipeline Ventures Limited Partnership
WCSB Western Canada Sedimentary Basin
MANAGEMENT'S DISCUSSION AND ANALYSIS 69
The consolidated financial statements included in this Annual Report are
the responsibility of Management and have been approved by the Board of
Report of Directors of the Company. These consolidated financial statements have
Management been prepared by Management in accordance with generally accepted
accounting principles (GAAP) in Canada and include amounts that are
based on estimates and judgments. Financial information contained
elsewhere in this Annual Report is consistent with the consolidated
financial statements.
Management has prepared Management's Discussion and Analysis which is
based on the Company's financial results prepared in accordance with
Canadian GAAP. It compares the Company's financial performance in 2006
to 2005 and should be read in conjunction with the consolidated
financial statements and accompanying notes. In addition, significant
changes between 2005 and 2004 are highlighted.
Management has designed 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.
Under the supervision and with the participation of the President and
Chief Executive Officer and Chief Financial Officer, Management
conducted an evaluation of the effectiveness of its internal control
over financial reporting based on the framework in Internal Control -
Integrated Framework issued by the Committee of Sponsoring Organizations
of the Treadway Commission. Based on this assessment according to these
criteria, Management concluded that internal control over financial
reporting is effective as of December 31, 2006 to provide reasonable
assurance regarding the reliability of financial reporting and the
preparation of financial statements for external reporting purposes.
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 in accordance with the
terms of the charter of the Audit Committee as set out in the Annual
Information Form. The Audit Committee reviews the Annual Report,
including 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 outlines the scope
of their examination and their opinion on the consolidated financial
statements.
,G867826.JPG ,G515198.JPG
Harold N. Kvisle Gregory A. Lohnes
President and Executive Vice-President and
Chief Executive Officer Chief Financial Officer
February 22, 2007
70 TRANSCANADA PIPELINES LIMITED
To the Shareholders of TransCanada PipeLines Limited
Auditors' We have audited the consolidated balance sheets of TransCanada PipeLines
Report Limited as at December 31, 2006 and 2005 and the consolidated statements
of income, retained earnings and cash flows for each of the years in the
three-year period ended December 31, 2006. 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. With respect to the consolidated financial
statements for the years ended December 31, 2006 and 2005, we also
conducted our audits in accordance with the standards of the Public
Company Accounting Oversight Board (United States). 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, 2006 and 2005 and the results of its operations and its
cash flows for each of the years in the three-year period ended December
31, 2006 in accordance with Canadian generally accepted accounting
principles.
,G398903.JPG
Chartered Accountants
Calgary, Canada
February 22, 2007
CONSOLIDATED FINANCIAL STATEMENTS 71
TRANSCANADA PIPELINES LIMITED
CONSOLIDATED INCOME
Year ended December 31 2006 2005 2004
(millions of dollars except per share amounts)
Revenues 7,520 6,124 5,497
Operating Expenses
Plant operating costs and other 2,411 1,825 1,615
Commodity purchases resold 1,707 1,232 940
Depreciation 1,059 1,017 948
5,177 4,074 3,503
2,343 2,050 1,994
Other Expenses/(Income)
Financial charges (Note 8) 828 837 860
Financial charges of joint ventures (Note 9) 92 66 63
Income from equity investments (Note 6) (33 ) (247 ) (213 )
Interest income and other (123 ) (63 ) (59 )
Gains on sale of assets (Note 7) (23 ) (445 ) (204 )
741 148 447
Income from Continuing Operations before Income 1,602 1,902 1,547
Taxes and Non-Controlling Interests
Income Taxes (Note 17)
Current 300 550 414
Future 175 60 77
475 610 491
Non-Controlling Interests (Note 13) 56 62 56
Net Income from Continuing Operations 1,071 1,230 1,000
Net Income from Discontinued Operations (Note 23) 28 - 52
Net Income 1,099 1,230 1,052
Preferred Share Dividends 22 22 22
Net Income Applicable to Common Shares 1,077 1,208 1,030
Net Income Applicable to Common Shares
Continuing operations 1,049 1,208 978
Discontinued operations 28 - 52
1,077 1,208 1,030
The accompanying notes to the consolidated financial statements are an integral
part of these statements.
72 CONSOLIDATED FINANCIAL STATEMENTS
TRANSCANADA PIPELINES LIMITED
CONSOLIDATED CASH FLOWS
Year ended December 31 (millions of dollars) 2006 2005 2004
Cash Generated from Operations
Net income 1,099 1,230 1,052
Depreciation 1,059 1,017 948
Gains on sale of assets, net of current tax (Note (11 ) (318 ) (204 )
7)
Income from equity investments in excess of (9 ) (71 ) (113 )
distributions received (Note 6)
Future income taxes (Note 17) 175 60 77
Non-controlling interests (Note 13) 56 62 56
Funding of employee future benefits in excess of (31 ) (9 ) (29 )
expense (Note 20)
Other 36 (21 ) (86 )
2,374 1,950 1,701
(Increase)/decrease in operating working capital (300 ) (48 ) 28
(Note 21)
Net cash provided by operations 2,074 1,902 1,729
Investing Activities
Capital expenditures (1,572 ) (754 ) (530 )
Acquisitions, net of cash acquired (Note 7) (470 ) (1,317 ) (1,516 )
Disposition of assets, net of current tax (Note 7) 23 671 410
Deferred amounts and other (95 ) 65 (12 )
Net cash used in investing activities (2,114 ) (1,335 ) (1,648 )
Financing Activities
Dividends on common and preferred shares (639 ) (608 ) (574 )
Distributions paid to non-controlling interests (50 ) (52 ) (65 )
Advances from/(repayments to) parent 40 (36 ) 35
Notes payable (repaid)/issued, net (495 ) 416 179
Long-term debt issued 2,107 799 1,090
Repayment of long-term debt (729 ) (1,113 ) (1,005 )
Long-term debt of joint ventures issued 56 38 217
Repayment of long-term debt of joint ventures (70 ) (80 ) (112 )
Common shares issued (Note 15) - 80 -
Partnership units of joint ventures issued - - 88
Net cash provided by/(used in) financing 220 (556 ) (147 )
activities
Effect of Foreign Exchange Rate Changes on Cash 9 11 (87 )
and Short-Term Investments
Increase/(Decrease) in Cash and Short-Term 189 22 (153 )
Investments
Cash and Short-Term Investments
Beginning of year 212 190 343
Cash and Short-Term Investments
End of year 401 212 190
The accompanying notes to the consolidated financial statements are an integral
part of these statements.
CONSOLIDATED FINANCIAL STATEMENTS 73
TRANSCANADA PIPELINES LIMITED
CONSOLIDATED BALANCE SHEET
December 31 2006 2005
(millions of dollars)
ASSETS
Current Assets
Cash and short-term investments 401 212
Accounts receivable 1,001 796
Inventories 392 281
Other 297 277
2,091 1,566
Long-Term Investments (Note 6) 71 400
Plant, Property and Equipment (Note 3) 21,487 20,038
Goodwill 281 57
Other Assets (Note 4) 1,978 2,052
25,908 24,113
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Notes payable (Note 18) 467 962
Accounts payable 1,582 1,536
Accrued interest 264 222
Current portion of long-term debt (Note 8) 616 393
Current portion of long-term debt of joint ventures (Note 9) 142 41
3,071 3,154
Deferred Amounts (Note 10) 1,029 1,196
Future Income Taxes (Note 17) 876 703
Long-Term Debt (Note 8) 10,887 9,640
Long-Term Debt of Joint Ventures (Note 9) 1,136 937
Preferred Securities (Note 12) 536 536
17,535 16,166
Non-Controlling Interests (Note 13) 366 394
Shareholders' Equity
Preferred shares (Note 14) 389 389
Common shares (Note 15) 4,712 4,712
Contributed surplus 277 275
Retained earnings 2,719 2,267
Foreign exchange adjustment (Note 16) (90 ) (90 )
8,007 7,553
Commitments, Contingencies and Guarantees (Note 22)
Subsequent Events (Note 24)
25,908 24,113
The accompanying notes to the consolidated financial statements are an integral
part of these statements.
On behalf of the Board:
,G763492.JPG
Harold N. Kvisle Harry G. Schaefer
Director Director
74 CONSOLIDATED FINANCIAL STATEMENTS
TRANSCANADA PIPELINES LIMITED
CONSOLIDATED RETAINED EARNINGS
Year ended December 31 2006 2005 2004
(millions of dollars)
Balance at beginning of year 2,267 1,653 1,185
Net income 1,099 1,230 1,052
Preferred share dividends (22 ) (22 ) (22 )
Common share dividends (625 ) (594 ) (562 )
2,719 2,267 1,653
The accompanying notes to the consolidated financial statements are an integral
part of these statements.
CONSOLIDATED FINANCIAL STATEMENTS 75
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, Pipelines and Energy,
each of which offers different products and services.
Pipelines
The Pipelines 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);
*
natural gas transmission systems in Alberta, owned by TransCanada Pipeline
Ventures Limited Partnership (Ventures LP), that supply natural gas to the
oil sands region of northern Alberta and to a petrochemical complex at
Joffre, Alberta;
*
a natural gas transmission system in Mexico extending from Naranjos,
Veracruz to Tamazunchale, San Luis Potosi (Tamazunchale);
*
a 61.7 per cent interest in Portland Natural Gas Transmission System
(Portland), which owns a pipeline system that extends from a point near East
Hereford, Quebec and delivers natural gas to the northeastern U.S.; and
*
a 50 per cent interest in TQM Services Limited Partnership (TQM), which owns
a pipeline system that connects with the Canadian Mainline and transports
natural gas in Quebec, from Montreal to Quebec City, and to the Portland
System.
Pipelines also holds the Company's investments in other natural gas pipelines
primarily in North America. TCPL's other significant pipeline investments
include:
*
a 50 per cent interest in Great Lakes Gas Transmission Limited Partnership
(Great Lakes), which owns a natural gas pipeline system that connects to the
Canadian Mainline and serves markets in Central Canada and Eastern and
Midwestern U.S.; and
*
a 44.5 per cent interest in Iroquois Gas Transmission System, L.P.
(Iroquois), which owns a natural gas pipeline system that connects with the
Canadian Mainline near Waddington, New York and delivers to customers in the
northeastern U.S.
In addition, Pipelines investigates and develops new natural gas and crude oil
pipelines in North America.
TCPL is the general partner of and consolidates its 13.4 per cent (at December
31, 2006) interest in TC PipeLines LP (PipeLines LP), which holds the following
investments:
*
a 50 per cent interest in Northern Border Pipeline Company (Northern
Border), which owns a pipeline system that transports natural gas from a
point near Monchy, Saskatchewan to the U.S. Midwest. TCPL expects to begin
operating Northern Border in April 2007. TCPL's effective ownership in
Northern Border is 6.7 per cent; and
*
owns or controls a 99 per cent interest in Tuscarora Gas Transmission
Company (Tucarora), which owns a pipeline system that transports natural gas
from Malin, Oregon to Wadsworth, Nevada. TCPL became the operator of
Tuscarora in December 2006. TCPL's effectively owns or controls 14.3 per
cent of Tuscarora, including one per cent owned directly by TCPL.
Energy
The Energy segment builds, owns and operates electrical power generation plants,
and sells electricity. Energy also holds the Company's investments in other
electrical power generation plants, natural gas storage facilities as well as
the Company's interest in liquefied natural gas (LNG) regassification projects
in North America. 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 plant in Burrillville, Rhode Island
(Ocean State Power);
*
natural gas-fired cogeneration plants in Alberta at Carseland, Redwater,
Bear Creek and MacKay River;
*
a natural gas-fired cogeneration plant near Saint John, New Brunswick
(Grandview);
76 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
*
a waste-heat fuelled power plant at the Cancarb facility in Medicine Hat,
Alberta (Cancarb);
*
a natural gas-fired cogeneration plant near Trois-Rivieres, Quebec
(Becancour); and
*
a natural gas storage facility near Edson, Alberta (Edson).
TCPL owns but does not operate:
*
a 48.7 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;
*
a 60 per cent interest in CrossAlta Gas Storage & Services Ltd. (CrossAlta),
which owns an underground natural gas storage facility near Crossfield,
Alberta; and
*
a 62 per cent interest in one (Baie-des-Sables) of six wind farms in Gaspe,
Quebec (Cartier Wind).
TCPL has long-term power purchase arrangements (PPAs) in place for:
*
100 per cent of the production of the Sundance A power facilities 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:
*
phase two of the six-phase Cartier Wind project in Quebec, owned 62 per cent
by TCPL;
*
a combined-cycle natural gas cogeneration plant in downtown Toronto,
Ontario, owned 50 per cent by TCPL (Portlands Energy); and
*
a natural gas-fired, combined-cycle power plant near Toronto, Ontario
(Halton Hills).
NOTE 1 ACCOUNTING POLICIES
The consolidated financial statements of the Company have been prepared by
Management in accordance with Canadian GAAP. Amounts are stated in Canadian
dollars unless otherwise indicated. Certain comparative figures have been
reclassified to conform with the current year's presentation.
Since a determination of many assets, liabilities, revenues and expenses is
dependent upon future events, the preparation of these consolidated financial
statements requires the use of estimates and assumptions which have been made
using careful judgment. In the opinion of Management, these consolidated
financial statements have been properly prepared within reasonable limits of
materiality and within the framework of the significant accounting policies
summarized below.
Basis of Presentation
The consolidated financial statements include the accounts of TCPL 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, Foothills and Trans Quebec & Maritimes
(TQM) 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, North Baja 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 11.
Revenue Recognition
Pipelines
In the Pipelines segment, revenues from the Canadian rate-regulated operations
are recognized in accordance with 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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 77
Energy
i) Power
The majority of revenues from the Power business are derived from the sale of
electricity from energy marketing 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 include the impact of energy derivative
contracts, including financial swaps, futures contracts and options.
ii) Natural Gas Storage
The majority of the revenues earned from natural gas storage are derived from
the sale of storage services recognized in accordance with the term of the gas
storage contracts. Revenues earned on the sale of gas held in inventory are
recorded in the month of delivery. These revenues include the impact of energy
derivative contracts, including financial swaps, futures contracts and options.
Dilution Gains
Dilution gains resulting from the sale of units by 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
Pipelines
Plant, property and equipment of the Pipelines 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 equipment 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.
Energy
Major power generation and natural gas storage plant, equipment and structures
in the Energy 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 power generation 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 plants 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.
Acquisitions and Goodwill
The Company accounts for business acquisitions using the purchase method of
accounting and, accordingly, the assets and liabilities of the acquired entities
are recorded at their estimated fair values at the date of acquisition. The
excess of the purchase price over the fair value of net assets acquired is
attributed to goodwill. Goodwill is not amortized for accounting purposes but is
amortized for tax purposes. Goodwill is re-evaluated on an annual basis for
impairment. Currently, all goodwill relates to Pipelines' operations.
Power Purchase Arrangements
PPAs are long-term contracts for the purchase or sale of power on a
predetermined basis. The initial payments for PPAs acquired are deferred and
amortized over the terms of the contracts, 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.
78 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Income Taxes
As prescribed by the regulators, the taxes payable method of accounting for
income taxes is used for tollmaking purposes for Canadian natural gas
transmission operations. Under the taxes payable method, it is not necessary to
provide for future income taxes. As permitted by Canadian GAAP, this method is
also used for accounting purposes, since there is reasonable expectation that
future taxes payable will be included in future costs of service and recorded in
revenues at that time. The liability method of accounting for income taxes is
used for the remainder of the Company's operations. Under this method, future
tax assets and liabilities are recognized for the future tax consequences
attributable to differences between the financial statement carrying amounts of
existing assets and liabilities and their respective tax bases. Future income
tax assets and liabilities are measured using enacted or substantively enacted
tax rates expected to apply to taxable income in the years in which temporary
differences are expected to be recovered or settled. Changes to these balances
are recognized in income in the period in which they occur.
Canadian income taxes are not provided on the unremitted earnings of foreign
investments 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 are recorded at their fair value at each balance sheet date.
Derivatives and other instruments must be designated and be effective to qualify
for hedge accounting. 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, after 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. Assessment of
effectiveness for those derivatives classified as hedges occurs at inception and
on an ongoing basis. 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. 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 an anticipated transaction is hedged
and the transaction is no longer probable to occur, the related deferred gains
or losses are recognized in income in the current period.
The recognition of gains and losses on the derivatives for the Canadian
Mainline, the Alberta System, the BC System and Foothills exposures is
determined through the regulatory process. The gains and losses on derivatives
accounted for as part of rate-regulated accounting that do not meet the criteria
for hedge accounting are deferred.
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.
No amount is recorded for asset retirement obligations relating to the regulated
natural gas transmission operation assets as it is not possible to make a
reasonable estimate of the fair value of the liability due to the inability to
determine the scope and timing of the asset retirements. Management believes it
is reasonable to assume that all retirement costs associated with the regulated
pipelines will be recovered through tolls in future periods.
For the hydroelectric power plant assets, as it is not possible to make a
reasonable estimate of the fair value of the liability due to the inability to
determine the scope and timing of the asset retirements, no amount has been
recorded for asset retirement obligations. For the Bruce
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 79
Power nuclear assets, as the lessor is responsible for decommissioning
liabilities under the lease agreement, no amount has been recorded for asset
retirement obligations.
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. Past service costs are amortized over
the expected average remaining service life of the employees. 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 net actuarial gains or losses 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. Employees have the
option of designating, in advance of the payout determination, some or all of
their payment to purchase shares through TCPL's stock savings plan. 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 SEGMENTED INFORMATION
Effective June 1, 2006, TCPL revised the composition and names of its reportable
business segments to Pipelines and Energy. The financial reporting of these
segments was aligned to reflect the internal organizational structure of the
Company. Pipelines principally comprises the Company's pipelines in Canada, the
U.S. and Mexico. Energy includes the Company's power operations, natural gas
storage business and LNG projects in Canada and the U.S. The segmented
information has been retroactively restated to reflect the changes in reportable
segments. These changes had no impact on consolidated income. These changes
resulted in increases to net income in the Energy segment of $5 million in 2005
and $2 million in 2004, and corresponding decreases to net income in the
Pipelines segment for the same years.
NET INCOME/(LOSS)(1)
Year ended December 31, 2006 (millions Pipelines Energy Corporate Total
of dollars)
Revenues 3,990 3,530 - 7,520
Plant operating costs and other (1,380 ) (1,024 ) (7 ) (2,411 )
Commodity purchases resold - (1,707 ) - (1,707 )
Depreciation (927 ) (131 ) (1 ) (1,059 )
1,683 668 (8 ) 2,343
Financial charges and non-controlling (767 ) - (139 ) (906 )
interests
Financial charges of joint ventures (69 ) (23 ) - (92 )
Income from equity investments 33 - - 33
Interest income and other 67 5 51 123
Gain on sale of assets 23 - - 23
Income taxes (410 ) (198 ) 133 (475 )
Net income from continuing operations 560 452 37 1,049
Net income from discontinued operations 28
Net Income Applicable to Common Shares 1,077
80 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Year ended December 31, 2005 (millions of Pipelines Energy Corporate Total
dollars)
Revenues 3,993 2,131 - 6,124
Plant operating costs and other (1,226 ) (595 ) (4 ) (1,825 )
Commodity purchases resold - (1,232 ) - (1,232 )
Depreciation (932 ) (85 ) - (1,017 )
1,835 219 (4 ) 2,050
Financial charges and non-controlling (788 ) (2 ) (131 ) (921 )
interests
Financial charges of joint ventures (57 ) (9 ) - (66 )
Income from equity investments 79 168 - 247
Interest income and other 25 5 33 63
Gains on sale of assets 82 363 - 445
Income taxes (497 ) (178 ) 65 (610 )
Net income from continuing operations 679 566 (37 ) 1,208
Net income from discontinued operations -
Net Income Applicable to Common Shares 1,208
Year ended December 31, 2004 (millions of
dollars)
Revenues 3,854 1,643 - 5,497
Plant operating costs and other (1,161 ) (451 ) (3 ) (1,615 )
Commodity purchases resold - (940 ) - (940 )
Depreciation (871 ) (77 ) - (948 )
1,822 175 (3 ) 1,994
Financial charges and non-controlling (848 ) (9 ) (81 ) (938 )
interests
Financial charges of joint ventures (59 ) (4 ) - (63 )
Income from equity investments 83 130 - 213
Interest income and other 8 14 37 59
Gains on sale of assets 7 197 - 204
Income taxes (429 ) (105 ) 43 (491 )
Net income from continuing operations 584 398 (4 ) 978
Net income from discontinued operations 52
Net Income Applicable to Common Shares 1,030
(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.
TOTAL ASSETS
December 31 (millions of dollars) 2006 2005
Pipelines 18,320 17,872
Energy 6,500 5,303
Corporate 1,088 938
25,908 24,113
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 81
GEOGRAPHIC INFORMATION
Year ended December 31 (millions of dollars) 2006 2005 2004
Revenues(1)
Canada - domestic 4,956 3,499 3,214
Canada - export 972 1,160 1,261
United States and other 1,592 1,465 1,022
7,520 6,124 5,497
(1)
Revenues are attributed to countries based on country of origin of product
or service.
December 31 (millions of dollars) 2006 2005
Plant, Property and Equipment
Canada 16,204 15,647
United States 5,109 4,306
Mexico 174 85
21,487 20,038
CAPITAL EXPENDITURES
Year ended December 31 (millions of dollars) 2006 2005 2004
Pipelines 560 244 221
Energy 976 506 305
Corporate 36 4 4
1,572 754 530
82 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 3 PLANT, PROPERTY AND EQUIPMENT
2006 2005
December 31 Cost Accumulated Net Cost Accumulated Net
(millions of dollars) Depreciation Book Value Depreciation Book Value
Pipelines
Canadian Mainline
Pipeline 8,850 3,911 4,939 8,701 3,665 5,036
Compression 3,343 1,181 2,162 3,341 1,066 2,275
Metering and other 346 136 210 359 134 225
12,539 5,228 7,311 12,401 4,865 7,536
Under construction 23 - 23 15 - 15
12,562 5,228 7,334 12,416 4,865 7,551
Alberta System
Pipeline 5,120 2,352 2,768 5,020 2,203 2,817
Compression 1,510 760 750 1,493 676 817
Metering and other 806 271 535 799 247 552
7,436 3,383 4,053 7,312 3,126 4,186
Under construction 98 - 98 25 - 25
7,534 3,383 4,151 7,337 3,126 4,211
GTN(1)
Pipeline 1,386 111 1,275 1,381 60 1,321
Compression 512 32 480 507 15 492
Metering and other 89 - 89 90 - 90
1,987 143 1,844 1,978 75 1,903
Under construction 17 - 17 18 - 18
2,004 143 1,861 1,996 75 1,921
Foothills
Pipeline 815 405 410 815 377 438
Compression 377 141 236 377 128 249
Metering and other 72 35 37 71 31 40
1,264 581 683 1,263 536 727
Joint Ventures and
Other
Great Lakes 1,187 600 587 1,181 566 615
Northern Border(2) 1,451 585 866 - - -
Other(3) 2,274 615 1,659 2,064 522 1,542
4,912 1,800 3,112 3,245 1,088 2,157
28,276 11,135 17,141 26,257 9,690 16,567
Energy(4)
Nuclear(5) 1,349 214 1,135 1,265 143 1,122
Natural gas 1,636 383 1,253 1,121 347 774
Hydro 592 21 571 598 9 589
Natural gas storage 344 22 322 45 20 25
Other 284 72 212 117 55 62
4,205 712 3,493 3,146 574 2,572
Under construction 809 - 809 872 - 872
5,014 712 4,302 4,018 574 3,444
Corporate 65 21 44 73 46 27
33,355 11,868 21,487 30,348 10,310 20,038
(1)
Gas Transmission Northwest System and North Baja system (collectively GTN).
(2)
In April 2006, PipeLines LP acquired an additional 20 per cent general
partnership interest in Northern Border, bringing its total general
partnership interest to 50 per cent. Northern Border became a jointly
controlled entity and TCPL commenced proportionately consolidating its
investment in Northern Border on a prospective basis. At December 31, 2006
the Company's effective ownership, net of non-controlling interests, is 6.7
per cent (2005 - 4.0 per cent) as a result of the Company holding a 13.4 per
cent interest in PipeLines LP.
(3)
Includes $4 million of plant under construction (2005 - $85 million).
(4)
Certain power generation facilities are accounted for as assets under
operating leases. At December 31, 2006, the net book value of these
facilities was $81 million (2005 - $87 million). In 2006, revenues of $13
million (2005 - $23 million) were recognized through the sale of electricity
under the related PPAs.
(5)
Includes assets under capital lease relating to Bruce Power.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 83
NOTE 4 OTHER ASSETS
December 31 (millions of dollars) 2006 2005
PPAs(1) 767 825
Pension and other benefit plans 268 304
Regulatory assets 171 169
Derivative contracts 142 209
Hedging deferrals 152 118
Loans and advances(2) 121 91
Debt issue costs 77 72
Deferred project development costs(3) 70 25
Other 210 239
1,978 2,052
(1)
The following amounts related to the PPAs are included in the consolidated
financial statements.
2006 2005
December 31 Cost Accumulated Net Cost Accumulated Net
(millions of Amortization Book Value Amortization Book Value
dollars)
PPAs 915 148 767 915 90 825
The amortization expense for the PPAs was $58 million for the year ended
December 31, 2006 (2005 - $24 million; 2004 - $24 million). The expected
amortization expense in each of the next five years approximates: 2007 - $58
million; 2008 - $58 million; 2009 - $58 million; 2010 - $58 million; and
2011 - $57 million.
(2)
The December 31, 2006 balance includes a $118 million loan (2005 - $87
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 (MGP) project. The ability to recover this investment remains
dependent upon the successful outcome of the project.
(3)
The December 31, 2006 balance includes $39 million (2005 - $6 million) and
$31 million (2005 - $19 million) related to the Keystone oil project and the
Broadwater LNG project respectively.
84 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 5 JOINT VENTURE INVESTMENTS
TCPL's Proportionate Share
Income Before Income Taxes Net Assets
Year ended December 31 December 31
(millions of Ownership 2006 2005 2004 2006 2005
dollars) Interest(1)
Pipelines
Great Lakes 50.0% 69 73 86 370 375
Iroquois 44.5% (2) 25 29 28 194 190
Trans Quebec & 50.0% 11 13 13 75 73
Maritimes
Northern Border 6.7% (3) 47 - - 634 -
Other Various (4) 11 15 12 26 67
Energy
Bruce A 48.7% (5) 75 19 - 916 563
Bruce B 31.6% (5) 140 5 - 425 434
ASTC Power 50.0% (6) - - - 82 88
Partnership
Power LP (7) - 25 32 - -
CrossAlta 60.0% 64 31 20 36 30
Portlands Energy 50.0% (8) - - - 90 -
Centre
Cartier Wind 62.0% (9) 2 - 172
444 210 191 3,020 1,820
(1)
All ownership interests are as at December 31, 2006. Changes due to the
February 22, 2007 acquisition of ANR are discussed in Note 24 "Subsequent
Events".
(2)
In June 2005, the Company acquired an additional 3.5 per cent ownership
interest in Iroquois.
(3)
In April 2006, PipeLines LP acquired an additional 20 per cent general
partnership interest in Northern Border, bringing its total general
partnership interest to 50 per cent. Northern Border became a jointly
controlled entity and TCPL commenced proportionately consolidating its
investment in Northern Border on a prospective basis. At December 31, 2006,
the Company's effective ownership, net of non-controlling interests, was 6.7
per cent (2005 - 4.0 per cent) as a result of the Company holding a 13.4
per cent interest in PipeLines LP.
(4)
In December 2006, PipeLines LP acquired an additional 49 per cent general
partnership interest in Tuscarora. As a result of this transaction,
PipeLines LP owns or controls 99 per cent of Tuscarora. PipeLines LP began
consolidating its investment in Tuscarora at the date of this additional
acquisition. At December 31, 2006, the Company effectively owned or
controled an aggregate 14.3 per cent (2005 - 7.6 per cent) interest in
Tuscarora of which 13.3 per cent was held indirectly through TCPL's 13.4 per
cent interest in PipeLines LP and the remaining one per cent was owned
directly.
(5)
TCPL acquired a 47.4 per cent ownership interest in Bruce A on October 31,
2005. The Company increased its ownership interest in Bruce A to 48.7 per
cent during 2006 (December 31, 2005 - 47.9 per cent) 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.
(6)
The Company has a 50 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 per cent ownership interest in the Partnership are
effectively transferred to TCPL.
(7)
In April 2004, the Company's interest in TransCanada Power, L.P. (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.
(8)
Portlands Energy is a limited partnership between Ontario Power Generation
and TCPL with both parties having a 50 per cent interest.
(9)
TCPL proportionately consolidates 62 per cent of the assets, liabilities,
revenues and expenses of its Cartier Wind project. Baie-des-Sables began
operating in November 2006.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 85
Summarized Financial Information of Joint Ventures
Year ended December 31 (millions of dollars) 2006 2005 2004
Income
Revenues 1,379 687 572
Plant operating costs and other (689 ) (328 ) (240 )
Depreciation (162 ) (93 ) (90 )
Financial charges and other (84 ) (56 ) (51 )
Proportionate share of income before income taxes of joint 444 210 191
ventures
Year ended December 31 (millions of dollars) 2006 2005 2004
Cash Flows
Operating activities 645 346 270
Investing activities (641 ) (133 ) (287 )
Financing activities(1) (31 ) (152 ) 35
Effect of foreign exchange rate changes on cash and short-term 9 (1 ) (5 )
investments
Proportionate share of (decrease)/increase in cash and (18 ) 60 13
short-term investments of joint ventures
(1)
Financing activities include cash outflows resulting from distributions paid
to TCPL of $470 million (2005 - $201 million; 2004 - $158 million) and cash
inflows resulting from capital contributions paid by TCPL of $452 million
(2005 - $92 million and 2004 - nil).
December 31 (millions of dollars) 2006 2005
Balance Sheet
Cash and short-term investments 127 123
Other current assets 304 281
Plant, property and equipment 4,110 2,707
Other assets/(deferred amounts) (net) 78 (45 )
Current liabilities (443 ) (291 )
Long-term debt (1,136 ) (937 )
Future income taxes (20 ) (18 )
Proportionate share of net assets of joint ventures 3,020 1,820
86 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 6 LONG-TERM INVESTMENTS
TCPL's Share
Distributions Income from Equity Investments
from Equity Investments Equity Investments December 31
Year ended December 31 Year ended December 31
(millions of Ownership 2006 2005 2004 2006 2005 2004 2006 2005
dollars) Interest
Pipelines
Northern Border (1) 13 76 79 13 61 65 - 315
TransGas 46.5% (2) 7 6 8 11 11 11 66 62
Other Various 4 10 13 9 7 7 5 23
Energy
Bruce B 31.6% (3) - 84 - - 168 130 - -
24 176 100 33 247 213 71 400
(1)
In April 2006, PipeLines LP acquired an additional 20 per cent general
partnership interest in Northern Border, bringing its total general
partnership interest to 50 per cent. Northern Border became a jointly
controlled entity and TCPL commenced proportionately consolidating its
investment in Northern Border on a prospective basis.
(2)
TransGas de Occidente S.A. (TransGas).
(3)
The Company proportionately consolidated its 31.6 per cent ownership
interest in Bruce B, on a prospective basis, effective October 31, 2005.
NOTE 7 ACQUISITIONS AND DISPOSITIONS
Acquisitions
Pipelines
Tuscarora
In December 2006, PipeLines LP acquired an additional 49 per cent controlling
general partner interest in Tuscarora, subject to closing adjustments, for
US$100 million, with the option to purchase Sierra Pacific Resources' remaining
one per cent interest in Tuscarora in approximately one year. In addition, the
Company indirectly assumed US$37 million of debt. The purchase price was
allocated US$79 million to goodwill, US$37 million to long-term debt, and the
balance primarily to plant, property and equipment. Factors that contributed to
goodwill include opportunities for expansion and a stronger competitive
position.
As a result of this transaction, PipeLines LP owns or controls 99 per cent of
Tuscarora. At December 31, 2006, TCPL's effective ownership in Tuscarora, net of
non-controlling interests, was 14.3 per cent as a result of it holding a 13.4
per cent interest in PipeLines LP, and its direct ownership of the remaining one
per cent of Tuscarora. PipeLines LP began consolidating its investment in
Tuscarora at the date of acquisition. In connection with this transaction,
TransCanada became the operator of Tuscarora in December 2006.
Northern Border Pipeline
In April 2006, PipeLines LP acquired an additional 20 per cent general
partnership interest in Northern Border for US$307 million, in addition to
indirectly assuming US$122 million of debt. The purchase price was allocated
US$114 million to goodwill, US$122 million to long-term debt and the balance
primarily to plant, property and equipment. Factors that contributed to goodwill
include opportunities for expansion and a stronger competitive position.
This transaction increased PipeLines LP's total general partnership interest in
Northern Border to 50 per cent. At December 31, 2006, TCPL's effective
ownership, net of non-controlling interests, was 6.7 per cent as a result of it
holding a 13.4 per cent interest in PipeLines LP. PipeLines LP proportionately
consolidated its 50 per cent interest in Northern Border at the date of
acquisition. In connection with this transaction, TransCanada expects to become
the operator of Northern Border in April 2007.
Energy
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. The PPA
terminates December 2021.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 87
Bruce Power
In October 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 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. As part of this
reorganization, both Bruce A and Bruce B became jointly controlled entities and
TCPL commenced proportionately consolidating its investment in both Bruce A and
Bruce B, on a prospective basis, effective October 31, 2005. At December 31,
2006 the Company held 48.7 per cent and 31.6 per cent interests in Bruce A and
Bruce B, respectively.
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.
Dispositions
The pre-tax gains on sale of assets are comprise the following.
Year ended December 31 (millions of dollars) 2006 2005 2004
Gain on sale of Northern Border Partners, L.P. 23 - -
interest
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
23 445 204
(1)
PT Paiton Energy Company (Paiton Energy); Millennium Pipeline project
(Millennium).
Northern Border Partners, L.P. Interest
In April 2006, TCPL sold its 17.5 per cent general partner interest in Northern
Border Partners L.P. for net proceeds of $33 million (US$30 million), and
recognized an after-tax gain on sale of $13 million. The net gain was recorded
in the Pipelines segment and the Company recorded a $10 million income tax
charge, including $12 million of current income tax expense, on this
transaction.
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 Energy 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 $539 million (US$403 million) plus closing adjustments of $17
million (US$13 million) and recognized an after-tax gain on sale of $15 million.
The net gain was recorded in the Energy segment and the Company recorded a $10
million income tax charge.
At a special meeting held on April 29, 2004, Power LP's unitholders approved an
amendment to the terms of the Power LP Partnership Agreement to remove Power
LP's obligation to redeem all units not owned by TCPL at June 30, 2017. TCPL was
required to fund this redemption, thus the removal of Power LP's obligation
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 approximately 11 per cent ownership interest in
Paiton Energy to subsidiaries of The Tokyo Electric Power Company for gross
proceeds of $122 million (US$103 million) and recognized an after-tax gain on
sale of $115 million. The net gain was recorded in the Energy 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 Pipelines 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 owned 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.
88 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 8 LONG-TERM DEBT
2006 2005
Maturity Dates Outstanding Weighted Outstanding Weighted
December 31(1) Average December 31(1) Average
Interest Interest
Rate(2) Rate(2)
TRANSCANADA PIPELINES LIMITED
First Mortgage Pipe Line Bonds
Pounds Sterling (2006 and 2005 2007 57 16.5% 50 16.5%
- #25)
Debentures
Canadian dollars 2008 to 2020 1,355 10.9% 1,355 10.9%
U.S. dollars (2006 and 2005 - 2012 to 2021 699 9.5% 700 9.5%
US$600)
Medium-Term Notes
Canadian dollars 2007 to 2031 3,848 6.0% 3,228 6.4%
U.S. dollars (2006 - US$2,223; 2009 to 2036 2,590 5.8% 2,146 5.8%
2005 - US$1,841)
Subordinated Debentures
U.S. dollars (2005 - US$57) - 66 9.1%
8,549 7,545
NOVA GAS TRANSMISSION LTD.
Debentures and Notes
Canadian dollars 2007 to 2024 564 11.6% 585 11.6%
U.S. dollars (2006 and 2005 - 2012 to 2023 437 8.2% 437 8.2%
US$375)
Medium-Term Notes
Canadian dollars 2007 to 2030 609 7.1% 665 7.2%
U.S. dollars (2006 and 2005 - 2026 38 7.5% 38 7.5%
US$33)
1,648 1,725
GAS TRANSMISSION NORTHWEST
CORPORATION
Unsecured Debentures and Notes
U.S. Dollars (2006 and 2005 - 2010 to 2035 466 5.3% 466 5.3%
US$400)
TC PIPELINES, LP
Unsecured Loan
U.S. dollars (2006 - US$397; 2007 463 5.4% 16 5.6%
2005 - US$14)
PORTLAND NATURAL GAS TRANSMISSION
SYSTEM
Senior Secured Notes
U.S. dollars (2006 - US$226; 2018 263 5.9% 281 5.9%
2005 - US$241)
TUSCARORA GAS TRANSMISSION COMPANY
Senior Unsecured Notes
U.S. dollars (2006 - US$74) 2010 to 2012 86 7.2%
OTHER
Secured Notes
U.S. dollars (2006 - US$24) 2011 28 7.3%
11,503 10,033
Less: Current Portion of Long-Term 616 393
Debt
10,887 9,640
(1)
Amounts outstanding are stated in millions of Canadian dollars; amounts
denominated in currencies other than Canadian dollars are stated in
millions.
(2)
Weighted average interest rates are stated as at the respective outstanding
dates. The effective weighted average interest rates resulting from swap
agreements are as follows: TCPL's U.S. dollar medium-term notes - 5.8 per
cent (2005 - 5.9 per cent) and TCPL's U.S. dollar subordinated debentures in
2005 - 9.0 per cent.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 89
Principal Repayments
Principal repayments on the long-term debt of the Company approximate: 2007 -
$616 million; 2008 - $549 million; 2009 - $847 million; 2010 - $653 million; and
2011 - $883 million.
Debt Shelf Programs
At December 31, 2006, $500 million of medium-term note debentures were available
for issue under a debt shelf program in Canada and US$500 million of debt
securities were available for issue under a debt shelf program in the U.S. Under
the Canadian debt shelf program, the Company issued $300 million of five-year
medium-term notes bearing interest of 4.3 per cent in January 2006 and $400
million of ten-year medium-term notes bearing interest of 4.65 per cent in
October 2006. In March 2006, the Company issued US$500 million of 30-year
medium-term notes bearing interest of 5.85 per cent under the U.S. base shelf
program. Both the Canadian and U.S. debt shelf programs expired in January 2007.
PipeLines LP
In April 2006, PipeLines LP borrowed US$307 million under its unsecured credit
facility to finance the cash portion of the purchase price of its acquisition of
an additional 20 per cent interest in Northern Border. In December 2006, the
credit facility was repaid in full and replaced with a US$410 million syndicated
revolving credit and term loan agreement, of which US$397 million was drawn as
at December 31, 2006. Borrowings under the credit and term loan agreement will
bear interest at the London interbank offered rate plus an applicable margin.
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.
Debentures
Debentures issued by Nova Gas Transmission Ltd. (NGTL), 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, 2006.
Medium-Term Notes
On February 15, 2007, the Company retired $275 million of 6.05 per cent medium
term notes.
Medium-term notes issued by NGTL, 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.
Financial Charges
Year ended December 31 (millions of dollars) 2006 2005 2004
Interest on long-term debt 849 849 864
Interest on short-term debt 23 23 7
Capitalized interest (60 ) (24 ) (11 )
Amortization and other financial charges 16 (11 ) -
828 837 860
The Company made interest payments of $771 million for the year ended December
31, 2006 (2005 - $838 million; 2004 - $864 million).
90 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 9 LONG-TERM DEBT OF JOINT VENTURES
2006 2005
Maturity Dates Outstanding Weighted Outstanding Weighted
December 31(1) Average December 31(1) Average
Interest Interest
Rate(2) Rate(2)
Great Lakes
Senior Unsecured Notes
(2006 and 2005 - US$230) 2011 to 2030 262 7.8% 268 7.9%
Bruce Power
Capital Lease Obligations 2018 250 7.5% 254 7.5%
Iroquois
Senior Unsecured Notes
(2006 and 2005 - US$165) 2010 to 2027 192 7.5% 192 7.5%
Bank Loan
(2006 - US$15; 2005 - US$25) 2008 17 6.2% 29 4.3%
Trans Quebec & Maritimes
Bonds 2009 to 2010 138 6.0% 138 6.0%
Term Loan 2010 32 4.4% 29 3.5%
Northern Border
Senior Unsecured Notes
(2006 - US$316) 2007 to 2021 368 6.9% - -
Other 2007 to 2012 19 3.8% 68 6.1%
1,278 978
Less: Current Portion of Long-Term 142 41
Debt of Joint Ventures
1,136 937
(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, 2006, the effective weighted average interest rates
resulting from swap agreements are as follows: Iroquois bank loan - 6.9 per
cent (2005 - 5.4 per cent).
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: 2007 - $134 million; 2008 - $17 million; 2009 - $192 million; 2010
- $246 million; and 2011 - $21 million.
The Company's proportionate share of principal payments resulting from the
capital lease obligations of Bruce Power approximates: 2007 - $8 million; 2008 -
$9 million; 2009 - $11 million; 2010 - $13 million; and 2011 - $15 million.
Financial Charges of Joint Ventures
Year ended December 31 (millions of dollars) 2006 2005 2004
Interest on long-term debt 67 60 59
Interest on capital lease obligations 19 3 -
Short-term interest and other financial charges 3 1 2
Deferrals and amortization 3 2 2
92 66 63
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 91
The Company's proportionate share of the interest payments of joint ventures was
$73 million for the year ended December 31, 2006 (2005 - $62 million; 2004 - $58
million).
The Company's proportionate share of interest payments from the capital lease
obligations of Bruce Power was $20 million for the year ended December 31, 2006
(2005 - $3 million; 2004 - 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 10 DEFERRED AMOUNTS
December 31 (millions of dollars) 2006 2005
Regulatory liabilities 386 597
Derivative contracts 254 212
Hedging deferrals 84 72
Employee benefit plans 195 168
Asset retirement obligations 45 33
Deferred revenue 32 42
Other 33 72
1,029 1,196
NOTE 11 REGULATED BUSINESSES
Regulatory assets and liabilities represent future revenues which are expected
to be recovered from or refunded to customers in future periods as a result of
the rate-setting process associated with certain costs and revenues, incurred in
the current period or in prior periods, and under or over collection of revenues
in the current or prior periods.
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 regulated
pipelines are typically set through a process that involves filing of 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, Foothills and 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.
Canadian Mainline
In March 2006, TCPL and its Canadian Mainline shippers entered into a negotiated
settlement that addressed all elements of the Canadian Mainline's 2006 tolls
(2006 Settlement). The 2006 Settlement was approved by the NEB in April 2006.
Pursuant to the 2006 Settlement, the cost of capital in the Canadian Mainline's
2006 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 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.
92 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Under the 2006 Settlement, the Canadian Mainline's operating, maintenance and
administrative (OM&A) costs for 2006 were fixed and variances between the 2006
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 2006 was 8.88 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 of 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 ROE 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 2006 was 8.93 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, the Foothills System and the TQM
System. 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 8.88 per cent in 2006. The deemed equity
component of each of the pipelines' capital structure was set at 36 per cent for
the BC System and Foothills and 30 per cent for TQM for 2006.
U.S. Regulated Operations
TCPL's wholly-owned and partially-owned U.S. pipelines 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 North Baja 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
the 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 remained in effect through December 2006, was approved by the
FERC in 1996. In June 2006, Gas Transmission Northwest Corporation filed a
general rate case under Section 4 of the Natural Gas Act of 1938. New rates on
the Gas Transmission Northwest System went into effect on January 1, 2007,
subject to refund, upon approval of final rates by the FERC. The FERC rate case
hearing is scheduled to commence in October 2007. Rates for capacity on North
Baja were established in 2002 in the FERC's initial order certificating
construction and operations of North Baja.
Portland
In 2003, Portland received final approval from the 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.
Northern Border
As required by the provisions of the settlement of its last rate case, on
November 1, 2005, Northern Border filed a rate case with the FERC. In December
2005, the FERC issued an order accepting the proposed rates but suspended their
effectiveness until May 1, 2006. Since May 1, 2006, the new rates were collected
subject to refund. The settlement was reached between Northern Border Pipeline
and its customers and was supported by the FERC trial staff. The FERC approved
the Northern Border settlement in November 2006.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 93
Regulatory Assets and Liabilities
Year ended December 31 (millions of dollars) 2006 2005 Remaining
Recovery/
Settlement
Period
(years)
Regulatory Assets
Unrealized losses on derivatives - Canadian Mainline(1) 44 43 1 - 4
Unrealized losses on derivatives - BC System(1) 33 33 7
Foreign exchange reserve - Alberta System(2) 33 32 23
Phase II Preliminary Expenditures - Foothills(3) 20 23 9
Transitional other benefit obligations - Canadian Mainline(4) 9 10 10
Other 32 28 n/a
Total Regulatory Assets (Other Assets) 171 169
Regulatory Liabilities
Operating and debt service regulatory liabilities(5) 70 273 1
Foreign exchange on long-term debt - Canadian Mainline(6) 195 202 1 - 41
Foreign exchange on long-term debt - Alberta System(6) 60 59 6 - 23
Foreign exchange on long-term debt - BC System(6) 19 20 7
Post-retirement benefits other than pension - Gas Transmission 19 17 n/a
Northwest System(7)
Other 23 26 n/a
Total Regulatory Liabilities (Deferred Amounts) 386 597
(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 the Canadian Mainline
and the BC System related foreign debt instruments. The Canadian Mainline
interest rate swaps were entered into as a result of the Mainline 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-regulated accounting, Canadian GAAP would require the inclusion of
these fair value losses in the operating results of the Canadian Mainline as
they were not documented as hedges for accounting purposes. In the absence
of rate-regulated accounting, pre-tax operating results of the Canadian
Mainline for 2006 would have been $1 million lower (2005 - $8 million
lower). Effective January 1, 2006, the BC System cross-currency swap has
been designated and is effective to qualify for hedge accounting. The
regulatory asset with respect to the BC System represents the unrealized
losses for the ineffective period of the derivative from inception to
December 31, 2005. In the absence of rate-regulated accounting, pre-tax
operating results would have been the same (2005 - $2 million lower) for 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.
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.
(3)
Phase II Preliminary Expenditures are costs incurred by Foothills prior to
1981 related to development of Canadian facilities to deliver Alaskan 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-regulated accounting, GAAP would require these
costs to be expensed in the year incurred, increasing pre-tax operating
results in 2006 by $3 million (2005 - $2 million higher).
(4)
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-regulated accounting, pre-tax operating results would have
been $1 million higher (2005 - $1 million higher).
(5)
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 immediate following calendar
year. In the absence of rate-regulated accounting, GAAP would have required
the inclusion of these variances in the operating results of the year in
which the variances were incurred. Pre-tax operating results for 2006 and
2005 are the same as would have been the case in the absence of
rate-regulated accounting.
(6)
The foreign exchange on long-term debt of the Canadian Mainline, the Alberta
System and the BC System represent the variance resulting from revaluing
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 or refunded through the determination of future
tolls. In the absence of rate-regulated accounting, GAAP would have required
the inclusion
94 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
(7)
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-regulated accounting, GAAP would require the inclusion of this amount
in operating results and pre-tax operating results in 2006 would have been
$2 million higher than reported (2005 - $1 million higher).
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-regulated
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 $1,355 million at December 31, 2006 (2005 -
$1,619 million) would have been recorded and would be recoverable from future
revenues. In the second quarter of 2006, a reduction in enacted Canadian federal
and provincial corporate future income tax rates resulted in a decrease of $182
million to this unrecorded future income tax liability. 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 12 PREFERRED SECURITIES
The US$460 million (2006 and 2005 - $536 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 13 NON-CONTROLLING INTERESTS
The Company's non-controlling interests included in the consolidated balance
sheet are as follows.
December 31 (millions of dollars) 2006 2005
Non-controlling interest in PipeLines LP 287 318
Other 79 76
366 394
The Company's non-controlling interests included in the consolidated income
statement are as follows.
Year ended December 31 (millions of dollars) 2006 2005 2004
Non-controlling interest in PipeLines LP 43 52 46
Other 13 10 10
56 62 56
Non-Controlling Interest in PipeLines LP and Other
As at December 31, 2006, the non-controlling interest in PipeLines LP represents
the 86.6 per cent of the limited partnership held by the limited partners. Other
non-controlling interests include the 38.3 per cent non-controlling interest in
Portland held by an unrelated partner. Revenues received from PipeLines LP and
Portland with respect to services provided by TCPL for the year ended December
31, 2006 were $1 million (2005 - $1 million; 2004 - $1 million) and $6 million
(2005 - $6 million; 2004 - $4 million), respectively.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 95
NOTE 14 PREFERRED SHARES
December 31 Number of Dividend Rate Redemption 2006 2005
Shares Per Share Price Per
Share
(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 issuer may redeem the shares at $50 per
share.
NOTE 15 COMMON SHARES
Number of Shares Amount
(thousands) (millions of
dollars)
Outstanding at January 1, and December 31, 2004 480,668 4,632
Issued for cash or cash equivalent 2,676 80
Outstanding at December 31, 2005 and 2006 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, 2006, under the most restrictive
provisions, approximately $1.9 billion (2005 - $1.7 billion) was available for
the payment of dividends on common shares.
Dividend Reinvestment and Share Purchase Plan
In January 2007, the Board of Directors of TransCanada Corporation (TransCanada)
authorized the issue of common shares from treasury at a discount of two per
cent to participants in TransCanada's Dividend Reinvestment and Share Purchase
Plan (DRP). Under this plan, eligible TCPL preferred shareholders may reinvest
their dividends and make optional cash payments to obtain additional TransCanada
common shares. Previously, shares purchased through the DRP were purchased by
TransCanada on the open market and provided to DRP participants at cost.
Commencing with the dividend payable in April 2007, the DRP shares will be
provided to the participants at a two per cent discount to the average market
price in the five days before dividend payment. TransCanada reserves the right
to alter the discount or return to purchasing shares on the open market at any
time.
NOTE 16 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 exposure that results from these activities. The use
of derivatives is subject to the Company's overall risk management policies and
procedures.
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.
This information is provided by RNS
The company news service from the London Stock Exchange
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