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RNS Number:6365T
TransCanada Pipelines Ld
03 November 2005
6-K
0000099070
xxxxxxx
09/30/2005
NYSE
EDGAR Advantage Service Team
(800) 688 - 1933
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 6-K
REPORT OF FOREIGN PRIVATE ISSUER
PURSUANT TO RULE 13a-16 OR 15d-16 OF
THE SECURITIES EXCHANGE ACT OF 1934
For the month of November 2005
COMMISSION FILE No. 1-8887
TransCanada PipeLines Limited
(Translation of Registrant's Name into English)
450 - 1 Street S.W., Calgary, Alberta, T2P 5H1, Canada
(Address of Principal Executive Offices)
Indicate by check mark whether the registrant files or will file annual reports
under cover of Form 20-F or Form 40-F
Form 20-F o Form 40-F y
Indicate by check mark if the registrant is submitting the Form 6-K in paper as
permitted by Regulation S-T
Rule 101(b)(1): o
Indicated by check mark if the registrant is submitting the Form 6-K in paper as
permitted by Regulation S-T
Rule 101(b)(7): o
Indicate by check mark whether the registrant by furnishing the information
contained in this Form is also thereby furnishing the information to the
Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.
Yes o No y
--------------------------------------------------------------------------------
I
The documents listed below in this Section and filed as Exhibits 13.1 to 13.3
and 99.1 to this Form 6-K are hereby filed with the Securities and Exchange
Commission for the purpose of being and hereby are incorporated by reference
into Registration Statement on Form F-9 (Reg. No. 333-121265) under the
Securities Act of 1933, as amended.
13.1 Management's Discussion and Analysis of Financial Condition and
Results of Operations of the registrant as at and for the period
ended September 30, 2005.
13.2 Consolidated comparative interim unaudited financial statements of
the registrant for the period ended September 30, 2005 (included in
the registrant's Third Quarter 2005 Quarterly Report).
13.3 U.S. GAAP reconciliation of the consolidated comparative interim
unaudited financial statements of the registrant contained
in the registrant's Third Quarter 2005 Quarterly Report.
99.1 Schedule of earnings coverage calculations at September 30, 2005.
II
The document listed below in this Section and in the Exhibit Index to this Form
6-K is hereby filed with the Securities and Exchange Commission.
99.2 Comfort letter of KPMG LLP dated November 2, 2005.
2
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.
TRANSCANADA PIPELINES LIMITED
By: /s/ Russell K. Girling
Russell K. Girling
Executive Vice-President, Corporate
Development and Chief Financial Officer
By: /s/ Lee G. Hobbs
Lee G. Hobbs
Vice-President and Controller
November 2, 2005
3
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EXHIBIT INDEX
13.1 Management's Discussion and Analysis of Financial Condition and
Results of Operations of the registrant as at and for the period
ended September 30, 2005.
13.2 Consolidated comparative interim unaudited financial statements of
the registrant for the period ended September 30, 2005 (included
in the registrant's Third Quarter 2005 Quarterly Report).
13.3 U.S. GAAP reconciliation of the consolidated comparative interim
unaudited financial statements of the registrant contained
in the registrant's Third Quarter 2005 Quarterly Report.
31.1 Certification of Chief Executive Officer pursuant
to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2 Certification of Chief Financial Officer pursuant to Section 302
of the Sarbanes-Oxley Act of 2002.
32.1 Certification of Chief Executive Officer regarding Periodic
Report containing Financial Statements.
32.2 Certification of Chief Financial Officer regarding Periodic
Report containing Financial Statements.
99.1 Schedule of earnings coverage calculations at September 30, 2005.
99.2 Comfort letter of KPMG LLP dated November 2, 2005.
4
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Exhibit 13.1
TRANSCANADA PIPELINES LIMITED -THIRD QUARTER 2005
Quarterly Report
Management's Discussion and Analysis
Management's discussion and analysis (MD&A) dated October 31, 2005 should be
read in conjunction with the accompanying unaudited consolidated financial
statements of TransCanada PipeLines Limited (TCPL or the company) for the nine
months ended September 30, 2005. It should also be read in conjunction with the
MD&A contained in TCPL's 2004 Annual Report for the year ended December 31, 2004
as well as the restated 2004 audited consolidated financial statements.
Additional information relating to TCPL, including the company's Annual
Information Form and continuous disclosure documents, is available on SEDAR at
www.sedar.com under TransCanada PipeLines Limited. Amounts are stated in
Canadian dollars unless otherwise indicated.
--------------------------------------------------------------------------------
THIRD QUARTER REPORT 2005
TCPL
Results of Operations
Consolidated
Segment Results-at-a-Glance
(unaudited) Three months ended September 30 Nine months ended September 30
(millions of dollars except per share amounts) 2005 2004 2005 2004
Gas Transmission Net Earnings
Excluding gains 148 134 475 422
Gain related to PipeLines LP - - 49 -
Gain related to Millennium - - - 7
148 134 524 429
Power Net Earnings
Excluding gains 99 51 171 178
Gains related to Power LP 193 - 193 187
292 51 364 365
Corporate (12) 7 (29) -
Net Income Applicable to Common Shares
Continuing Operations (1) 428 192 859 794
Discontinued Operations - 52 - 52
428 244 859 846
--------------------
(1)Net Income Applicable to Common Shares from
Continuing Operations is comprised of:
Excluding gains 235 192 617 600
Gains related to PipeLines LP, Power LP and 193 - 242 194
Millennium
428 192 859 794
TCPL's net income applicable to common shares for third quarter 2005 was $428
million compared to $244 million for the same period in 2004. Net income
applicable to common shares for third quarter 2004 included net income from
discontinued operations of $52 million, reflecting income recognized on the
initially deferred gains relating to the disposition of the company's Gas
Marketing business in 2001.
Net income applicable to common shares from continuing operations (net earnings)
for third quarter 2005 of $428 million increased by $236 million compared to
$192 million for third quarter 2004. This increase was due to significantly
higher net earnings from the Power business, primarily resulting from an
after-tax gain of $193 million from the sale of the company's interest in
TransCanada Power, L.P. (Power LP) to EPCOR Utilities Inc. (EPCOR).
2
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Excluding the $193 million gain related to the sale of Power LP, net earnings
for third quarter 2005 increased $43 million compared to third quarter 2004, to
$235 million. This was due to increases of $48 million in net earnings from the
Power business and $14 million in net earnings from the Gas Transmission
business for third quarter 2005, partially offset by an increase of $19 million
in net expenses in the Corporate segment. The increase in Power's net earnings
was primarily due to higher equity income from Bruce Power L.P. (Bruce Power)
and higher operating and other income from Eastern Operations as a result of
contributions from TransCanada Hydro Northeast, Inc. (TC Hydro), which holds the
assets acquired from USGen New England, Inc. (USGen) in April 2005. These
increases were partially offset by lower operating and other income from Western
Operations. The increase in net earnings from the Gas Transmission business was
primarily due to $14 million generated from the Gas Transmission Northwest
System and the North Baja System (collectively GTN), which were acquired by TCPL
on November 1, 2004. Corporate's net expenses increased in third quarter 2005
compared to third quarter 2004 due to a $12 million after-tax adjustment
recorded in third quarter 2004 resulting from the release of previously
established restructuring provisions as well as higher interest expense on
higher average long-term debt and commercial paper balances in 2005.
TCPL's net income applicable to common shares for the nine months ended
September 30, 2005 was $859 million compared to $846 million for the comparable
period in 2004. Net income applicable to common shares for the nine months
ended September 30, 2004 included net income from discontinued operations of $52
million.
TCPL's net earnings for the nine months ended September 30, 2005 were $859
million compared to $794 million for the comparable period in 2004. Net
earnings for the nine months ended September 30, 2005 included after-tax gains
of $193 million related to the sale of the company's interest in Power LP and
$49 million related to the sale of TC PipeLines, LP (PipeLines LP) units, while
net earnings for the nine months ended September 30, 2004 included after-tax
gains of $187 million related to the sale of the ManChief and Curtis Palmer
assets to Power LP and the recognition of dilution gains resulting from a
reduction in TCPL's ownership interest in Power LP and other previously deferred
gains, as well as a $7 million after-tax gain on sale of the company's equity
interest in the Millennium Pipeline project (Millennium).
Excluding the total gains of $242 million recorded in the nine months ended
September 30, 2005 and total gains of $194 million recorded in the nine months
ended September 30, 2004, net earnings for the nine months ended September 30,
2005 increased $17 million compared to the same period in 2004, to $617 million.
This was mainly due to an increase in net earnings from the Gas
3
--------------------------------------------------------------------------------
Transmission business partially offset by an increase in net expenses in the
Corporate segment and a decrease in Power's net earnings.
Excluding the $49 million after-tax gain on sale of PipeLines LP units in 2005
and the $7 million after-tax gain on sale of the company's equity interest in
Millennium in 2004, the $53 million increase in net earnings from the Gas
Transmission business for the nine months ended September 30, 2005 compared to
the same period in 2004 was primarily attributable to $53 million of net
earnings generated from GTN. In addition, Gas Transmission's net earnings for
the nine months ended September 30, 2005 included approximately $30 million ($13
million related to 2004 and $17 million related to the nine months ended
September 30, 2005) as a result of the April 2005 National Energy Board (NEB)
decision on the Canadian Mainline's 2004 Tolls and Tariff Application (Phase
II). This decision dealt with capital structure and included an increase in the
deemed common equity ratio to 36 per cent from 33 per cent for 2004, which is
also effective under the 2005 tolls settlement. The increase in Canadian
Mainline's earnings for the nine months ended September 30, 2005 from this
decision was partially offset by the combination of a lower average investment
base and a decrease in the approved rate of return on common equity in 2005
compared to 2004.
The increase in net expenses of $29 million in the Corporate segment in the nine
months ended September 30, 2005 compared to the same period in 2004 was due to
increased interest expense on higher average long-term debt and commercial paper
balances in 2005 as well as the release in third quarter 2004 of previously
established restructuring provisions.
Excluding the above-mentioned $193 million gain related to the sale of Power LP
in third quarter 2005 and $187 million of gains related to Power LP in the first
nine months of 2004, Power's net earnings for the nine months ended September
30, 2005 decreased $7 million as a result of lower contributions from Western
and Eastern Operations partially offset by higher equity income from Bruce
Power.
Funds generated from operations of $490 million and $1,375 million for the three
and nine months ended September 30, 2005 increased $104 million and $192
million, respectively, when compared to the same periods in 2004.
Gas Transmission
The Gas Transmission business generated net earnings of $148 million and $524
million for the three and nine months ended September 30, 2005, respectively,
compared to $134 million and $429 million for the same periods in 2004.
4
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GasTransmission Results-at-a-Glance
(unaudited) Three months ended September 30 Nine months ended September 30
(millions of dollars) 2005 2004 2005 2004
Wholly-Owned Pipelines
Canadian Mainline 67 71 216 201
Alberta System 38 31 112 110
GTN (1) 14 53
Foothills System 5 6 16 17
BC System 2 2 5 5
126 110 402 333
Other Gas Transmission
Great Lakes 11 12 36 43
Iroquois 7 3 14 14
PipeLines LP 2 4 7 13
Portland 1 - 7 6
Ventures LP 3 3 9 10
TQM 2 2 5 6
CrossAlta 5 4 12 6
TransGas 2 3 8 9
Northern Development (1) (1) (3) (3)
General, administrative, support costs and other (10) (6) (22) (15)
22 24 73 89
Gain related to PipeLines LP - - 49 -
Gain related to Millennium - - - 7
22 24 122 96
Net Earnings 148 134 524 429
--------------------
(1) TCPL acquired GTN on November 1, 2004.
Wholly-Owned Pipelines
The Canadian Mainline's third quarter 2005 net earnings decreased $4 million
compared to third quarter 2004. The decrease in net earnings is due to a
combination of a lower average investment base in 2005, a lower approved rate of
return on common equity of 9.46 per cent in 2005 compared to 9.56 per cent in
2004 and lower earnings related to operating costs savings in 2005 compared to
2004, partially offset by an increase in the deemed common equity ratio. The
NEB's decision on the Canadian Mainline's 2004 Tolls and Tariff Application
(Phase II) in April 2005 included an increase in the deemed common equity ratio
from 33 to 36 per cent for 2004 which is also effective for 2005 under the 2005
tolls settlement. Net earnings for the nine months ended September 30, 2005
increased $15 million compared to the corresponding period in
5
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2004. As a result of the NEB decision that increased the deemed common equity
to 36 per cent from 33 per cent, Canadian Mainline's 2005 net earnings for the
nine months ended September 30, 2005 increased $30 million ($13 million related
to 2004 and $17 million related to the first nine months of 2005) compared to
the same period in 2004. However, this earnings increase is partially offset by
the combination of a lower average investment base in 2005 and a decrease in the
approved rate of return on common equity to 9.46 per cent in 2005 from 9.56 per
cent in 2004.
The Alberta System's net earnings of $38 million in third quarter 2005 increased
$7 million compared to $31 million in the same quarter of 2004. Net earnings
for the nine months ended September 30, 2005 increased $2 million compared to
the same period in 2004. The increases were primarily due to lower earnings in
2004 as a result of the 2004 General Rate Application (GRA) decision in August
2004 which disallowed certain costs. These increases were partially offset by a
lower investment base and a lower approved rate of return on common equity in
2005. During 2005, the Alberta System is operating under a negotiated
settlement with its shippers. Net earnings reflect a rate of return, as
prescribed by the Alberta Energy and Utilities Board (EUB), of 9.50 per cent in
2005 compared to a rate of return of 9.60 per cent in 2004 on deemed common
equity of 35 per cent.
GTN, which was acquired by TCPL in November 2004, generated net earnings of $14
million in third quarter 2005 and $53 million in the nine months ended September
30, 2005.
Operating Statistics
Gas
Transmission
Canadian Northwest
Nine months ended September Mainline (1) Alberta System System (3) Foothills BC System
30 (2) System
(unaudited) 2005 2004 2005 2004 2005 2005 2004 2005 2004
Average investment base
($ millions) 7,839 8,233 4,478 4,642 n/a (3) 683 718 218 229
Delivery volumes (Bcf) Total 2,181 1,947 2,918 2,872 581 788 844 236 255
Average per day 8.0 7.1 10.7 10.5 2.1 2.9 3.1 0.9 0.9
--------------------
(1) Canadian Mainline deliveries originating at the Alberta border and
in Saskatchewan for the nine months ended September 30, 2005 were 1,605 Bcf
(2004 - 1,503 Bcf); average per day was 5.9 Bcf (2004 - 5.5 Bcf).
(2) Field receipt volumes for the Alberta System for the nine months
ended September 30, 2005 were 3,010 Bcf (2004 - 2,959 Bcf); average per day was
11.0 Bcf (2004 - 10.8 Bcf).
(3) TCPL acquired the Gas Transmission Northwest System on November 1,
2004. The system is currently operating under a fixed rate model approved by the
United States Federal Energy Regulatory Commission and, as a result, the
system's current results are not dependent on average investment base.
6
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Other Gas Transmission
TCPL's proportionate share of net earnings from its Other Gas Transmission
businesses was $22 million for the three months ended September 30, 2005
compared to $24 million for the same period in 2004. The $2 million decrease
compared to the prior period was mainly due to higher general, administrative,
support costs and other, lower earnings from PipeLines LP due to the reduced
ownership interest and the negative impact of a weaker U.S. dollar. Partially
offsetting these decreases was the impact of Iroquois customer bankruptcy
settlements recognized in third quarter 2005.
Net earnings for the nine months ended September 30, 2005 were $122 million
compared to $96 million for the corresponding period in 2004. Excluding the $49
million gain on sale of PipeLines LP units recorded in 2005, and the $7 million
gain on sale of Millennium recorded in 2004, net earnings for the nine months
ended September 30, 2005 were $16 million lower compared to the same period in
2004. The decrease was due to the impact of a weaker U.S. dollar in 2005,
higher general, administrative, support costs and other, lower earnings from
PipeLines LP, and lower earnings from Great Lakes as a result of lower
short-term revenues and higher operating and maintenance costs. These decreases
were partially offset by higher earnings from CrossAlta as a result of more
favourable natural gas storage market conditions in 2005. In addition, the
impact of the Iroquois customer bankruptcy settlements recognized in third
quarter 2005 was offset by a positive tax adjustment recorded in first quarter
2004.
As at September 30, 2005, TCPL had capitalized $13 million of costs related to
its Broadwater liquified natural gas (LNG) project.
7
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Power
Power Results-at-a-Glance
(unaudited) Three months ended September 30 Nine months ended September 30
(millions of dollars) 2005 2004 2005 2004
Bruce Power investment 99 29 142 125
Western operations 32 43 90 113
Eastern operations 25 21 69 77
Power LPinvestment 12 6 29 22
General, administrative, support costs and other (23) (21) (74) (70)
Operating and other income 145 78 256 267
Financial charges - (4) (7) (9)
Income taxes (46) (23) (78) (80)
99 51 171 178
Gains related to Power LP 193 - 193 187
Net Earnings 292 51 364 365
Power's net earnings in third quarter 2005 of $292 million increased $241
million compared to third quarter 2004. Gains related to the sale of Power LP
accounted for $193 million of this increase. Excluding these gains, Power's net
earnings in third quarter 2005 of $99 million increased $48 million compared to
the same period in 2004, primarily due to $46 million of higher after-tax equity
earnings from Bruce Power. In addition, higher operating and other income from
Eastern Operations and Power LP was offset by a decreased contribution from
Western Operations.
Bruce Power's pre-tax equity income increased by $70 million to $99 million in
third quarter 2005 compared to third quarter 2004 primarily due to higher
realized power prices on uncontracted volumes sold into Ontario's wholesale spot
market. Realized prices in third quarter 2005 were $70 per megawatt hour (MWh)
or $25 per MWh higher than the same period in 2004. Generation volumes of 9.1
terawatt hours (TWh) and a capacity factor of 88 per cent were higher compared
to 8.7 TWh and a capacity factor of 85 per cent in third quarter 2004.
Eastern Operations' operating and other income was $4 million higher in third
quarter 2005 compared to third quarter 2004 primarily due to contributions from
TC Hydro, which represents the hydroelectric generation assets acquired from
USGen on April 1, 2005, and from the Grandview cogeneration facility placed
in-service in January 2005. Partially offsetting these increases was a loss of
margin primarily associated with the expiration of long-term sales contracts
held at the end of 2004 which did not carry over into 2005.
Power LP's operating and other income was $6 million higher in third quarter
2005 compared to the same period in 2004 due to the combined impact of
accounting for the Power LP investment as an
8
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asset held for sale and improved operating results at its Ontario facilities,
partially offset by the impact of TCPL's sale of this investment on August 31,
2005.
Western Operations' operating and other income was $11 million lower in third
quarter 2005 compared to third quarter 2004 primarily due to recognition in
third quarter 2004 of income from the MacKay River plant which was previously
deferred for the first six months of 2004. Operating and other income was also
lower due to fee revenues earned in third quarter 2004 from Power LP's
acquisition of facilities and reduced margins in third quarter 2005 from lower
market heat rates on uncontracted volumes of power generated. Partially
offsetting these decreases were higher contributions from the Sundance A&B power
purchase arrangements (PPAs) primarily due to higher plant availability.
Net earnings for the nine months ended September 30, 2005 of $364 million
approximated net earnings in the same period in 2004. Excluding the Power
LP-related gains of $193 million and $187 million in 2005 and 2004,
respectively, Power's net earnings for the nine months ended September 30, 2005
of $171 million decreased $7 million compared to $178 million in 2004. Higher
equity income from Bruce Power was more than offset by reduced contributions
from Western and Eastern Operations.
Bruce Power Investment
Bruce Power Results-at-a-Glance
(unaudited) Three months ended September 30 Nine months ended September 30
(millions of dollars) 2005 2004 2005 2004
Bruce Power (100 per cent basis)
Revenues 642 395 1,453 1,228
Operating expenses
Cash costs (materials, labour, services and fuel) (269) (254) (821) (716)
Non-cash costs (depreciation and amortization) (48) (43) (145) (117)
(317) (297) (966) (833)
Operating income 325 98 487 395
Financial charges (18) (17) (52) (50)
Income before income taxes 307 81 435 345
TCPL's interest in Bruce Power income before
income taxes 97 26 137 109
Adjustments 2 3 5 16
TCPL's income from Bruce Power before income 99 29 142 125
taxes
TCPL's share of Bruce Power's income before income taxes (equity income) was $70
million higher in third quarter 2005 compared to third quarter 2004 primarily
due to higher realized power prices in third quarter 2005 which averaged $70 per
MWh compared to $45
9
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per MWh in third quarter 2004. Slightly higher generation volumes in third
quarter 2005 also contributed to the higher income.
TCPL's share of power output from Bruce Power for third quarter 2005 increased
to 2,882 gigawatt hours (GWh) compared to 2,765 GWh in third quarter 2004. This
increase primarily reflected fewer planned and forced maintenance outages
compared to third quarter 2004.
Approximately 32 reactor days of planned maintenance outages as well as 23
reactor days of unplanned outages occurred in third quarter 2005. In third
quarter 2004, Bruce Power experienced 55 reactor days of planned maintenance
outages and 13 reactor days of unplanned outages. The Bruce units ran at an
average availability of 88 per cent in third quarter 2005, compared to an 85 per
cent average availability during third quarter 2004. Unit 7 returned to service
mid-August 2005 following a planned maintenance inspection that began on May 7,
2005. The unit was offline for 98 days including a 12 day unplanned extension
to the outage. During third quarter 2005, Unit 3 was taken offline for 11 days
to make repairs to the reactor regulating system. Unit 5 was taken offline on
October 8, 2005 to begin its planned maintenance inspection, which is expected
to last approximately two months.
Overall prices achieved during third quarter 2005 were $70 per MWh, compared to
$45 per MWh in third quarter 2004. Approximately 60 per cent of the available
output was sold into Ontario's wholesale spot market during third quarter 2005
with the remainder being sold under longer term contracts. Bruce Power's
operating expenses increased slightly to $35 per MWh in third quarter 2005 from
$34 per MWh in third quarter 2004. Adjustments to TCPL's interest in Bruce
Power's equity income for the three and nine months ended September 30, 2005
were lower than in 2004 primarily due to a lower amortization of the purchase
price allocated to the fair value of sales contracts in place at the time of
acquisition. The adjustment for the nine months ended September 30, 2005 was
also lower due to the cessation of interest capitalization upon the return to
service of Unit 3 in March 2004.
Pre-tax equity income for the nine months ended September 30, 2005 was $142
million compared to $125 million for the same period in 2004. Prices realized
for the nine months ended September 30, 2005 were $58 per MWh compared to $46
per MWh for the same period in 2004. Approximately 53 per cent of the available
output was sold into Ontario's wholesale spot market during the first nine
months of 2005 with the remainder being sold under longer term contracts. Bruce
Power's operating expenses increased to $39 per MWh for the nine months ended
September 30, 2005 from $32 per MWh for the same period in 2004. This was the
result of reduced output as well as higher maintenance costs, higher
depreciation and lower capitalization of labour and other in-house costs
following the restart of Unit 3.
10
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Equity income from Bruce Power is directly impacted by fluctuations in wholesale
spot market prices for electricity as well as overall plant availability, which
in turn, is impacted by scheduled and unscheduled maintenance. To reduce its
exposure to spot market prices, Bruce Power has entered into fixed price sales
contracts to sell forward 3.2 TWh of output for the balance of 2005 and
approximately 13 TWh of 2006 output from the Bruce B units has also been sold
under fixed-price sales contracts. Overall plant availability for the six Bruce
units in 2005 is expected to be 83 per cent.
Bruce Power made a total of $165 million in cash distributions to its partners
in third quarter 2005. TCPL's share was $52 million. For the nine months ended
September 30, 2005, the total distributions to partners were $215 million, of
which TCPL's share was $68 million. No distributions were made to partners in
2004. The partners have agreed that all excess cash will be distributed on a
monthly basis and that separate cash calls will be made for major capital
projects.
On October 17, 2005, TCPL announced that Bruce Power and the Ontario Power
Authority (OPA), entered into a long-term agreement whereby Bruce Power will
refurbish and restart the currently idle Units 1 and 2, extend the operating
life of Unit 3 by replacing its steam generators and fuel channels when required
and replace the steam generators on Unit 4. Bruce Power's capital program for
the restart and refurbishment work is expected to total approximately $4.25
billion and TCPL's approximate $2.125 billion share will be financed through
capital contributions over the period from 2005 to 2011. A capital cost risk
and reward sharing schedule with OPA is in place for spending below or in excess
of the $4.25 billion base case estimate of Bruce A restart and refurbishment.
As a result of the agreement between Bruce Power and the OPA, and Cameco
Corporation's decision not to participate in the restart and refurbishment
program, a new partnership has been created. The new Bruce Power A Limited
Partnership (BALP) will sublease the Bruce A facilities, which are comprised of
Units 1 to 4, from Bruce Power. The effect of these transactions is that TCPL
and BPC Generation Infrastructure Trust each incurred a net cash outlay of
approximately $100 million and each owns a 47.4 per cent interest in BALP. The
remaining 5.2 per cent is owned by the Power Worker's Union and The Society of
Energy Professionals. The day-to-day operations of the Bruce facility will be
unaffected by the formation of BALP and TCPL continues to own 31.6 per cent of
the Bruce B facilities (Units 5 to 8). The agreement and above transactions
were completed October 31, 2005 with the receipt of a favourable tax ruling from
the Canada Revenue Agency.
11
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Work to restart Units 1 and 2 will begin immediately with the first unit
expected to be online in 2009, subject to approval by the Canadian Nuclear
Safety Commission. Restarting Units 1 and 2 which have a capacity of
approximately 1,500 megawatts (MW) will boost the Bruce facilities' overall
output to more than 6,200 MW.
As a result of the contract with the OPA, all of the output from Bruce A,
effective upon closing, will be sold at a fixed price of $57.37 per MWh,
adjusted annually for inflation, before a recovery of fuel costs which will be
flowed through to the OPA. As part of the contract, sales from the Bruce B
Units 5 to 8 are subject to a floor price of $45 per MWh, adjusted annually for
inflation. Any receipts by Bruce Power under this floor price mechanism are
refunded if prices subsequently increase above the $45 per MWh floor price.
As a result of reorganizing Bruce Power, TCPL expects to proportionately
consolidate its investment in both Bruce Power and BALP on a prospective basis
from closing.
Western Operations
Western Operations Results-at-a-Glance (1)
(unaudited) Three months ended September 30 Nine months ended September 30
(millions of dollars) 2005 2004 2005 2004
Revenue
Power 165 132 480 446
Other (2) 29 24 108 87
194 156 588 533
Cost of sales
Power (105) (71) (313) (274)
Other (2) (17) (9) (67) (47)
(122) (80) (380) (321)
Other costs and expenses (34) (28) (102) (82)
Depreciation (6) (5) (16) (17)
Operating and other income 32 43 90 113
--------------------
(1) ManChief is included until April 30, 2004.
(2) Other revenue includes Cancarb Thermax and natural gas sales. Other cost of
sales includes the cost of natural gas sold.
12
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Western Operations Sales Volumes (1)
(unaudited) Three months ended September 30 Nine months ended September 30
(GWh) 2005 2004 2005 2004
Supply
Generation 544 680 1,691 1,432
Purchased
Sundance A & B PPAs 1,593 1,388 5,137 5,084
Other purchases (2) 658 686 2,003 2,043
2,795 2,754 8,831 8,559
Contracted vs. Spot
Contracted 2,423 2,503 7,570 7,858
Spot 372 251 1,261 701
2,795 2,754 8,831 8,559
--------------------
(1) ManChief is included until April 30, 2004.
(2) Includes Sheerness Power Purchase Arrangement (PPA) volumes.
Western Operations' operating and other income of $32 million in third quarter
2005 was $11 million lower compared to the same period in 2004. This decrease
was mainly due to recognition in third quarter 2004 of income from the MacKay
River facility which was previously deferred for the first six months of 2004.
Operating and other income was also lower due to fee revenues earned in third
quarter 2004 from Power LP and reduced margins in third quarter 2005 from lower
market heat rates on uncontracted volumes of power generated. Market heat rates
decreased by approximately 20 per cent in the quarter as a result of an
approximate 50 per cent ($3 per gigajoule) increase in spot market natural gas
prices in Alberta in third quarter 2005 compared to the same period in 2004,
while average spot market power prices increased by approximately 23 per cent
($12 per MWh). Partially offsetting these decreases were higher contributions
from the Sundance A&B PPAs primarily due to higher plant availability. A
significant portion of plant generation in Western Operations is sold under
long-term contract to mitigate price risk. Some output is intentionally not
committed under long-term contract to assist in managing Power's overall
portfolio of generation. This approach to portfolio management assists in
minimizing costs in situations where TCPL would otherwise have to purchase
electricity in the open market to fulfill its contractual obligations.
Operating and other income for the nine months ended September 30, 2005 was $90
million or $23 million lower compared to $113 million earned in the same period
in 2004. This decrease was primarily due to reduced margins from lower market
heat rates on uncontracted volumes of power generated and fee revenues earned in
2004 from Power LP.
Western Operations' power sales revenues, power cost of sales and associated
purchased volumes increased in third quarter 2005 compared to third quarter 2004
primarily due to higher plant
13
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availability at Sundance A & B as a result of lower maintenance outages. Power
sales revenues also increased as a result of higher realized prices in third
quarter 2005. Other costs and expenses of $34 million, which includes fuel gas
consumed in generation, were higher in third quarter 2005 primarily due to
higher fuel costs at the MacKay River facility resulting from higher natural gas
prices and higher generation output. Generation volumes of 544 GWh in third
quarter 2005 decreased 136 GWh compared to third quarter 2004 primarily due to
planned maintenance outages in 2005 at Carseland and an unplanned outage at Bear
Creek. Partially offsetting these decreases were higher generation volumes
from MacKay River resulting from outages in third quarter 2004. Bear Creek has
experienced certain operational difficulties in 2005 and, as a result, has not
been fully available throughout much of the first nine months of 2005. Power
earnings in 2005 have not been significantly impacted by the operational
difficulties at Bear Creek. Technical evaluation continues and possible
long-term solutions are being studied. In third quarter 2005, approximately 13
per cent of power sales volumes were sold into the spot market compared to
approximately nine per cent for the same period in 2004. To reduce its exposure
to spot market prices on uncontracted volumes, as at September 30, 2005, Western
Operations had fixed price sales contracts to sell forward approximately 2,800
GWh for the remainder of 2005 and approximately 8,000 GWh for 2006.
Eastern Operations
Eastern Operations Results-at-a-Glance (1)
(unaudited) Three months ended September 30 Nine months ended September 30
(millions of dollars) 2005 2004 2005 2004
Revenue
Power 136 139 380 415
Other (2) 111 51 254 168
247 190 634 583
Cost of sales
Power (70) (83) (183) (228)
Other (2) (98) (52) (237) (157)
(168) (135) (420) (385)
Other costs and expenses (46) (30) (127) (105)
Depreciation (8) (4) (18) (16)
Operating and other income 25 21 69 77
--------------------
(1) Curtis Palmer is included until April 30, 2004.
(2) Other includes natural gas.
14
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Eastern Operations Sales Volumes (1)
(unaudited) Three months ended September 30 Nine months ended September 30
(GWh) 2005 2004 2005 2004
Supply
Generation 600 302 2,006 1,102
Purchased 833 1,329 2,138 3,614
1,433 1,631 4,144 4,716
Contracted vs. Spot
Contracted 1,348 1,581 3,765 4,581
Spot 85 50 379 135
1,433 1,631 4,144 4,716
--------------------
(1) Curtis Palmer is included until April 30, 2004.
Operating and other income in third quarter 2005 from Eastern Operations of $25
million was $4 million higher compared to $21 million earned in third quarter
2004. The increase was primarily due to income from the April 1, 2005
acquisition of the TC Hydro hydroelectric generation assets and from the
Grandview cogeneration facility placed in-service in January 2005. Partially
offsetting these increases was a loss of margin primarily associated with the
expiration of long-term sales contracts held at the end of 2004 which did not
carry over into 2005.
Operating and other income for the nine months ended September 30, 2005 was $69
million or $8 million lower than the $77 million earned in 2004. Incremental
income from the acquisition of the TC Hydro assets and income from the Grandview
cogeneration facility were more than offset by a $16 million pre-tax ($10
million after-tax) contract restructuring payment made by Ocean State Power
(OSP) to its natural gas fuel suppliers in first quarter 2005, a $16 million
pre-tax ($10 million after-tax) reduction in income as a result of the sale of
Curtis Palmer to Power LP in April 2004 and a loss of margin primarily
associated with the expiration of long-term sales contracts. The contract
restructuring at OSP reduced the term of the long-term natural gas supply
contracts by approximately three years (now ending in October 2008) and adjusted
the pricing to track spot pricing of natural gas at the Niagara delivery point
versus the previously arbitrated pricing that had resulted in above-market cost
of natural gas for OSP.
Generation volumes in third quarter 2005 increased 298 GWh to 600 GWh compared
to 302 GWh in 2004 primarily due to the acquisition of the TC Hydro assets and
the placing into service of the Grandview cogeneration facility. Partially
offsetting these increases was reduced generation from the OSP facility. In
third quarter 2005, OSP Phase I returned to service after a six month unplanned
maintenance outage and OSP Phase II commenced a planned maintenance outage
expected to continue into first quarter 2006.
15
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Eastern Operations' power sales revenues of $136 million decreased $3 million in
third quarter 2005 due to lower contracted sales volumes partially offset by
higher realized prices. Sales volumes of 1,433 GWh for third quarter 2005 were
lower than the same period in 2004 due primarily to the expiration of long-term
sales contracts held at the end of 2004 which did not carry over into 2005.
Power's cost of sales of $70 million was lower in third quarter 2005 due to the
impact of lower purchased power volumes partially offset by higher prices for
purchased power. Purchased power volumes of 833 GWh were lower in third quarter
2005 due to lower contracted sales volumes and the impact of power generation
from the purchase of the TC Hydro assets. Volumes generated from the TC Hydro
assets reduced some of the requirement to purchase power to fulfill contractual
sales obligations. Other revenue and cost of sales increased year-over-year
primarily as a result of natural gas purchased and resold from the new natural
gas supply contracts at OSP. Other costs and expenses of $46 million, which
include fuel gas consumed in generation, increased $16 million primarily due to
higher fuel costs at the OSP facility and operating costs of the TC Hydro assets
acquired in 2005.
In third quarter 2005, approximately six per cent of power sales volumes were
sold into the spot market compared to approximately three per cent in third
quarter 2004 reflecting the sale of a portion of the generation from the TC
Hydro assets into the spot market. Eastern Operations is focused on selling the
majority of its power under contract to wholesale, commercial and industrial
customers while managing a portfolio of power supplies sourced from its own
generation and wholesale power purchases. To reduce its exposure to spot market
prices, as at September 30, 2005, Eastern Operations had entered into fixed
price sales contracts to sell forward approximately 1,400 GWh of power for the
remainder of 2005 and approximately 3,300 GWh of power for 2006. Certain
contracted volumes are dependent on customer usage levels.
Power LP Investment
Power LP's operating and other income was $6 million higher in third quarter
2005 compared to the same period in 2004 primarily due to the combined impact of
accounting for the Power LP investment as an asset held for sale and improved
operating results at its Ontario facilities. Operating and other income for the
nine months ended September 30, 2005 was $7 million higher compared to the same
period in 2004. The increase was primarily due to additional earnings from
Power LP's 2004 acquisitions of the Curtis Palmer, ManChief, Mamquam and Queen
Charlotte facilities, improved operating results and the impact of accounting
for the Power LP investment as an asset held for sale. Partially offsetting
these increases was the impact of TCPL's sale
16
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of this investment on August 31, 2005, a reduced ownership interest in Power LP
in 2005, and the effect of the recognition in second quarter 2004 of all
previously deferred gains resulting from the removal of the Power LP redemption
obligation.
General, Administrative, Support Costs and Other
General, administrative, support costs and other of $23 million in third quarter
2005 were $2 million higher than in third quarter 2004. These costs were $74
million for the nine months ended September 30, 2005 or $4 million higher
compared to the same period in 2004.
Power Sales Volumes and Plant Availability
Power Sales Volumes
(unaudited) Three months ended September 30 Nine months ended September 30
(GWh) 2005 2004 2005 2004
Bruce Power investment (1) 2,882 2,765 7,786 8,257
Western operations (2) 2,795 2,754 8,831 8,559
Eastern operations (2) 1,433 1,631 4,144 4,716
Power LPinvestment (2) (3) 445 642 1,865 1,750
Total 7,555 7,792 22,626 23,282
--------------------
(1) Sales volumes reflect TCPL's 31.6 per cent share of Bruce Power output.
(2) ManChief and Curtis Palmer volumes are included in Power LP investment
effective April 30, 2004.
(3) TCPL operated and managed Power LP until August 31, 2005. The volumes in
the table represent 100 percent of Power LP's sales volumes up to August 31,
2005.
Weighted Average Plant Availability (1)
Three months ended September 30 Nine months ended September 30
(unaudited) 2005 2004 2005 2004
Bruce Power investment (2) 88 % 85 % 80 % 85 %
Western operations (3) 89 % 94 % 86 % 96 %
Eastern operations (3) (4) 84 % 98 % 81 % 97 %
Power LP investment (3) (5) 96 % 97 % 93 % 97 %
All plants, excluding Bruce Power investment 88 % 97 % 85 % 96 %
All plants 89 % 92 % 81 % 92 %
--------------------
(1) Plant availability represents the percentage of time in the period that the
plant is available to generate power, whether actually running or not and is
reduced by planned and unplanned outages.
(2) Unit 3 is included effective March 1, 2004.
(3) ManChief and Curtis Palmer are included in Power LP investment effective
April 30, 2004.
(4) TC Hydro is included in Eastern Operations effective April 1, 2005.
(5) Power LP is included up to August 31, 2005.
17
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Corporate
Net expenses for the three and nine months ended September 30, 2005 were $12
million and $29 million, respectively, compared to net income of $7 million and
nil for the corresponding periods in 2004.
The $19 million increase in Corporate's net expenses for third quarter 2005
compared to the same period in 2004 was primarily due to a $12 million after-tax
adjustment in third quarter 2004 as a result of the release of previously
established restructuring provisions and higher interest expense on higher
average long-term debt and commercial paper balances in 2005.
The $29 million increase in Corporate's net expenses for the nine months ended
September 30, 2005 compared to the same period in 2004 was primarily due to
increased interest expense on higher average long-term debt and commercial paper
balances in 2005 as well as the release in third quarter 2004 of previously
established restructuring provisions. Income tax refunds and related interest
in the nine months ended September 30, 2004 were comparable to income tax
refunds and positive tax adjustments recorded in the nine months ended September
30, 2005.
Liquidity and Capital Resources
Funds Generated from Operations
Funds generated from operations were $490 million and $1,375 million for the
three and nine months ended September 30, 2005, respectively, compared with $386
million and $1,183 million for the same periods in 2004.
TCPL expects that its ability to generate adequate amounts of cash in the short
term and the long term, when needed, and to maintain financial capacity and
flexibility to provide for planned growth remains substantially unchanged since
December 31, 2004.
Investing Activities
In the three and nine months ended September 30, 2005, capital expenditures,
excluding acquisitions, totalled $166 million (2004 - $97 million) and $409
million (2004 - $291 million), respectively, and related primarily to
construction of new power plants as well as maintenance and capacity capital in
the Gas Transmission business.
In the three and nine months ended September 30, 2005, disposition of assets
generated $523 million (2004 - nil) and $676 million (2004 - $408 million),
respectively. The dispositions in 2005 relate to the sale of TCPL's ownership
interest in Power LP and
18
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PipeLines LP units while the dispositions in 2004 relate primarily to the sale
of ManChief and Curtis Palmer to Power LP.
Acquisitions for the nine months ended September 30, 2005 were $632 million
(2004 - $63 million), and relate to the acquisition of the TC Hydro assets and
the purchase of an additional 3.52 per cent ownership interest in Iroquois Gas
Transmission System L.P.
Financing Activities
TCPL retired $5 million and $941 million of long-term debt in the three and nine
months ended September 30, 2005, respectively. TCPL issued $799 million of
long-term debt in the nine months ended September 30, 2005. On June 1, 2005,
Gas Transmission Northwest Corporation (GTNC) redeemed all of its outstanding
US$150 million 7.80 per cent Senior Unsecured Debentures and US$250 million 7.10
per cent Senior Unsecured Notes. On the same date, GTNC completed a US$400
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. For
the nine months ended September 30, 2005, outstanding notes payable decreased by
$163 million, while cash and short-term investments increased by $19 million.
Dividends
On October 31, 2005, TCPL's Board of Directors declared a dividend for the
quarter ending December 31, 2005 in an aggregate amount equal to the aggregate
quarterly dividend to be paid on January 31, 2006 by TransCanada Corporation on
the issued and outstanding common shares as at the close of business on December
30, 2005. The Board also declared regular dividends on TCPL's preferred
shares.
Contractual Obligations
Primarily as a result of new contracts in the nine months ended September 30,
2005, Power's future purchase obligations at September 30, 2005 are estimated to
be as follows.
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Purchase Obligations
(unaudited - millions of 2005 (1) 2006 2007 2008 2009 2010+
dollars)
Power
Commodity purchases (2) 289 797 706 596 273 2,648
Capital expenditures (3) 82 185 70 3 1 -
Other (4) 22 60 49 32 29 114
393 1,042 825 631 303 2,762
--------------------
(1) Includes purchase obligations for the three months ending December 31, 2005.
(2) 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.
(3) Amounts are estimates and are subject to variability based on timing of
construction and project enhancements.
(4) 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.
There have been no other material changes to TCPL's contractual obligations from
December 31, 2004 to September 30, 2005, including payments due for the next
five years and thereafter. For further information on these contractual
obligations, refer to the MD&A in TCPL's 2004 Annual Report.
Financial and Other Instruments
The following represents the material changes to the company's financial
instruments since December 31, 2004.
Energy Price Risk Management
The company executes power, natural gas and heat rate derivatives in order to
manage exposure and risks associated with its overall asset portfolio. Heat
rate contracts are contracts for the sale or purchase of power that are priced
based on a natural gas index. The fair values and notional volumes of the swap,
option, future and heat rate contracts are shown in the tables below. In
accordance with the company's accounting policy, each of the derivatives in the
table below is recorded on the balance sheet at its fair value at September 30,
2005 and December 31, 2004.
20
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Power
Asset/(Liability)
September 30, December 31, 2004
2005
(unaudited)
Accounting Fair Fair
(millions of dollars) Treatment Value Value
Power - swaps
(maturing 2005 to 2011) Hedge (123) 7
(maturing 2005 to 2010) Non-hedge 19 (2)
Gas - swaps, futures and options
(maturing 2005 to 2016) Hedge (13) (39)
(maturing 2005 to 2008) Non-hedge (16) (2)
Heat rate contracts
(maturing 2005 to 2006) Hedge - (1)
Notional Volumes
September 30, 2005
Accounting Power (GWh) Gas (Bcf)
(unaudited) Treatment Purchases Sales Purchases Sales
Power - swaps
(maturing 2005 to 2011) Hedge 911 6,366 - -
(maturing 2005 to 2010) Non-hedge 1,206 220 - -
Gas - swaps, futures and options
(maturing 2005 to 2016) Hedge - - 80 71
(maturing 2005 to 2008) Non-hedge - - 26 21
Heat rate contracts
(maturing 2005 to 2006) Hedge - 44 - -
Notional Volumes
December 31, 2004
Accounting Power (GWh) Gas (Bcf)
Treatment Purchases Sales Purchases Sales
Power - swaps Hedge 3,314 7,029 - -
Non-hedge 438 - - -
Gas - swaps, futures and options Hedge - - 80 84
Non-hedge - - 5 8
Heat rate contracts Hedge - 229 2 -
21
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Risk Management
TCPL's market, financial and counterparty risks remain substantially unchanged
since December 31, 2004. For further information on risks, refer to the MD&A in
TCPL's 2004 Annual Report.
Controls and Procedures
As of September 30, 2005, TCPL's management, together with TCPL's President and
Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness
of the design and operation of the company's disclosure controls and procedures.
Based on this evaluation, the President and Chief Executive Officer and the
Chief Financial Officer of TCPL have concluded that the disclosure controls and
procedures are effective.
There were no changes in TCPL's internal control over financial reporting during
the most recent fiscal quarter that have materially affected or are reasonably
likely to materially affect TCPL's internal control over financial reporting.
Critical Accounting Policy
TCPL's critical accounting policy, which remains unchanged since December 31,
2004, is the use of regulatory accounting for its regulated operations. For
further information on this critical accounting policy, refer to the MD&A in
TCPL's 2004 Annual Report.
Critical Accounting Estimates
Since a determination of many assets, liabilities, revenues and expenses is
dependent upon future events, the preparation of the company's consolidated
financial statements requires the use of estimates and assumptions which have
been made using careful judgment. TCPL's critical accounting estimate from
December 31, 2004 continues to be depreciation expense. For further information
on this critical accounting estimate, refer to the MD&A in TCPL's 2004 Annual
Report.
Accounting Change
Financial Instruments - Disclosure and Presentation
Effective January 1, 2005, the company adopted the provisions of the Canadian
Institute of Chartered Accountants' amendment to the existing Handbook Section "
Financial Instruments - Disclosure and Presentation" which provides guidance
for classifying certain
22
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financial instruments that embody obligations that may be settled by issuance of
the issuer's equity shares as debt when the instrument does not establish an
ownership relationship. In accordance with this amendment, TCPL reclassified
the non-controlling interest component of preferred securities as long-term
debt.
This accounting change was applied retroactively with restatement of prior
periods. The impact of this change on TCPL's net income in third quarter 2005
and prior periods was nil.
The impact of the accounting change on the company's consolidated balance sheet
as at December 31, 2004 is as follows.
(unaudited - millions of dollars) Increase/
(Decrease)
Deferred Amounts (1) 135
Preferred Securities 535
Non-Controlling Interest
Preferred securities of subsidiary (670)
Total Liabilities and Shareholders' Equity -
--------------------
(1) Regulatory deferral
Outlook
In 2005, the company expects higher net income from the Gas Transmission segment
than originally anticipated primarily as a result of the $49 million after-tax
gain related to the sale of PipeLines LP units. The company also expects higher
Power net income in 2005 than originally anticipated primarily as a result of
the $193 million after-tax gain on sale of Power LP and the approximately $115
million after-tax gain on sale of the company's investment in PT Paiton Energy
Company (Paiton Energy), expected in fourth quarter 2005. For further
information on Paiton Energy, please refer to Other Recent Developments. In
addition, primarily as a result of higher realized power prices in 2005 compared
to 2004, TCPL expects higher earnings from Bruce Power than originally
anticipated. Excluding these impacts, the company's outlook is relatively
unchanged since December 31, 2004. For further information on outlook, refer to
the MD&A in TCPL's 2004 Annual Report.
In 2005, TCPL will continue to direct its resources towards long-term growth
opportunities that will strengthen its financial performance and create
long-term value for shareholders. The company's net income and cash flow
combined with a strong balance sheet continue to provide the financial
flexibility for TCPL to make disciplined investments in its core businesses of
Gas Transmission and Power.
23
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Credit ratings on TCPL PipeLines Limited's senior unsecured debt assigned by
Dominion Bond Rating Service Limited (DBRS), Moody's Investors Service (Moody's)
and Standard & Poor's remain at A, A2 and A-, respectively. DBRS and Moody's
both maintain a 'stable' outlook on their ratings and Standard & Poor's
maintains a 'negative' outlook on its rating.
Other Recent Developments
Gas Transmission
Wholly-Owned Pipelines
Alberta System
On June 7, 2005, the EUB granted approval of a negotiated settlement for the
Alberta System's 2005-2007 Revenue Requirement. As stipulated in the settlement,
following the approval of the settlement, TCPL withdrew its motion filed with
the Alberta Court of Appeal for leave to appeal Decision 2004-069 which dealt
with Phase I of the 2004 GRA. TCPL also agreed that it would not pursue a review
and variance application on the EUB's findings regarding incentive compensation
and long-term incentive costs.
TCPL will continue to charge interim tolls for 2005 for transportation service
on the Alberta System. The interim tolls, approved by the EUB in December 2004,
will remain in effect until final tolls are established following the Phase II
proceeding of the Alberta System's 2005 GRA. In this second phase of the EUB's
rate making process, the allocation of 2005 approved costs among transportation
services and rate design are determined. The EUB commenced a hearing for Phase
II on October 4, 2005. The two week oral hearing on Phase II concluded October
19 with written argument and reply due November 10 and November 24,
respectively.
Other Gas Transmission
Cacouna
In September 2005, the village of Cacouna, Quebec, voted 57.2 per cent in favour
of an LNG terminal to be built in the area. The Cacouna Energy joint venture
between Petro-Canada and TCPL was originally announced in September 2004 and
proposes a $660 million project at Gros Cacouna harbour on the St. Lawrence
River, capable of receiving, storing and regasifying imported LNG with an
average send-out capacity of approximately 500 million cubic feet per day of
natural gas. TCPL will operate the facility, while Petro-Canada will contract
for all of the capacity and supply the LNG.
24
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Regulatory applications have been made with the federal, provincial and
municipal governments and the relevant decisions are anticipated in late 2006.
Should approvals be received, construction will commence soon thereafter with a
terminal in-service date expected by late 2009.
Power
TransCanada Hydro Northeast, Inc.
On April 1, 2005, TCPL closed its acquisition of hydroelectric generation
assets, with total generating capacity of 567 MW, from USGen for US$505 million,
subject to closing adjustments.
The 49 MW Bellows Falls facility was one of the hydro facilities purchased by
TCPL and was the subject of a purchase option in favour of the Town of
Rockingham (the Town). This agreement provided the Town with an option to
purchase the facility for US$72 million. The option was exercised in December
2004 and the Town assigned the option agreement to the Vermont Hydroelectric
Power Authority for the purposes of financing the Town's acquisition of the
Bellows Falls facility. The closing under the option agreement contained many
conditions precedent, in particular that the relevant government approvals be
obtained, including the approval of the Vermont Public Service Board and the
United States Federal Energy Regulatory Commission. As these conditions
precedent were not satisfied before the deadline outlined in the option
agreement, the option agreement was terminated in September 2005. As a result,
TCPL continues to own and operate the 49 MW Bellows Falls hydroelectric
facility.
Power LP
On August 31, 2005, TCPL closed the sale of its interest in Power LP to EPCOR
for net proceeds of $523 million. In third quarter 2005, TCPL realized an
after-tax gain of $193 million from this sale. The net gain was recorded in the
Power segment and the company recorded a $52 million tax charge, including $79
million of current income tax expense, on this transaction. EPCOR's acquisition
includes 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. Following the close of the
transaction, the name of the partnership changed from TransCanada Power, L.P. to
EPCOR Power L.P. (the Partnership).
Effective upon the closing of the sale, TCPL was no longer the general partner
of the Partnership and TCPL and its affiliates ceased to own Partnership units.
In addition, approximately 100
25
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TCPL employees, who provided management, operations and maintenance services
under the contract to the Partnership, became EPCOR employees.
Paiton Energy
In June 2005, TCPL reached an agreement to sell its approximate 11 per cent
interest in Paiton Energy to subsidiaries of The Tokyo Electric Power Company
for US$103 million, subject to adjustments. TCPL originally purchased its
interest in Paiton Energy in 1996. Paiton Energy owns two 615 MW coal-fired
plants in East Java, Indonesia. Pending various approvals, this transaction is
expected to close in fourth quarter 2005. Upon closing, TCPL expects to realize
an after-tax gain on sale of approximately $115 million.
Share Information
As at September 30, 2005, TCPL had 483,344,109 issued and outstanding common
shares. In addition, there were 4,000,000 Series U and 4,000,000 Series Y
Cumulative First Preferred Shares issued and outstanding as at September 30,
2005.
26
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Selected Quarterly Consolidated Financial Data (1)
(unaudited) 2005 2004 2003
(millions of dollars except Third Second First Fourth Third Second First Fourth
per share amounts)
Revenues 1,491 1,444 1,407 1,478 1,307 1,344 1,356 1,375
Net Income applicable to
common shares
Continuing operations 428 199 232 184 192 388 214 193
Discontinued operations - - - - 52 - - -
428 199 232 184 244 388 214 193
Share Statistics
Net income per share - Basic
and diluted
Continuing operations $ 0.89 $ 0.41 $ 0.48 $ 0.38 $ 0.40 $ 0.81 $ 0.44 $ 0.40
Discontinued operations - - - - 0.11 - - -
$ 0.89 $ 0.41 $ 0.48 $ 0.38 $ 0.51 $ 0.81 $ 0.44 $ 0.40
--------------------
(1) The selected quarterly consolidated financial data has been prepared in
accordance with Canadian GAAP. For a discussion on the
factors affecting the comparability of the financial data, including
discontinued operations, refer to Note 1 and Note 22 of TCPL's
restated 2004 audited consolidated financial statements.
Factors Impacting Quarterly Financial Information
In the Gas Transmission business, which consists primarily of the company's
investments in regulated pipelines, annual revenues and net earnings fluctuate
over the long term based on regulators' decisions and negotiated settlements
with shippers. Generally, quarter over quarter revenues and net earnings during
any particular fiscal year remain relatively stable with fluctuations arising as
a result of adjustments being recorded due to regulatory decisions and
negotiated settlements with shippers and due to items outside of the normal
course of operations.
In the Power business, which consists primarily of the company's investments in
electrical power generation plants, quarter over quarter revenues and net
earnings are affected by seasonal weather conditions, customer demand, market
prices, planned and unplanned plant outages as well as items outside of the
normal course of operations.
Significant items which impacted the last eight quarters' net earnings are as
follows.
* First quarter 2004 net earnings included approximately $12 million
of income tax refunds and related interest.
* Second quarter 2004 net earnings included after-tax gains related
to Power LP of $187 million, of which $132 million were previously
deferred and were being amortized into income to 2017.
27
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THIRD QUARTER REPORT 2005
* In third quarter 2004, the EUB's decisions on the Generic Cost of
Capital and Phase I of the 2004 GRA resulted in lower earnings for
the Alberta System compared to the previous quarters. In addition,
third quarter 2004 included a $12 million after-tax adjustment related
to the release of previously established restructuring provisions and
recognition of $8 million of non-capital loss carry forwards.
* In fourth quarter 2004, TCPL completed the acquisition of GTN and
recorded $14 million of net earnings from the November 1, 2004
acquisition date. Power recorded a $16 million pre-tax positive
impact of a restructuring transaction related to power purchase
contracts between OSP and Boston Edison in Eastern Operations.
* In first quarter 2005, net earnings included a $48 million
after-tax gain related to the sale of PipeLines LP units. Power
earnings included a $10 million after-tax cost for the restructuring
of natural gas supply contracts by OSP. In addition, Bruce Power's
equity income was lower than previous quarters due to the impact of
planned maintenance outages and the increase in operating costs as a
result of moving to a six-unit operation.
* Second quarter 2005 net earnings included $21 million ($13 million
related to 2004 and $8 million related to the six months ended June
30, 2005) with respect to the NEB's decision on TCPL's 2004 Mainline
Tolls and Tariff Application (Phase II). On April 1, 2005, TCPL
completed the acquisition of hydroelectric generation assets from
USGen. Bruce Power's equity income was lower than previous quarters
due to the continuing impact of planned maintenance outages and an
unplanned maintenance outage on Unit 6 relating to a transformer
fire.
* In third quarter 2005, net earnings included a $193 million after-tax
gain related to the sale of the company's ownership interest in Power
LP. In addition, Bruce Power's equity income increased from prior
quarters due to higher realized power prices and slightly higher
generation volumes.
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Forward-Looking Information
Certain information in this quarterly report is forward-looking and is subject
to important risks and uncertainties. The results or events predicted in this
information may differ from actual results or events. Factors which could cause
actual results or events to differ materially from current expectations include,
among other things, the ability of TCPL to successfully implement its strategic
initiatives and whether such strategic initiatives will yield the expected
benefits, the availability and price of energy commodities, regulatory
decisions, competitive factors in the pipeline and power industry sectors, and
the prevailing economic conditions in North America. For additional information
on these and other factors, see the reports filed by TCPL with Canadian
securities regulators and with the United States Securities and Exchange
Commission. TCPL disclaims any intention or obligation to update or revise any
forward-looking statements, whether as a result of new information, future
events or otherwise.
29
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Exhibit 13.2
Consolidated Income
(unaudited) Three months ended September 30 Nine months ended September 30
(millions of dollars) 2005 2004 2005 2004
Revenues 1,491 1,307 4,342 4,007
Operating Expenses
Cost of sales 290 215 800 706
Other costs and expenses 466 379 1,310 1,152
Depreciation 247 236 750 700
1,003 830 2,860 2,558
Operating Income 488 477 1,482 1,449
Other (Income)/Expenses
Financial charges 210 220 626 638
Financial charges of joint ventures 14 15 46 45
Equity income (105) (39) (163) (156)
Interest income and other (22) (33) (50) (58)
Gain related to PipeLines LP - - (82) -
Gains related to Power LP (245) - (245) (197)
Gain related to Millennium - - - (7)
(148) 163 132 265
Income from Continuing Operations before Income 636 314 1,350 1,184
Taxes and Non-Controlling Interests
Income Taxes
Current 189 99 429 329
Future 12 17 38 38
201 116 467 367
Non-Controlling Interests 1 - 7 6
Net Income from Continuing Operations 434 198 876 811
Net Income from Discontinued Operations - 52 - 52
Net Income 434 250 876 863
Preferred Share Dividends 6 6 17 17
Net Income Applicable to Common Shares 428 244 859 846
Net Income Applicable to Common Shares
Continuing operations 428 192 859 794
Discontinued operations - 52 - 52
428 244 859 846
See accompanying notes to the consolidated financial statements.
1
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Consolidated Cash Flows
(unaudited) Three months ended September 30 Nine months ended September 30
(millions of dollars) 2005 2004 2005 2004
Cash Generated From Operations
Net income from continuing operations 434 198 876 811
Depreciation 247 236 750 700
Gain related to PipeLines LP, net of current tax - - (31) -
expense (Note 5)
Gains related to Power LP, net of current tax (166) - (166) (197)
expense (Note 5)
Gain related to Millennium, net of current tax - - - (7)
expense
Equity income in excess of distributions (52) (29) (78) (119)
received
Pension funding lower than/(in excess of) 12 (22) (5) (21)
expense
Future income taxes 12 17 38 38
Non-controlling interests 1 - 7 6
Other 2 (14) (16) (28)
Funds generated from operations 490 386 1,375 1,183
Decrease/(increase) in operating working capital 89 133 (129) 51
Net cash provided by operations 579 519 1,246 1,234
Investing Activities
Capital expenditures (166) (97) (409) (291)
Acquisitions, net of cash acquired - (49) (632) (63)
Disposition of assets 523 - 676 408
Deferred amounts and other (44) (11) (97) (27)
Net cash provided by/(used in) investing 313 (157) (462) 27
activities
Financing Activities
Dividends (154) (152) (454) (442)
Advances from parent - - (75) -
Notes payable repaid, net (696) (66) (163) (367)
Long-term debt issued - - 799 665
Reduction of long-term debt (5) (9) (941) (510)
Non-recourse debt of joint ventures issued 4 60 9 147
Reduction of non-recourse debt of joint ventures (9) (8) (30) (20)
Partnership units of joint ventures issued - - - 88
Common shares issued - - 80 -
Net cash used in financing activities (860) (175) (775) (439)
Effect of Foreign Exchange Rate Changes on Cash (12) (58) 10 (55)
and Short-Term Investments
Increase in Cash and Short-Term Investments 20 129 19 767
Cash and Short-Term Investments
Beginning of period 186 975 187 337
Cash and Short-Term Investments
End of period 206 1,104 206 1,104
Supplementary Cash Flow Information
Income taxes paid 101 77 408 329
Interest paid 214 193 642 586
See accompanying notes to the consolidated financial statements.
2
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Consolidated Balance Sheet
(millions of dollars) September 30, December 31,
2005 2004
(unaudited)
ASSETS
Current Assets
Cash and short-term investments 206 187
Accounts receivable 574 627
Inventories 241 174
Other 302 120
1,323 1,108
Long-Term Investments 850 840
Plant, Property and Equipment 18,566 18,704
Other Assets 1,378 1,459
22,117 22,111
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Notes payable 383 546
Accounts payable 1,171 1,215
Accrued interest 222 214
Current portion of long-term debt 379 766
Current portion of non-recourse debt of joint ventures 71 83
2,226 2,824
Deferred Amounts 962 783
Long-Term Debt 9,781 9,713
Future Income Taxes 571 509
Non-Recourse Debt of Joint Ventures 626 779
Preferred Securities 534 554
14,700 15,162
Non-Controlling Interests 74 76
Shareholders' Equity
Preferred shares 389 389
Common shares 4,712 4,632
Contributed surplus 273 270
Retained earnings 2,067 1,653
Foreign exchange adjustment (98 ) (71 )
7,343 6,873
22,117 22,111
See accompanying notes to the consolidated financial statements.
3
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Consolidated Retained Earnings
(unaudited) Nine months ended September 30
(millions of dollars) 2005 2004
Balance at beginning of period 1,653 1,185
Net income 876 863
Preferred share dividends (17) (17)
Common share dividends (445) (421)
2,067 1,610
See accompanying notes to the consolidated financial statements.
4
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Notes to Consolidated Financial Statements
(Unaudited)
1. Significant Accounting Policies
The consolidated financial statements of TransCanada PipeLines Limited (TCPL or
the company) have been prepared in accordance with Canadian generally accepted
accounting principles (GAAP). The accounting policies applied are consistent
with those outlined in TCPL's restated audited consolidated financial statements
for the year ended December 31, 2004 except as stated below. These consolidated
financial statements reflect all normal recurring adjustments that are, in the
opinion of management, necessary to present fairly the financial position and
results of operations for the respective periods. These consolidated financial
statements do not include all disclosures required in the annual financial
statements and should be read in conjunction with the restated 2004 audited
consolidated financial statements. Amounts are stated in Canadian dollars
unless otherwise indicated. Certain comparative figures have been reclassified
to conform with the current period'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. In the opinion of
Management, these consolidated financial statements have been properly prepared
within reasonable limits of materiality and within the framework of the
company's significant accounting policies.
2. Accounting Change
Financial Instruments - Disclosure and Presentation
Effective January 1, 2005, the company adopted the provisions of the Canadian
Institute of Chartered Accountants amendment to the existing Handbook Section "
Financial Instruments - Disclosure and Presentation" which provides guidance for
classifying certain financial instruments that embody obligations that may be
settled by issuance of the issuer's equity shares as debt when the instrument
does not establish an ownership relationship. In accordance with this
amendment, TCPL reclassified the non-controlling interest component of preferred
securities as long-term debt.
This accounting change was applied retroactively with restatement of prior
periods. The impact of this change on TCPL's net income in third quarter 2005
and prior periods was nil.
5
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The impact of the accounting change on the company's consolidated balance sheet
as at December 31, 2004 is as follows.
(unaudited - millions of dollars) Increase/
(Decrease)
Deferred Amounts (1) 135
Preferred Securities 535
Non-Controlling Interest
Preferred securities of subsidiary (670)
Total Liabilities and Shareholders' Equity -
--------------------
(1) Regulatory deferral
3. Segmented Information
Three months ended Gas Transmission Power Corporate Total
September 30
(unaudited - millions of 2005 2004 2005 2004 2005 2004 2005 2004
dollars)
Revenues 1,039 945 452 362 - - 1,491 1,307
Cost of sales - - (290) (215) - - (290) (215)
Other costs and expenses (358) (293) (107) (86) (1) - (466) (379)
Depreciation (236) (218) (11) (18) - - (247) (236)
Operating income/(loss) 445 434 44 43 (1) - 488 477
Financial charges and (183) (198) - (3) (34) (25) (217) (226)
non-controlling interests
Financial charges of joint (14) (14) - (1) - - (14) (15)
ventures
Equity income 6 10 99 29 - - 105 39
Interest income and other 8 1 2 6 12 26 22 33
Gains related to Power LP - - 245 - - - 245 -
Income taxes (114) (99) (98) (23) 11 6 (201) (116)
Continuing Operations 148 134 292 51 (12) 7 428 192
Discontinued Operations - 52
Net Income Applicable to 428 244
Common Shares
Nine months ended Gas Transmission Power Corporate Total
September 30
(unaudited - millions of 2005 2004 2005 2004 2005 2004 2005 2004
dollars)
Revenues 3,066 2,842 1,276 1,165 - - 4,342 4,007
Cost of sales - - (800) (706) - - (800) (706)
Other costs and expenses (988) (876) (318) (273) (4) (3) (1,310) (1,152)
Depreciation (701) (645) (49) (55) - (750) (700)
Operating income/(loss) 1,377 1,321 109 131 (4) (3) 1,482 1,449
Financial charges and (552) (587) (2) (7) (96) (67) (650) (661)
non-controlling interests
Financial charges of joint (41) (43) (5) (2) - - (46) (45)
ventures
Equity income 21 31 142 125 - - 163 156
Interest income and other 21 6 5 11 24 41 50 58
Gain related to PipeLines 82 - - - - - 82 -
LP
Gains related to Power LP - - 245 197 - - 245 197
Gain related to Millennium - 7 - - - - - 7
Income taxes (384) (306) (130) (90) 47 29 (467) (367)
Continuing Operations 524 429 364 365 (29) - 859 794
Discontinued Operations - 52
Net Income Applicable to 859 846
Common Shares
6
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Total Assets
(millions of dollars) September 30, December 31,
2005 2004
(unaudited)
Gas Transmission 17,781 18,410
Power 3,427 2,802
Corporate 909 899
22,117 22,111
4. Risk Management and Financial Instruments
The following represents the material changes to the company's financial
instruments since December 31, 2004.
Energy Price Risk Management
The company executes power, natural gas and heat rate derivatives for overall
management of its asset portfolio. Heat rate contracts are contracts for the
sale or purchase of power that are priced based on a natural gas index. The
fair values and notional volumes of the swap, option, future and heat rate
contracts are shown in the tables below. In accordance with the company's
accounting policy, each of the derivatives in the table below is recorded on the
balance sheet at its fair value at September 30, 2005 and December 31, 2004.
Power
September 30, 2005 December 31, 2004
(unaudited)
Asset/(Liability) Accounting Fair Fair
(millions of dollars) Treatment Value Value
Power - swaps
(maturing 2005 to 2011) Hedge (123) 7
(maturing 2005 to 2010) Non-hedge 19 (2)
Gas - swaps, futures and options
(maturing 2005 to 2016) Hedge (13) (39)
(maturing 2005 to 2008) Non-hedge (16) (2)
Heat rate contracts
(maturing 2005 to 2006) Hedge - (1)
7
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Notional Volumes
September 30, 2005 Accounting Power (GWh) Gas (Bcf)
(unaudited) Treatment Purchases Sales Purchases Sales
Power - swaps
(maturing 2005 to 2011) Hedge 911 6,366 - -
(maturing 2005 to 2010) Non-hedge 1,206 220 - -
Gas - swaps, futures and options
(maturing 2005 to 2016) Hedge - - 80 71
(maturing 2005 to 2008) Non-hedge - - 26 21
Heat rate contracts
(maturing 2005 to 2006) Hedge - 44 - -
Notional Volumes Accounting Power (GWh) Gas (Bcf)
December 31, 2004 Treatment Purchases Sales Purchases Sales
Power - swaps Hedge 3,314 7,029 - -
Non-hedge 438 - - -
Gas - swaps, futures and options Hedge - - 80 84
Non-hedge - - 5 8
Heat rate contracts Hedge - 229 2 -
5. Dispositions
PipeLines LP
In March and April 2005, TCPL sold 3,547,200 common units of TC PipeLines, LP
(PipeLines LP) for net proceeds to the company of approximately $153 million and
an after-tax gain of $49 million. The net gain was recorded in the Gas
Transmission segment and the company recorded a $33 million tax charge,
including $51 million of current income tax expense, on this transaction.
Subsequent to these transactions, TCPL continues to own a 13.4 per cent interest
in PipeLines LP represented by the general partner interest of 2.0 per cent as
well as an 11.4 per cent limited partner interest.
Power LP
On August 31, 2005, TCPL closed the sale of its interest in TransCanada Power,
L.P. (Power LP) to EPCOR for net proceeds of $523 million. In third quarter
2005, TCPL realized an after-tax gain of $193 million from this sale. The net
gain was recorded in the Power segment and the company recorded a $52 million
tax charge,
8
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including $79 million of current income tax expense, on this transaction.
EPCOR's acquisition includes 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. Following the
close of the transaction, the name of the partnership changed from TransCanada
Power, L.P. to EPCOR Power L.P. (the Partnership).
Effective upon the closing of the sale, TCPL was no longer the general partner
of the Partnership and TCPL and its affiliates ceased to own Partnership units.
In addition, approximately 100 TCPL employees, who provided management,
operations and maintenance services under the contract to the Partnership,
became EPCOR employees.
6. Employee Future Benefits
The net benefit plan expense for the company's defined benefit pension plans and
other post-employment benefit plans for the three and nine months ended
September 30 is as follows.
Three months ended September 30, 2005 Pension Benefit Plans Other Benefit Plans
(unaudited - millions of dollars) 2005 2004 2005 2004
Current service cost 7 7 - 1
Interest cost 16 14 1 1
Expected return on plan assets (16) (14) - -
Amortization of transitional obligation related - - 1 1
to regulated business
Amortization of net actuarial loss 5 3 - 1
Amortization of past service costs 1 1 - -
Net benefit cost recognized 13 11 2 4
Nine months ended September 30, 2005 Pension Benefit Plans Other Benefit Plans
(unaudited - millions of dollars) 2005 2004 2005 2004
Current service cost 22 21 1 2
Interest cost 48 42 4 4
Expected return on plan assets (48) (41) - -
Amortization of transitional obligation related - - 2 2
to regulated business
Amortization of net actuarial loss 13 9 1 2
Amortization of past service costs 2 2 - -
Net benefit cost recognized 37 33 8 10
7. Subsequent Events
Bruce Power L.P.
On October 17, 2005, TCPL announced that Bruce Power L.P. (Bruce Power) and the
Ontario Power Authority (OPA), entered into a long-term agreement whereby Bruce
Power will refurbish and restart the
9
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currently idle Units 1 and 2, extend the operating life of Unit 3 by replacing
its steam generators and fuel channels when required and replace the steam
generators on Unit 4. Bruce Power's capital program for the restart and
refurbishment work is expected to total approximately $4.25 billion and TCPL's
approximate $2.125 billion share will be financed through capital contributions
over the period from 2005 to 2011. As a result of the agreement between Bruce
Power and the OPA, and Cameco Corporation's decision not to participate in the
restart and refurbishment program, a new partnership has been created.
The new Bruce Power A Limited Partnership (BALP) will sublease the Bruce A
facilities, which are comprised of Units 1 to 4, from Bruce Power. The effect of
these transactions is that TCPL and BPC Generation Infrastructure Trust each
incurred a net cash outlay of approximately $100 million and each owns a 47.4
per cent interest in BALP. The remaining 5.2 per cent is owned by the Power
Worker's Union and The Society of Energy Professionals. The day-to-day
operations of the Bruce facility will be unaffected by the formation of BALP and
TCPL continues to own 31.6 per cent of the Bruce B facilities (Units 5 to 8).
As a result of reorganizing Bruce Power, TCPL expects to proportionately
consolidate its investment in both Bruce Power and BALP, on a prospective basis
from closing. The agreement and above transactions were completed October 31,
2005 with the receipt of a favourable tax ruling from the Canada Revenue Agency.
TCPL welcomes questions from shareholders and potential investors. Please
telephone:
Investor Relations, at 1-800-361-6522 (Canada and U.S. Mainland) or direct dial
David Moneta at (403) 920-7911. The investor fax line is (403) 920-2457. Media
Relations: Kurt Kadatz/Jennifer Varey at (403) 920-7859
Visit TCPL's Internet site at: http://www.transcanada.com
10
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Exhibit 13.3
TRANSCANADA PIPELINES LIMITED
U.S. GAAP CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
Condensed Statement of Consolidated Income and Comprehensive Income in
Accordance with U.S. GAAP(1)
Three months Nine months
ended ended
September 30 September 30
(millions of dollars) 2005 2004 2005 2004
Restated Restated
Revenues 1,371 1,216 3.993 3,719
Cost of sales 264 196 726 634
Other costs and expenses 470 385 1,302 1,172
Depreciation 235 212 693 634
969 793 2,721 2,440
Operating income 402 423 1,272 1,279
Other (income)/expenses
Equity income(1) (156) (82) (301) (290)
Other (income)/expenses (2)(3) (49) 191 263 577
Dilution gain(3) - - - (40)
Income taxes 191 117 455 369
(14) 226 417 616
Net income from continuing operations - U.S. GAAP 416 197 855 663
Net income from discontinued operations - U.S. GAAP - 52 - 52
Net Income in Accordance with U.S. GAAP 416 249 855 715
Adjustments affecting comprehensive income under U.S. GAAP
Foreign currency translation adjustment, net of tax (37) (13) (27) (6)
Changes in minimum pension liability, net of tax - 25 - 75
Unrealized (loss)/gain on derivatives, net of tax(4) (59) 17 (98) (12)
Comprehensive Income in Accordance with U.S. GAAP 320 278 730 772
Reconciliation of Net Income
Three months Nine months
ended ended
September 30 September 30
(millions of dollars) 2005 2004 2005 2004
Restated
Net Income from Continuing Operations in 434 198 876 811
Accordance with Canadian GAAP
U.S. GAAP adjustments
Unrealized (loss)/gain on energy contracts(5) (28) (1) (37) 2
Tax impact of unrealized (loss)/gain on energy 10 - 13 (1)
contracts
Equity gain/(loss)(6) - 1 3 (2)
Tax impact of equity gain/(loss) - (1) (1) -
Unrealized gain/(loss) on foreign exchange and - - 1 (11)
interest rate derivatives(4)
Tax impact of gain/(loss) on foreign exchange - - - 4
and interest rate derivatives
Deferred income taxes(7) - - - (5)
Amortization of deferred gains related to Power LP(3) - - - (3)
Deferred gains related to Power LP(3) - - - (132)
Net Income from Continuing Operations in 416 197 855 663
Accordance with U.S. GAAP
1
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Condensed Statement of Consolidated Cash Flows in Accordance with U.S. GAAP(1)
Three months Nine months
ended ended
September 30 September 30
(millions of dollars) 2005 2004 2005 2004
Cash Generated from Operations
Net cash provided by operating activities 568 510 1,179 1,151
Investing Activities
Net cash provided by/(used in) investing 321 (96) (425) 307
activities
Financing Activities
Net cash used in financing activities (855) (227) (754) (654)
Effect of Foreign Exchange Rate Changes on Cash (10) (58) 12 (55)
and Short-Term Investments
Increase in Cash and Short-Term Investments 24 129 12 749
Cash and Short-Term Investments
Beginning of period 111 902 123 282
Cash and Short-Term Investments
End of period 135 1,031 135 1,031
Condensed Consolidated Balance Sheet in Accordance with U.S. GAAP (1)
(millions of dollars) September December
30, 2005 31, 2004
Current assets 1,035 907
Long-term investments(6)(8) 1,516 1,887
Plant, property and equipment 17,306 17,083
Regulatory asset(9) 2,491 2,606
Other assets 1,202 1,217
23,550 23,700
Current liabilities(10) 2,085 2,653
Deferred amounts(4)(5)(8) 942 785
Long-term debt(4) 9,800 9,753
Deferred income taxes(9) 2,933 3,048
Preferred securities(11) 534 554
Non-controlling interests 74 76
Shareholders' equity 7,182 6,831
23,550 23,700
2
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Statement of Other Comprehensive Income in Accordance with U.S. GAAP
(millions of dollars) Cumulative Minimum Cash Flow Total
Translation Pension Hedges
Account Liability (SFAS No.
(SFAS No. 133)
87)
Balance at December 31, 2004 (71) (26) (4) (101)
Unrealized loss on derivatives, net of tax of $52(4) - - (98) (98)
Foreign currency translation adjustment, net of tax of $(19) (27) - - (27)
Balance at September 30, 2005 (98) (26) (102) (226)
Balance at December 31, 2003 (40) (98) (5) (143)
Changes in minimum pension liability, net of tax of $(41) - 75 - 75
Unrealized gain on derivatives, net of tax of $5 (4) - - (12) (12)
Foreign currency translation adjustment, net of (6) - - (6)
tax of $(10)
Balance at September 30, 2004 (46) (23) (17) (86)
--------------------
(1) In accordance with U.S. GAAP, the condensed statement of
consolidated income, statement of consolidated cash flows and consolidated
balance sheet of TransCanada PipeLines Limited (TCPL or the company) are
prepared using the equity method of accounting for joint ventures. Excluding
the impact of other U.S. GAAP adjustments, the use of the proportionate
consolidation method of accounting for joint ventures, as required under
Canadian GAAP, results in the same net income and shareholders' equity.
(2) Other expenses included an allowance for funds used during
construction of $2 million for the nine months ended September 30, 2005
(September 30, 2004 - $1 million).
(3) The company recorded its investment in TransCanada Power L.P.
(Power LP) using the proportionate consolidation method for Canadian GAAP
purposes and as an equity investment for U.S. GAAP purposes. During the period
from 1997 to April 2004, the company was obligated to fund the redemption of
Power LP units in 2017. As a result, under Canadian GAAP, TCPL accounted for
the issuance of units by Power LP to third parties as a sale of a future net
revenue stream and the resulting gains were deferred and amortized to income
over the period to 2017. The redemption obligation was removed in April 2004
and the unamortized gains were recognized as income. Under U.S. GAAP, any such
gains in the period from 1997 to April 2004 are characterized as dilution gains
and, because the company was committed to fund the redemption of the units, the
gains were recorded, on an after-tax basis, as equity transactions in
shareholders' equity.
The company's accounting policy for dilution gains is to record them as income
for both Canadian and U.S. GAAP purposes, however, U.S. GAAP requires such gains
to be recorded directly in equity if there is a contemplation of reacquisition
of units. With the removal of the redemption obligation in April 2004,
3
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subsequent issuances of units by Power LP are accounted for as dilution gains in
income for both Canadian and U.S. GAAP purposes.
(4) All foreign exchange and interest rate derivatives are
recorded in the company's consolidated financial statements at fair value under
Canadian GAAP. Under the provisions of SFAS No. 133 "Accounting for Derivatives
and Hedging Activities", all derivatives are recognized as assets and
liabilities on the balance sheet and measured at fair value. For derivatives
designated as fair value hedges, changes in the fair value are recognized in
earnings together with an equal or lesser amount of changes in the fair value of
the hedged item attributable to the hedged risk. For derivatives designated as
cash flow hedges, changes in the fair value of the derivatives that are
effective in offsetting the hedged risk are recognized in other comprehensive
income until the hedged item is recognized in earnings. Any ineffective portion
of the change in fair value is recognized in earnings each period.
Substantially all of the amounts recorded in the nine months ended September 30,
2005 and 2004 as differences between U.S. and Canadian GAAP, for net income,
relate to the differences in accounting treatment with respect to the hedged
items and, for comprehensive income, relate to cash flow hedges.
(5) Substantially all of the amounts recorded in the nine months
ended September 30, 2005 and 2004 as differences between U.S. and Canadian GAAP
in respect of energy contracts relate to gains and losses on derivative energy
contracts for periods before they were documented as hedges for purposes of U.S.
GAAP and to differences in accounting with respect to physical energy trading
contracts in the U.S. and Canada.
4
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(6) Under Canadian GAAP, pre-operating costs incurred during the
commissioning phase of a new project are deferred until commercial production
levels are achieved. After such time, those costs are amortized over the
estimated life of the project. Under U.S. GAAP, such costs are expensed as
incurred. Certain start-up costs incurred by Bruce Power L.P. (an equity
investment) are required to be expensed under U.S. GAAP. Under both Canadian
GAAP and U.S. GAAP, interest is capitalized on expenditures relating to
construction of development projects actively being prepared for their intended
use. In Bruce Power L.P., under U.S. GAAP, the carrying value of development
projects against which interest is capitalized is lower due to the expensing of
pre-operating costs.
(7) Under U.S. GAAP, SFAS No. 109 "Accounting for Income Taxes"
requires that a deferred tax liability be recognized for an excess of the amount
for financial reporting over the tax basis of an investment in a 50 per cent or
less owned investee.
(8) Financial Interpretation (FIN) 45 requires the recognition of
a liability for the fair value of certain guarantees that require payments
contingent on specified types of future events. The measurement standards of
FIN 45 are applicable to guarantees entered into after January 1, 2003. For
U.S. GAAP purposes, the fair value of guarantees recorded as a liability at
September 30, 2005 was $9 million (December 31, 2004 - $9 million) and relates
to the company's equity interest in Bruce Power L.P.
(9) Under U.S. GAAP, the company is required to record a deferred
income tax liability for its cost-of-service regulated businesses. As these
deferred income taxes are recoverable through future revenues, a corresponding
regulatory asset is recorded for U.S. GAAP purposes.
(10) Current liabilities at September 30, 2005 include dividends payable
of $154 million (December 31, 2004 - $146 million) and current taxes payable of
$256 million (December 31, 2004 - $260 million).
(11) The fair value of the preferred securities at September 30, 2005
was $554 million (December 31, 2004 - $572 million). The company made preferred
securities charges payments of $36 million for the nine months ended September
30, 2005 (September 30, 2004 - $36 million).
Summarized Financial Information of Long-Term Investments
The following summarized financial information of long-term investments includes
those investments that are accounted for by the equity method under U.S. GAAP
(including those that are accounted for by the proportionate consolidation
method under Canadian GAAP).
Three months Nine months ended
ended September 30
September 30
(millions of dollars) 2005 2004 2005 2004
Income
Revenues 337 275 906 854
Other costs and expenses (138) (136) (437) (403)
Depreciation (35) (41) (111) (114)
Financial charges and other (8) (16) (57) (47)
156 82 301 290
5
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(millions of dollars) September December
30, 31,
2005 2004
Balance sheet
Current assets 358 361
Plant, property and equipment 2,600 3,020
Current liabilities (184) (248)
Deferred amounts (net) (399) (199)
Non-recourse debt (813) (1,030)
Deferred income taxes (46) (17)
Proportionate share of net assets of long-term investments 1,516 1,887
6
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Exhibit 31.1
Certifications
I, Harold N. Kvisle, certify that:
1. I have reviewed this quarterly report on Form 6-K of TransCanada
PipeLines Limited;
2. Based on my knowledge, this report does not contain any untrue statement
of a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial
information included in this report, fairly present in all material respects
the financial condition, results of operations and cash flows of the registrant
as of, and for, the periods presented in this report;
4. The registrant's other certifying officer(s) and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
(a) designed such disclosure controls and procedures, or caused such
disclosure controls and procedures to be designed under our supervision, to
ensure that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities,
particularly during the period in which this report is being prepared;
(b) evaluated the effectiveness of the registrant's disclosure
controls and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end of the
period covered by this report based on such evaluation; and
(c) disclosed in this report any change in the registrant's internal
control over financial reporting that occurred during the registrant's most
recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an
annual report) that has materially affected, or is reasonably likely to
materially affect, the registrant's internal control over financial reporting;
and
5. The registrant's other certifying officer(s) and I have disclosed,
based on our most recent evaluation of internal control over financial
reporting, to the registrant's auditors and the audit committee of the
registrant's board of directors (or persons performing the equivalent
functions):
(a) all significant deficiencies and material weaknesses in the design
or operation of internal control over financial reporting which are reasonably
likely to adversely affect the registrant's ability to record, process,
summarize and report financial information; and
(b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's internal control
over financial reporting.
Dated November 2, 2005
/s/ Harold N. Kvisle
Harold N. Kvisle
President and Chief Executive Officer
--------------------------------------------------------------------------------
Exhibit 31.2
Certifications
I, Russell K. Girling, certify that:
1. I have reviewed this quarterly report on Form 6-K of TransCanada
PipeLines Limited;
2. Based on my knowledge, this report does not contain any untrue statement
of a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial
information included in this report, fairly present in all material respects
the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this report;
4. The registrant's other certifying officer(s) and I are responsible
for establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-15(e) and 15d-15 (e)) for the registrant and have:
(a) designed such disclosure controls and procedures, or caused such
disclosure controls and procedures to be designed under our supervision, to
ensure that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities,
particularly during the period in which this report is being prepared;
(b) evaluated the effectiveness of the registrant's disclosure
controls and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end of the
period covered by this report based on such evaluation; and
(c) disclosed in this report any change in the registrant's internal
control over financial reporting that occurred during the registrant's most
recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an
annual report) that has materially affected, or is reasonably likely to
materially affect, the registrant's internal control over financial reporting;
and
5. The registrant's other certifying officer(s) and I have disclosed, based on
our most recent evaluation of internal control over financial reporting, to
the registrant's auditors and the audit committee of the registrant's board
of directors (or persons performing the equivalent functions):
(a) all significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are reasonably
likely to adversely affect the registrant's ability to record, process,
summarize and report financial information; and
(b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal control
over financial reporting.
/s/ Russell K. Girling
Dated November 2, 2005 Russell K. Girling
Executive Vice-President, Corporate Development and
Chief Financial Officer
--------------------------------------------------------------------------------
Exhibit 32.1
TRANSCANADA PIPELINES LIMITED
450 - 1st Street S.W.
Calgary, Alberta, Canada
T2P 5H1
CERTIFICATION OF CHIEF EXECUTIVE OFFICER
REGARDING PERIODIC REPORT CONTAINING
FINANCIAL STATEMENTS
I, Harold N. Kvisle, the Chief Executive Officer of TransCanada PipeLines
Limited (the "Company"), in compliance with 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, hereby certify, in
connection with the Company's Quarterly Report as filed on Form 6-K for the
period ended September 30, 2005 with the Securities and Exchange Commission (the
"Report"), that:
1. the Report fully complies with the requirements of Section 13
(a) or 15(d) of the Securities Exchange Act of 1934; and
2. the information contained in the Report fairly presents, in all material
respects, the financial condition and results of operations of the
Company.
/s/ Harold N. Kvisle
Harold N. Kvisle
Chief Executive Officer
November 2, 2005
--------------------------------------------------------------------------------
Exhibit 32.2
TRANSCANADA PIPELINES LIMITED
450 - 1st Street S.W.
Calgary, Alberta, Canada
T2P 5H1
CERTIFICATION OF CHIEF FINANCIAL OFFICER
REGARDING PERIODIC REPORT CONTAINING
FINANCIAL STATEMENTS
I, Russell K. Girling, the Chief Financial Officer of TransCanada PipeLines
Limited (the "Company"), in compliance with 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, hereby certify, in
connection with the Company's Quarterly Report as filed on Form 6-K for the
period ended September 30, 2005 with the Securities and Exchange Commission (the
"Report"), that:
1. the Report fully complies with the requirements of Section 13
(a) or 15(d) of the Securities Exchange Act of 1934; and
2. the information contained in the Report fairly presents, in all material
respects, the financial condition and results of operations of the
Company.
/s/ Russell K. Girling
Russell K. Girling
Chief Financial Officer
November 2, 2005
--------------------------------------------------------------------------------
Exhibit 99.1
TransCanada PipeLines Limited
EARNINGS COVERAGE
SEPTEMBER 30, 2005
The following financial ratios have been calculated on a consolidated basis for
the respective 12 month period ended September 30, 2005 and are based on
unaudited financial information. The financial ratios have been calculated
based on financial information prepared in accordance with Canadian generally
accepted accounting principles. The following ratios have been prepared based
on net income:
September 30,
2005
Earnings coverage on long-term debt 3.01 times
Earnings coverage on long-term debt and First Preferred Shares 2.90 times
--------------------------------------------------------------------------------
Exhibit 99.2
The securities regulatory authorities in each of the provinces and territories
of Canada
November 2, 2005
Dear Sirs
TransCanada PipeLines Limited (the "Company")
We refer to the short-form base shelf prospectus of the Company dated December
21, 2004 relating to the sale of up to $1,500,000,000 Medium Term Note
Debentures of the Company (the "Prospectus").
We are the auditors of the Company and under date of February 28, 2005 except as
to note 23 which is as of July 28, 2005, we reported on the following revised
financial statements incorporated by reference in the Prospectus:
* Consolidated balance sheets as at December 31, 2004 and
December 31, 2003; and
* Consolidated statements of income, retained earnings and cash flows for
each of the years in the three-year period ended December 31, 2004.
Also incorporated by reference in the Prospectus are the following unaudited
interim financial statements, which have been filed with the securities
regulatory authorities:
* Consolidated balance sheet as at September 30, 2005;
* Consolidated statements of income and cash flows for the three-month
and nine-month periods ended September 30, 2005 and 2004; and
* Consolidated statements of retained earnings for the nine-months
ended September 30, 2005 and 2004.
We have not audited any financial statements of the Company as at any date or
for any period subsequent to December 31, 2004. Although we have performed an
audit for the year ended December 31, 2004, the purpose and therefore the scope
of the audit was to enable us to express our opinion on the consolidated
financial statements as at December 31, 2004 and for the year then ended, but
not on the financial statements for any interim period within that year.
Therefore, we are unable to and do not express an opinion on the above-mentioned
unaudited interim consolidated financial statements or on the financial
position, results of operations or cash flows as at any date or for any period
subsequent to December 31, 2004.
--------------------------------------------------------------------------------
We have, however, performed a review of the unaudited interim consolidated
financial statements of the Company as at September 30, 2005 and for the
three-month and nine-month periods ended September 30, 2005 and 2004. We
performed our review in accordance with Canadian generally accepted standards
for a review of interim financial statements by an entity's auditors. Such an
interim review consists principally of applying analytical procedures to
financial data and making inquiries of, and having discussions with, persons
responsible for financial and accounting matters. An interim review is
substantially less in scope than an audit, whose objective is the expression of
an opinion regarding the financial statements. An interim review does not
provide assurance that we would become aware of any, or all, significant matters
that might be identified in an audit.
Based on our review, we are not aware of any material modification that needs to
be made for these interim consolidated financial statements to be in accordance
with Canadian generally accepted accounting principles.
This letter is provided solely for the purpose of assisting the securities
regulatory authority to which it is addressed in discharging its
responsibilities and should not be used for any other purpose. Any use that a
third party makes of this letter or any reliance or decisions based on it, are
the responsibility of such third parties. We accept no responsibility for loss
or damages, if any, suffered by any third party as a result of decisions made or
actions taken based on this letter.
Yours very truly
/s/ "KPMG LLP"
Chartered Accountants
Calgary, Canada
2
--------------------------------------------------------------------------------
This information is provided by RNS
The company news service from the London Stock Exchange
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