RNS Number:4162L
TransCanada Pipelines Ld
01 November 2006
6-K
0000099070
xxxxxxx
10/31/2006
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 2006
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 x
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 x
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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, 2006.
13.2 Consolidated comparative interim unaudited
financial statements of the registrant for the period ended September 30, 2006
(included in the registrant's Third Quarter 2006 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 2006 Quarterly Report.
99.1 Schedule of earnings coverage calculations at September 30, 2006.
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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/ Gregory A. Lohnes
Gregory A. Lohnes
Executive Vice-President and
Chief Financial Officer
By: /s/ G. Glenn Menuz
G. Glenn Menuz
Vice-President and Controller
November 1, 2006
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, 2006.
13.2 Consolidated comparative interim unaudited financial statements of the registrant for the period ended
September 30, 2006 (included in the registrant's Third Quarter 2006 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 2006 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, 2006.
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Exhibit 13.1
TRANSCANADA PIPELINES LIMITED - THIRD QUARTER 2006
Quarterly Report
Management's Discussion and Analysis
Management's discussion and analysis (MD&A) dated October 30, 2006 should be
read in conjunction with the accompanying unaudited consolidated financial
statements of TransCanada PipeLines Limited (TCPL or the company) for the three
and nine months ended September 30, 2006. It should also be read in conjunction
with the audited consolidated financial statements and the MD&A contained in
TCPL's 2005 Report for the year ended December 31, 2005. 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 TCPL. Amounts
are stated in Canadian dollars unless otherwise indicated. Capitalized and
abbreviated terms that are used but not otherwise defined herein have the
meanings provided in the MD&A contained in TCPL's 2005 Report.
Forward-Looking Information
Certain information in this MD&A includes forward-looking statements. All
forward-looking statements are based on TCPL's beliefs and assumptions based on
information available at the time the assumptions were made. Forward-looking
statements relate to, among other things, anticipated financial performance,
business prospects, strategies, regulatory developments, new services, market
forces, commitments and technological developments. By its nature, such
forward-looking information is subject to various risks and uncertainties,
including those material risks discussed in the MD&A contained in TCPL's 2005
Report under "Gas Transmission - Business Risks" and "Power - Business Risks",
which could cause TCPL's actual results and experience to differ materially from
the anticipated results or other expectations expressed. The material
assumptions in making these forward-looking statements are disclosed in this MD&
A under the heading "Outlook" and in the MD&A contained in the company's 2005
Report under the headings "TCPL Overview", "TCPL's Strategy", "Gas Transmission
- Opportunities and Developments", "Gas Transmission - Outlook", "Power -
Opportunities and Developments" and "Power - Outlook". Readers are cautioned not
to place undue reliance on this forward-looking information, which is given as
of the date it is expressed in this MD&A or as otherwise stated. TCPL undertakes
no obligation to update publicly or revise any forward-looking information,
whether as a result of new information, future events or otherwise, except as
required by law.
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Non-GAAP Measures
The company uses the measures "funds generated from operations" and "operating
income" in its MD&A. These measures do not have any standardized meaning in
generally accepted accounting principles (GAAP) and are therefore considered to
be non-GAAP measures. These measures may not be comparable to similar measures
presented by other entities. These measures have been used to provide readers
with additional information on the company's liquidity and its ability to
generate funds to finance its operations.
Funds generated from operations is comprised of net cash provided by operations
before changes in operating working capital. Operating income is used in the
Energy segment and is comprised of revenues plus equity income less operating
expenses as shown on the consolidated income statement. Refer to the Energy
section in this MD&A for a reconciliation of operating income to net earnings.
Results of Operations
Effective June 1, 2006, TCPL revised the composition and names of its reportable
business segments to Pipelines and Energy. Pipelines is principally comprised
of the company's pipelines in Canada, the United States and Mexico. Energy
includes the company's power operations, natural gas storage and liquefied
natural gas (LNG) businesses in Canada and the U.S. The financial reporting of
these segments was aligned to reflect the internal organizational structure of
the company. The segmented information in this MD&A has been retroactively
restated to reflect the changes in reportable segments. These changes had no
impact on consolidated net income.
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Consolidated
Segment Results-at-a-Glance
(unaudited) Three months ended September Nine months ended September
30 30
(millions of dollars except per share amounts) 2006 2005 2006 2005
Pipelines
Excluding gains 130 149 421 475
Gain on sale of Northern Border Partners, L.P. - - 13 -
interest
Gain on sale of PipeLines LP units - - - 49
130 149 434 524
Energy
Excluding gains 123 98 320 171
Gains related to Power LP - 193 - 193
123 291 320 364
Corporate 40 (12) 27 (29)
Net Income Applicable to Common Shares
Continuing operations (1) 293 428 781 859
Discontinued operations - - 28 -
293 428 809 859
(1)Net Income Applicable to Common Shares from
Continuing Operations comprised of:
Excluding gains 293 235 768 617
Gains related to Northern Border Partners, L.P. - 193 13 242
interest, PipeLines LP units and Power LP
293 428 781 859
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TCPL's net income applicable to common shares and net income applicable to
common shares from continuing operations (net earnings) for third quarter 2006
were $293 million compared to $428 million for third quarter 2005. The 2006 net
earnings were lower than 2005 by $135 million primarily due to after-tax gains
of $193 million from the sale of the company's interest in Power LP to EPCOR
Utilities Inc. (EPCOR) in third quarter 2005. Excluding these gains, the company
reported a decrease in Corporate's net expenses and an increase in Energy's net
earnings, partially offset by a decrease in Pipelines' net earnings.
The $52 million decrease in Corporate's net expenses in third quarter 2006
compared to third quarter 2005 was primarily due to an income tax benefit of
approximately $50 million on the resolution of certain income tax matters with
taxation authorities and changes in estimates during the quarter.
Excluding the gains related to the sale of the Power LP interest in third
quarter 2005, Energy's net earnings for third quarter 2006 increased $25 million
compared to third quarter 2005 primarily due to higher operating income from
Eastern and Western Power Operations and Natural Gas Storage, partially offset
by lower operating income from Bruce Power.
Pipelines' net earnings for third quarter 2006 decreased $19 million primarily
due to lower net earnings from the Canadian Mainline and Alberta System as a
result of lower rates of return on common equity (ROE) and lower average
investment bases. Net earnings from TCPL's Other Pipelines for third quarter
2006 decreased $6 million compared to third quarter 2005 primarily due to the
impact of a weaker U.S. dollar and higher project development and support costs,
partially offset by increased net earnings from Portland.
TCPL's net income applicable to common shares for the nine months ended
September 30, 2006 was $809 million which included net income from discontinued
operations of $28 million reflecting bankruptcy settlements with Mirant
Corporation and certain of its subsidiaries (Mirant) received in first quarter
2006 related to TCPL's Gas Marketing business divested in 2001. Net income
applicable to common shares for the nine months ended September 30, 2005 was
$859 million.
TCPL's net earnings for the nine months ended September 30, 2006 were $781
million compared to $859 million for the same period in 2005. The decrease of
$78 million was primarily due to gains recognized on the sales of PipeLines LP
units and the company's interest in Power LP in 2005.
Excluding the $49 million after-tax gain on the sale of PipeLines LP units in
2005 and the $13 million after-tax gain on the sale of TCPL's general partner
interest in Northern Border Partners, L.P. in 2006, Pipelines' net earnings for
the nine months ended September 30, 2006 decreased $54 million compared to the
same period in 2005. This decrease was primarily due to lower net earnings from
the Canadian Mainline and Alberta System as a result of lower ROE and lower
average investment bases in 2006 compared to 2005. In addition, the 2005 net
earnings included a positive adjustment of $13 million related to 2004,
resulting from the
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April 2005 National Energy Board (NEB) decision on Canadian Mainline's 2004
Tolls and Tariff Application (Phase II), As well, TCPL's Other Pipelines
experienced lower net earnings in 2006, compared to 2005. These decreases were
partially offset by higher net earnings from GTN, which included an $18 million
($29 million pre-tax) bankruptcy settlement with Mirant, a former shipper on the
Gas Transmission Northwest System.
Excluding the $193 million after-tax gains related to the sale of the Power LP
interest in 2005, Energy's net earnings for the nine months ended September 30,
2006 increased $149 million compared to the same period in 2005, primarily due
to higher operating income from each of its existing businesses as well as a $23
million favourable impact on future income taxes arising from reductions in
Canadian federal and provincial income tax rates enacted in second quarter 2006.
These increases were partially offset by the loss of operating income associated
with the sale in third quarter 2005 of the Power LP investment.
The decrease of $56 million in Corporate's net expenses for the nine months
ended September 30, 2006 compared to the same period in 2005 was primarily due
to the income tax benefit of approximately $50 million in third quarter 2006, as
well as a $10 million favourable impact on future income taxes in second quarter
2006 arising from reductions in Canadian federal and provincial income tax
rates.
Results from each business segment for the three and nine months ended September
30, 2006 are discussed further in the "Pipelines", "Energy" and "Corporate"
sections of this MD&A.
Funds generated from operations of $661 million and $1,716 million for the three
and nine months ended September 30, 2006 increased $157 million and $295
million, respectively, when compared to the same periods in 2005.
Pipelines
The Pipelines business generated net earnings of $130 million and $434 million
for the three and nine months ended September 30, 2006, respectively, compared
to $149 million and $524 million for the same periods in 2005.
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Pipelines Results-at-a-Glance
(unaudited) Three months ended September Nine months ended September
30 30
(millions of dollars) 2006 2005 2006 2005
Wholly-Owned Pipelines
Canadian Mainline 59 67 179 216
Alberta System 35 38 102 112
GTN 12 14 57 53
Foothills System 5 5 16 16
BC System 2 2 5 5
113 126 359 402
Other Pipelines
Great Lakes 10 11 33 36
Iroquois 4 7 11 14
Portland 6 1 10 7
PipeLines LP (1) 2 3 7
Ventures LP 3 3 9 9
TQM 2 2 5 5
TransGas 3 2 8 8
Gas Pacifico/INNERGY 1 2 5 2
Northern Development (1) (1) (3) (3)
General, administrative, support costs and other (10) (6) (19) (12)
17 23 62 73
Gain on sale of Northern Border Partners, L.P. - - 13 -
interest
Gain on sale of PipeLines LP units - - - 49
17 23 75 122
Net Earnings 130 149 434 524
Wholly-Owned Pipelines
Canadian Mainline's third quarter 2006 net earnings decreased $8 million
compared to third quarter 2005 primarily due to a lower ROE, as determined by
the NEB, of 8.88 per cent in 2006 compared to 9.46 per cent in 2005, and a lower
average investment base. Net earnings for the nine months ended September 30,
2006 decreased $37 million compared to the corresponding period in 2005. This
decrease was due to a combination of a lower ROE and a lower average investment
base in 2006, compared to 2005. In addition, the 2005 net earnings included a
positive adjustment of $13 million related to 2004, as a result of the NEB's
decision in April 2005 on Canadian Mainline's 2004 Tolls and Tariff Application
(Phase II). This NEB decision included an increase in the deemed common equity
ratio from 33 per cent to 36 per cent for 2004 which was also effective for 2005
under the 2005 tolls settlement with shippers.
The Alberta System's net earnings of $35 million and $102 million for the three
and nine months ended September 30, 2006 decreased $3 million and $10 million,
respectively, compared to the same periods in 2005. The decreases were
primarily due to a lower investment base and a lower ROE in 2006. Net earnings
in 2006 reflect an ROE of 8.93 per cent on a deemed common equity of 35 per cent
compared to an ROE of 9.50 per cent on a deemed common equity of 35 per cent in
2005.
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GTN's net earnings for the three months ended September 30, 2006 were $12
million, a $2 million decrease from the same period in 2005. This decrease was
primarily due to lower transportation revenues in 2006. GTN's net earnings for
the nine months ended September 30, 2006 were $57 million, a $4 million increase
over the same period in 2005. This increase was primarily due to an $18 million
bankruptcy settlement ($29 million pre-tax) in first quarter 2006 with Mirant, a
former shipper on the Gas Transmission Northwest System. Partially offsetting
this increase were lower transportation revenues, the negative impact of a
weaker U.S. dollar and a provision for non-payment of contract transportation
revenue from a subsidiary of Calpine Corporation that has filed for bankruptcy
protection.
Operating Statistics
Gas Transmission
Nine months ended Canadian Alberta Northwest
September 30 Mainline(1) System(2) System(3) Foothills System BC System
(unaudited) 2006 2005 2006 2005 2006 2005 2006 2005 2006 2005
Average
investment base
($ millions) 7,450 7,839 4,293 4,478 n/a n/a 649 683 207 218
Delivery volumes
(Bcf)
Total 2,209 2,181 3,033 2,918 592 581 795 788 256 236
Average per day 8.1 8.0 11.1 10.7 2.2 2.1 2.9 2.9 0.9 0.9
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(1) Canadian Mainline deliveries originating at the Alberta
border and in Saskatchewan for the nine months ended September 30, 2006 were
1,694 Bcf (2005 - 1,605 Bcf); average per day was 6.2 Bcf (2005 - 5.9 Bcf).
(2) Field receipt volumes for the Alberta System for the nine
months ended September 30, 2006 were 3,133 Bcf (2005 - 3,010 Bcf); average per
day was 11.5 Bcf (2005 - 11.0 Bcf).
(3) The Gas Transmission Northwest System operates under a fixed
rate model approved by the United States Federal Energy Regulatory Commission
(FERC) and, as a result, the system's current results are not dependent on
average investment base.
Other Pipelines
TCPL's proportionate share of net earnings from Other Pipelines was $17 million
for the three months ended September 30, 2006 compared to $23 million for the
same period in 2005. Increased net earnings from Portland, primarily due to a
bankruptcy settlement received in third quarter 2006, were more than offset by
the impact of higher project development and support costs in 2006, lower net
earnings from Iroquois reflecting customer bankruptcy settlements received in
third quarter 2005 and lower net earnings from PipeLines LP.
Net earnings for the nine months ended September 30, 2006 were $75 million
compared to $122 million for the corresponding period in 2005. Excluding the
$13 million gain on the sale of the Northern Border Partners, L.P. interest in
2006, and the $49 million gain on the sale of PipeLines LP units in 2005,
year-to-date net earnings were $11 million lower compared to the same period in
2005. Increased net earnings from Portland due to the bankruptcy settlement
received in third quarter 2006
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were partially offset by provisions recorded in second and third quarter 2006
for non-payment of contract transportation revenue from a subsidiary of Calpine
Corporation that has filed for bankruptcy protection. This increase was more
than offset by bankruptcy settlements received by Iroquois in third quarter
2005, a weaker U.S. dollar, reduced ownership in PipeLines LP and higher support
costs. In addition, Gas Pacifico/INNERGY generated higher earnings in 2006 as a
result of natural gas curtailments that negatively affected 2005 net earnings.
As at September 30, 2006, TCPL had advanced $111 million to the Aboriginal
Pipeline Group with respect to the Mackenzie Gas Pipeline Project and had
capitalized $21 million related to the Keystone pipeline.
Energy
Energy Results-at-a-Glance
(unaudited) Three months ended September 30 Nine months ended September 30
(millions of dollars) 2006 2005 2006 2005
Bruce Power 72 99 176 142
Western Power Operations 84 32 188 90
Eastern Power Operations 40 25 132 69
Natural Gas Storage 24 4 63 15
Power LP Investment - 12 - 29
General, administrative and support costs (35) (30) (100) (93)
Operating income 185 142 459 252
Financial charges (5) - (17) (7)
Interest income and other 2 2 5 5
Income taxes (59) (46) (127) (79)
123 98 320 171
Gains related to Power LP - 193 - 193
Net Earnings 123 291 320 364
Energy's net earnings were $123 million in third quarter 2006, compared to $291
million in third quarter 2005. In third quarter 2005, TCPL recognized gains of
$193 million on the sale of the Power LP interest.
Excluding the gains of $193 million in 2005, Energy's net earnings of $123
million in third quarter 2006 increased $25 million compared to $98 million in
third quarter 2005 due to higher operating income from Western and Eastern Power
Operations and Natural Gas Storage. Partially offsetting these increases were
lower operating income from Bruce Power and the loss of income associated with
the sale of the Power LP interest in third quarter 2005.
Bruce Power's contribution to operating income decreased $27 million in third
quarter 2006 compared to third quarter 2005, primarily due to lower overall
realized prices, partially offset by higher generation volumes.
Western Power Operations' operating income was $52 million higher in third
quarter 2006 compared to third quarter 2005 primarily due to incremental
earnings from the December 31, 2005 acquisition of the 756 megawatt (MW)
Sheerness power purchase arrangement (PPA) and improved
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margins from higher overall realized power prices and higher market heat rates
on uncontracted volumes of power sold.
Eastern Power Operations' operating income was $15 million higher in third
quarter 2006 compared to third quarter 2005 primarily due to higher overall
margins on higher power sales volumes and increased generation from the TC Hydro
facilities resulting from higher water flows.
Natural Gas Storage operating income increased $20 million in third quarter 2006
compared to third quarter 2005 primarily due to higher contributions from
CrossAlta as a result of increased storage capacity and higher natural gas
storage spreads.
Excluding the gains of $193 million on the sale of the Power LP interest in
2005, Energy's net earnings for the nine months ended September 30, 2006 of $320
million increased $149 million compared to $171 million for the same period in
2005. The increase was due to higher contributions from each of its existing
businesses and the $23 million decrease in future income taxes resulting from
reductions in Canadian federal and provincial corporate income tax rates enacted
in second quarter 2006. Partially offsetting these increases was the loss of
operating income associated with the sale of the Power LP interest in third
quarter 2005 and reduced earnings due to a weaker U.S. dollar.
Bruce Power
Effective October 31, 2005, TCPL increased its interest in the Bruce A units
through the formation of the Bruce A partnership. Bruce A subleases its
facilities from Bruce B. TCPL commenced proportionately consolidating its
investments in Bruce A and Bruce B effective October 31, 2005. The following
Bruce Power financial results reflect the operations of the full six-unit
facility for both periods.
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Bruce Power Results-at-a-Glance(1)
Three months ended September Nine months ended September 30
30
(unaudited) 2006 2005 2006 2005
Bruce Power (100 per cent basis)
(millions of dollars)
Revenues
Power 478 635 1,396 1,431
Other (2) 15 7 43 22
493 642 1,439 1,453
Operating expenses
Operations and maintenance (210) (207) (656) (640)
Fuel (26) (21) (68) (58)
Supplemental rent (42) (41) (127) (123)
Depreciation and amortization (34) (48) (99) (145)
(312) (317) (950) (966)
Revenues, net of operating expenses 181 325 489 487
Financial charges under equity accounting - (18) - (52)
181 307 489 435
TCPL's proportionate share 69 97 170 137
Adjustments 3 2 6 5
TCPL'S operating income from Bruce Power (3) 72 99 176 142
Bruce Power - Other Information
Plant availability
Bruce A 86% 76%
Bruce B 92% 94%
Combined Bruce Power 90% 88% 88% 80%
Sales volumes (GWh) (4)
Bruce A - 100 per cent 2,850 7,440
Bruce B - 100 per cent 6,540 19,790
Combined Bruce Power - 100 per cent 9,390 9,130 27,230 24,648
TCPL' s proportionate share 3,448 2,882 9,848 7,786
Results per MWh (5)
Bruce A revenues $ 59 $ 58
Bruce B revenues $ 48 $ 49
Combined Bruce Power revenues $ 51 $ 70 $ 51 $ 58
Fuel $ 3 $ 2 $ 2 $ 2
Total operating expenses(6) $ 32 $ 35 $ 34 $ 39
Percentage of output sold to spot market 33% 60% 37% 53%
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(1) All information in the table includes adjustments to
eliminate the effects of inter-partnership transactions between Bruce A and
Bruce B.
(2) Includes fuel cost recoveries for Bruce A of $9 million and
$19 million, respectively, for the three and nine months ended September 30,
2006.
(3) TCPL's consolidated equity income includes $99 million and
$142 million, respectively, for the three and nine months ended September 30,
2005 representing TCPL's 31.6 per cent share of Bruce Power earnings for the
period.
(4) Gigawatt hours.
(5) Megawatt hours.
(6) Net of fuel cost recoveries.
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TCPL's operating income of $72 million from its combined investment in Bruce
Power decreased $27 million in third quarter 2006 compared to third quarter
2005, primarily due to the negative impact of lower realized prices, partially
offset by the positive impact of higher generation volumes.
TCPL's share of Bruce Power's generation for third quarter 2006 increased 566
GWh to 3,448 GWh compared to third quarter 2005 generation of 2,882 GWh as a
result of fewer planned maintenance outage days in third quarter 2006 compared
to third quarter 2005 and an increased ownership interest in the Bruce A
facilities. Bruce Power prices achieved during third quarter 2006 (excluding
other revenues) were $51 per MWh, compared to $70 per MWh in third quarter 2005.
Bruce Power's operating expenses (net of fuel cost recoveries) in third
quarter 2006 decreased to $32 per MWh from $35 per MWh in third quarter 2005
primarily due to increased output in third quarter 2006.
Approximately 22 reactor days of planned maintenance outages as well as
approximately 20 reactor days of unplanned outages occurred on the six operating
units in third quarter 2006. In third quarter 2005, Bruce Power experienced 32
reactor days of planned maintenance outages and 21 reactor days of unplanned
outages. The Bruce Power units ran at a combined average availability of 90 per
cent in third quarter 2006, compared to an 88 per cent average availability
during third quarter 2005.
TCPL's operating income from its combined investment in Bruce Power for the nine
months ended September 30, 2006 was $176 million compared to $142 million for
the same period in 2005. The increase of $34 million was primarily due to
higher sales volumes resulting from increased plant availability and an
increased ownership interest in the Bruce A facilities.
Combined Bruce Power prices achieved for the nine months ended September 30,
2006 (excluding other revenues) were $51 per MWh compared to $58 per MWh for the
same period in 2005. Bruce Power's combined operating expenses (net of fuel
cost recoveries) decreased to $34 per MWh for the nine months ended September
30, 2006 from $39 per MWh in 2005 primarily due to increased output in 2006.
The Bruce units ran at a combined average availability of 88 per cent in the
nine months ended September 30, 2006 compared to 80 per cent in the same period
of 2005.
The overall plant availability percentage in 2006 is still expected to be in the
low 90s for the four Bruce B units and in the low 80s for the two operating
Bruce A units. A planned one month maintenance outage on Bruce A Unit 3 during
first quarter 2006 and a planned two month maintenance outage on Bruce A Unit 4
during second quarter 2006 were completed. The planned maintenance outage for
2006 for Bruce B Unit 8 began in September 2006 and is expected to last
approximately two months.
Income from Bruce B is directly impacted by the fluctuations in wholesale spot
market prices for electricity. Income from both Bruce A and Bruce B units is
impacted by overall plant availability, which in turn is impacted by scheduled
and unscheduled maintenance. As a result of a contract with the Ontario Power
Authority (OPA), in first quarter 2006 all of the output from Bruce A was sold
at a
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fixed price of $57.37 per MWh (before recovery of fuel costs from the OPA) and
sales from the Bruce B Units 5 to 8 were subject to a floor price of $45 per
MWh. Both of these reference prices are adjusted annually on April 1 for
inflation and other potential adjustments in accordance with the terms of the
contract with OPA. Effective April 1, 2006, the Bruce A price is $58.63 per MWh
and the Bruce B floor price is $45.99 per MWh. Payments received pursuant to
the Bruce B floor price mechanism may be subject to refund dependent on spot
prices over the term of the contract. Bruce B net earnings included no amounts
received under this floor mechanism to date. To further reduce its exposure to
spot market prices, Bruce B has entered into fixed price sales contracts to sell
forward approximately 3,300 GWh of output for the remainder of 2006 and 6,700
GWh of output for 2007.
The capital cost of Bruce A's four unit, seven year restart and refurbishment
project is expected to total approximately $4.25 billion with TCPL's share being
approximately $2.125 billion. As at September 30, 2006, Bruce A had incurred
$806 million with respect to the restart and refurbishment project.
Western Power Operations
Western Power Operations Results-at-a-Glance
(unaudited) Three months ended September Nine months ended September
30 30
(millions of dollars) 2006 2005 2006 2005
Revenues
Power 311 165 807 480
Other (1) 32 29 134 108
343 194 941 588
Cost of sales
Power (194) (105) (534) (313)
Other (1) (27) (17) (103) (67)
(221) (122) (637) (380)
Other costs and expenses (32) (34) (100) (102)
Depreciation (6) (6) (16) (16)
Operating income 84 32 188 90
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(1) Other includes Cancarb Thermax and natural gas.
Western Power Operations Sales Volumes
(unaudited) Three months ended September 30 Nine months ended September 30
(GWh) 2006 2005 2006 2005
Supply
Generation 599 544 1,622 1,691
Purchased
Sundance A & B and Sheerness PPAs 3,283 1,593 9,520 5,137
Other purchases 455 658 1,460 2,003
4,337 2,795 12,602 8,831
Contracted vs. Spot
Contracted 2,818 2,423 7,976 7,570
Spot 1,519 372 4,626 1,261
4,337 2,795 12,602 8,831
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Western Power Operations' operating income of $84 million and $188 million for
the three and nine months ended September 30, 2006 increased $52 million and $98
million, respectively, compared to the same periods in 2005. These increases
were primarily due to incremental earnings from the December 31, 2005
acquisition of the 756 MW Sheerness PPA and increased margins from a combination
of higher overall realized power prices and higher market heat rates on
uncontracted volumes of power sold. The market heat rate is determined by
dividing the average price of power per MWh by the average price of natural gas
per gigajoule (GJ) for a given period. Market heat rates in third quarter 2006
increased by approximately 141 per cent as a result of an approximate 42 per
cent ($27.95 per MWh) increase in spot market power prices, while average spot
market natural gas prices in Alberta decreased by approximately 39 per cent
($3.45 per GJ) compared to the same quarter in 2005. A significant portion of
power sales volumes were sold by the company into the spot market in third
quarter 2006, compared to 2005, due to the acquisition of the Sheerness PPA on
December 31, 2005. TCPL manages the sale of its supply volumes on a portfolio
basis. Depending on market conditions, TCPL will commit a portion of this
supply to long-term sales arrangements with the remaining volumes subject to
spot market price volatility. 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 sales obligations.
Power revenues and cost of sales increased in third quarter 2006 compared to
third quarter 2005 primarily due to the acquisition of the Sheerness PPA,
effective December 31, 2005, and higher overall realized power prices in third
quarter 2006. Generation volumes of 599 GWh in third quarter 2006 increased 55
GWh compared to third quarter 2005 primarily due to the return to service of the
Bear Creek facility in August 2006 and planned maintenance outages at the
Carseland facility in 2005. The company's purchased power volumes and
percentage of power volumes sold in the Alberta spot market increased in third
quarter 2006 compared to 2005 due to the acquisition of the Sheerness PPA. A
significant portion of the Sheerness PPA purchased volumes were not sold under
contract and were subject to spot market prices. As a result, approximately 35
per cent of power sales volumes were sold into the spot market in third quarter
2006 compared to 13 per cent in third quarter 2005. To reduce its exposure to
spot market prices on uncontracted volumes, as at September 30, 2006, Western
Power Operations had fixed price power sales contracts to sell approximately
3,200 GWh for the remainder of 2006 and approximately 10,300 GWh for 2007.
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14
Eastern Power Operations
Eastern Power Operations Results-at-a-Glance
(unaudited) Three months ended September Nine months ended September
30 30
(millions of dollars) 2006 2005 2006 2005
Revenue
Power 192 136 527 380
Other (1) 49 111 224 254
241 247 751 634
Cost of sales
Power (94) (70) (284) (183)
Other (1) (47) (98) (196) (237)
(141) (168) (480) (420)
Other costs and expenses (53) (46) (118) (127)
Depreciation (7) (8) (21) (18)
Operating income 40 25 132 69
--------------------
(1) Other includes natural gas.
Eastern Power Operations Sales Volumes
(unaudited) Three months ended September Nine months ended September 30
30
(GWh) 2006 2005 2006 2005
Supply
Generation 1,039 600 2,693 2,006
Purchased 934 833 2,331 2,138
1,973 1,433 5,024 4,144
Contracted vs. Spot
Contracted 1,829 1,348 4,715 3,765
Spot 144 85 309 379
1,973 1,433 5,024 4,144
Eastern Power Operations' operating income was $15 million higher in third
quarter 2006 compared to third quarter 2005 primarily due to higher overall
margins on higher sales volumes and increased generation from the TC Hydro
facilities resulting from higher water flows. The 550 MW Becancour cogeneration
plant was placed in service in late third quarter 2006 and therefore its
contribution to operating income was not significant.
Operating income for the nine months ended September 30, 2006 was $132 million
or $63 million higher than the $69 million earned in the same period of 2005.
The increase was primarily due to incremental income from the April 1, 2005
acquisition of the TC Hydro generation assets, a $10 million ($16 million
pre-tax) first quarter 2005 one-time restructuring payment from OSP to its
natural gas fuel suppliers, margins earned in first quarter 2006 on
transportation related to unutilized OSP natural gas fuel, higher overall
margins on higher power sales volumes and profits earned on natural gas
purchased and resold under the OSP gas supply contracts. Partially offsetting
these increases was the negative impact of a weaker U.S. dollar in 2006 compared
to 2005.
Generation volumes in third quarter 2006 increased 439 GWh to 1,039 GWh compared
to third quarter 2005 due to increased dispatch
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15
of the OSP facility, increased output from the TC Hydro generation assets
resulting from higher water flows and the placing in service of the Becancour
facility.
Power revenues of $192 million increased $56 million in third quarter 2006
compared to third quarter 2005 due to increased sales volumes and higher
realized prices. Power cost of sales of $94 million was higher in third quarter
2006 compared to third quarter 2005 due to the impact of increased purchased
volumes and higher prices. Purchased power volumes of 934 GWh were higher in
third quarter 2006 to supply increased sales volumes. Third quarter 2006 other
revenue and other cost of sales of $49 million and $47 million, respectively,
decreased year-over-year primarily as a result of a reduction in the quantity of
natural gas being resold under the OSP natural gas sales contracts and lower gas
prices. Other costs and expenses in third quarter 2006 of $53 million, which
includes fuel gas consumed in generation, increased from the prior year
primarily as a result of the placing in service of the Becancour facility.
In third quarter 2006, approximately seven per cent of power sales volumes were
sold into the spot market compared to approximately six per cent in third
quarter 2005. Eastern Power 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, 2006, Eastern Power Operations had entered into fixed price power
sales contracts to sell approximately 2,500 GWh for the remainder of 2006 and
approximately 9,600 GWh for 2007, although certain contracted volumes are
dependent on customer usage levels.
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16
Power Sales Volumes and Plant Availability
Power Sales Volumes
(unaudited) Three months ended September Nine months ended September 30
30
(GWh) 2006 2005 2006 2005
Bruce Power (1) 3,448 2,882 9,848 7,786
Western Power Operations (2) 4,337 2,795 12,602 8,831
Eastern Power Operations (3) 1,973 1,433 5,024 4,144
Power LP Investment (4) - 445 - 1,865
Total 9,758 7,555 27,474 22,626
--------------------
(1) Sales volumes reflect TCPL's proportionate share of Bruce
Power output.
(2) The Sheerness PPA volumes are included in Western Power
Operations effective December 31, 2005.
(3) TC Hydro is included in Eastern Power Operations effective
April 1, 2005. Becancour is included in Eastern Power Operations effective
September 17, 2006.
(4) TCPL operated and managed Power LP until August 31, 2005. The
volumes in the table represent 100 per cent of Power LP's sales volumes up to
August 31, 2005.
Weighted Average Plant Availability (1)
Three months ended September Nine months ended September
30 30
(unaudited) 2006 2005 2006 2005
Bruce Power 90% 88% 88% 80%
Western Power Operations 94% 89% 86% 86%
Eastern Power Operations (2) 98% 84% 97% 81%
Power LP Invest ment (3) 96% 93%
All plants, excluding Bruce Power 97% 88% 94% 85%
All plants 93% 89% 90% 81%
--------------------
(1) Plant availability represents the percentage of time in the
period that the plant is available to generate power, even if the plant is not
operating, reduced by planned and unplanned outages.
(2) TC Hydro is included in Eastern Power Operations effective
April 1, 2005. Becancour is included in Eastern Power Operations effective
September 17, 2006.
(3) Power LP is included up to August 31, 2005.
Natural Gas Storage
Natural Gas Storage operating income of $24 million and $63 million for the
three and nine months ended September 30, 2006, respectively, increased $20
million and $48 million, respectively, compared to the same periods in 2005.
The increases were primarily due to higher contributions from CrossAlta as a
result of increased capacity and higher natural gas storage spreads, and income
from other contracted third party natural gas storage capacity in Alberta.
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17
General, Administrative and Support Costs
General, administrative and support costs of $35 million and $100 million for
the three and nine months ended September 30, 2006, respectively, increased $5
million and $7 million compared to the same periods in 2005. The increases were
primarily due to higher business development costs.
As at September 30, 2006, TCPL had capitalized $26 million related to the
Broadwater LNG project.
Corporate
Net earnings from Corporate for the three and nine months ended September 30,
2006 were $40 million and $27 million, respectively, compared to net expenses of
$12 million and $29 million for the same periods in 2005.
The $52 million decrease in net expenses for third quarter 2006, compared to the
same period in 2005, was primarily due to an income tax benefit of approximately
$50 million on the resolution of certain income tax matters with taxation
authorities and changes in estimates during the quarter.
The $56 million decrease in net expenses for the nine months ended September 30,
2006, compared to the same period in 2005, was primarily due to the $50 million
income tax benefit in third quarter 2006, as well as a $10 million favourable
impact on future income taxes arising from reductions in Canadian federal and
provincial corporate income tax rates enacted in second quarter 2006. In
addition, net earnings were positively impacted by increased interest income and
other and the favourable impact of a weaker U.S. dollar. Partially offsetting
these decreases in net expenses were income tax refunds and positive income tax
adjustments recorded in the nine months ended September 30, 2005.
Liquidity and Capital Resources
Funds Generated from Operations
Funds generated from operations were $661 million and $1,716 million for the
three and nine months ended September 30, 2006, respectively, compared to $504
million and $1,421 million for the same periods in 2005.
TCPL expects that its ability to generate adequate amounts of cash in the short
and long term, when needed, and to maintain financial capacity and flexibility
to provide for planned growth remains substantially unchanged since December 31,
2005.
Investing Activities
In the three and nine months ended September 30, 2006, capital expenditures
totalled $372 million (2005 - $166 million) and $1,002 million (2005 - $409
million), respectively, and related primarily to the restart and refurbishment
of Bruce A Units 1 and 2, construction of new power plants, the Tamazunchale
pipeline and the Edson natural gas storage facilities as well as maintenance and
other capacity capital
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18
expenditures in the Pipelines business.
Acquisitions for the nine months ended September 30, 2006 were $358 million
(2005 - $632 million). In second quarter 2006, PipeLines LP acquired an
additional 20 per cent general partnership interest in Northern Border. In
2005, TCPL acquired TC Hydro generation assets and an additional 3.52 per cent
interest in Iroquois.
In the three and nine months ended September 30, 2006, disposition of assets,
net of current income tax, generated nil (2005 - $444 million) and $23 million
(2005 - $546 million), respectively. The disposition in 2006 related to the
sale of TCPL's 17.5 per cent general partner interest in Northern Border
Partners, L.P. The dispositions in 2005 related to the sale of TCPL's ownership
interest in Power LP and PipeLines LP units.
Financing Activities
TCPL retired $4 million and $352 million of long-term debt in the three and nine
months ended September 30, 2006, respectively. TCPL issued $1,250 million of
long-term debt in the nine months ended September 30, 2006. For the three
months ended September 30, 2006, notes payable increased $4 million while, for
the nine months ended September 30, 2006, notes payable decreased $449 million.
In October 2006, the company issued $400 million of 4.65 per cent medium-term
notes, due October 2016. The proceeds were used to reduce the company's notes
payable.
Cash and short-term investments for the three and nine months ended September
30, 2006 increased $18 million and $118 million, respectively.
Dividends
On October 30, 2006, TCPL's Board of Directors declared a dividend for the
quarter ending December 31, 2006 in an aggregate amount equal to the aggregate
quarterly dividend to be paid on January 31, 2007 by TransCanada Corporation on
the issued and outstanding common shares as at the close of business on December
29, 2006. The board also declared regular dividends on TCPL's preferred shares.
Contractual Obligations
Energy's future capital expenditure obligations at September 30, 2006 increased
compared to December 31, 2005, primarily as a result of TCPL's commitment with
OPA to construct the Portland Energy Centre (PEC), as discussed in the Other
Recent Developments section of this MD&A.
Other than the PEC commitment, there have been no material changes to TCPL's
contractual obligations from December 31, 2005 to September 30, 2006, 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 2005 Report.
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19
Financial and Other Instruments
The following represents the material changes to the company's financial
instruments since December 31, 2005.
Energy Price Risk Management
The company executes power, natural gas and heat rate derivatives for overall
management of its asset portfolio. Heat rate contracts are contracts for the
sale or purchase of power that are priced based on a natural gas index. The
fair value and notional volumes of contracts for differences and the swap,
future, option and heat rate contracts are shown in the tables below.
Power
September 30,
2006
(unaudited) December 31,
2005
Asset/(Liability) Accounting Fair Fair
(millions of dollars) Treatment Value Value
Power - swaps and contracts for differences
(maturing 2006 to 2011) Hedge (89) (130)
(maturing 2006 to 2010) Non-hedge (6) 13
Gas - swaps and futures
(maturing 2006 to 2016) Hedge (58) 17
(maturing 2006 to 2008) Non-hedge 26 (11)
Notional Volumes
September 30, 2006 Accounting Power (GWh) Gas (Bcf)
(unaudited) Treatment Purchases Sales Purchases Sales
Power - swaps and contracts for differences
(maturing 2006 to 2011) Hedge 4,946 11,189 - -
(maturing 2006 to 2010) Non-hedge 1,465 917 - -
Gas - swaps and futures
(maturing 2006 to 2016) Hedge - - 81 60
(maturing 2006 to 2008) Non-hedge - - 15 20
Heat rate contracts
(maturing 2006) Non-hedge - 12 - -
Notional Volumes
Accounting Power (GWh) Gas (Bcf)
December 31, 2005 Treatment Purchases Sales Purchases Sales
Power - swaps and contracts for differences
Hedge 2,556 7,780 - -
Non-hedge 1,332 456 - -
Gas - swaps and futures Hedge - - 91 69
Non-hedge - - 15 18
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20
Certain of the company's joint ventures use power derivatives to manage energy
price risk exposures. The company's proportionate share of the fair value of
these outstanding power sales derivatives at September 30, 2006 was $55 million
(December 31, 2005 - $(38) million) and relates to contracts which cover the
period 2006 to 2010. The company's proportionate share of the notional sales
volumes associated with this exposure at September 30, 2006 was 4,500 GWh
(December 31, 2005 - 2,058 GWh).
Risk Management
TCPL's market, financial and counterparty risks remain substantially unchanged
since December 31, 2005. For further information on risks, refer to the MD&A in
TCPL's 2005 Report.
Controls and Procedures
As of September 30, 2006, 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 and reaffirmed 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,
2005, 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 2005 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, 2005 continues to be depreciation expense. For further information
on this critical accounting estimate, refer to the MD&A in TCPL's 2005 Report.
Outlook
In 2006, TCPL expects higher net income than originally anticipated due to the
income tax benefit of approximately $50 million on the resolution of certain
income tax matters with taxation authorities and changes in estimates during the
quarter, the $33 million favourable impact of Canadian federal and provincial
corporate income tax rate reductions, improved Energy results to date and net
income from discontinued operations as a result of bankruptcy settlements
received from Mirant.
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21
Excluding these impacts, the company's outlook is relatively unchanged since
December 31, 2005. For further information on outlook, refer to the MD&A in
TCPL's 2005 Report.
In 2006, 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
Pipelines and Energy.
Credit ratings on senior unsecured debt assigned by Dominion Bond Rating Service
Limited (DBRS), 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
Pipelines
Wholly-Owned Pipelines
Gas Transmission Northwest System
In June 2006, the Gas Transmission Northwest System filed a rate case with the
FERC. The comprehensive filing requests a number of tariff changes including an
increase in rates for transportation services. The current rates are based on
the last rate case filed in 1994. The proposed rates include an ROE of 14.5 per
cent, a common equity ratio of 62.99 per cent and a depreciation rate for the
transmission plant of 2.76 per cent.
GTN anticipates receiving a procedural order from the FERC in first quarter
2007, and this order will establish a timeline for GTN's rate case proceedings.
North Baja Pipeline Expansion
On February 7, 2006, TCPL's North Baja Pipeline filed an application with the
FERC to expand and modify its existing system to facilitate the importation of
more than 2.7 billion cubic feet per day (Bcf /d) of regasified LNG from Mexico
into the California and Arizona markets. Specifically, North Baja proposes to
modify its existing system to accommodate bi-directional natural gas flow,
construct a new meter station and a 36 inch pipeline interconnect with Southern
California Gas Company (SoCal Gas), construct approximately 74 kilometres of
lateral facilities to serve electric generation facilities, and loop its entire
approximate 129 kilometres existing system with a combination of 42 inch and 48
inch diameter pipeline. On October 6, 2006, the FERC
--------------------------------------------------------------------------------
22
issued a preliminary determination approving all aspects of North Baja's
proposal other than those related to environmental issues, which will be the
subject of a future order.
Tamazunchale
In September 2006, TCPL entered the commissioning phase of construction of its
Tamazunchale pipeline in east-central Mexico. The 130 kilometre pipeline is
expected to begin commercial operations in December 2006 and will initially
transport 170 million cubic feet per day (mmcf/d) of natural gas from the PEMEX
gas pipeline system near Naranjos, Veracruz, Mexico to an electricity generation
station near Tamazunchale, San Luis Potosi, Mexico. Under the current contract
with the Comision Federal de Electricidad, the capacity of the Tamazunchale
pipeline will be expanded beginning in 2009 to approximately 430 mmcf/d to meet
the needs of two additional proposed power plants near Tamazunchale.
Other Pipelines
In September 2006, Northern Border reached a settlement with its participant
customers regarding its pending rate case before the FERC. The settlement,
which establishes maximum long-term rates and charges for transportation on the
Northern Border system, and is supported by the FERC trial staff, was certified
by the administrative law judge presiding over the case and forwarded to the
FERC for approval. The approval process is expected to be completed by late
2006.
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23
Northern Development
Mackenzie Gas Pipeline Project public hearings are expected to conclude in April
2007. The hearings are held by a Joint Review Panel, which focuses on
environmental and socio-economic impacts, and the NEB, which is reviewing all
other matters including pipeline engineering, safety, need and economic
feasibility. Concurrently, the project proponents are re-assessing the capital
cost estimate and construction schedule for the project, in light of overall
industry cost escalations and labour shortages.
Keystone Pipeline
In April 2006, TCPL filed an application with the U.S. Department of State for a
Presidential Permit authorizing the construction, operation and maintenance of
the Keystone pipeline. In September 2006, the Department of State issued a
formal notice of the application as well as a Notice of Intent to prepare an
Environmental Impact Statement for the project.
In June 2006, TCPL Keystone Pipeline LP (Keystone LP) filed a petition with the
Illinois Commerce Commission for a certificate authorizing the pipeline and
granting authority to exercise eminent domain. The matter is expected to go to
hearing in mid-November 2006.
In June 2006, TCPL and Keystone LP filed an application with the NEB seeking
approval to transfer a portion of the Canadian Mainline to the Keystone
pipeline. As part of the transfer application, TCPL is also seeking approval to
reduce the Canadian Mainline's rate base by the net book value (NBV) of the
transferred facilities and Keystone LP is seeking approval to add the NBV of the
facilities to the Keystone pipeline rate base. The transfer application is the
first of two major regulatory applications required to obtain approvals
necessary to construct the Canadian portion of the Keystone pipeline. An oral
public hearing on the application commenced on October 23, 2006.
TCPL filed its Preliminary Information Package for required new facilities with
the NEB in July 2006.
TCPL expects to file an application with the NEB for a certificate of public
convenience and necessity to construct the required new facilities later this
year once environmental assessment work is completed. The project will also
require regulatory approvals from various U.S. agencies.
Energy
Bruce Power
The Bruce A restart and refurbishment project reached another key milestone in
third quarter 2006 with the delivery of the first three of 16 steam generators
that will be installed in Units 1 and 2 as part of the restart project. The
restart of Units 1 and 2 is expected to return another 1,500 MW of generating
capacity to Ontario with the first unit expected to restart in late 2009. Bruce
Power also plans to replace the eight steam generators in each of Units 3 and 4.
Based on results
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24
from recent inspections, it is expected that the steam generators in Unit 4 can
continue to operate until 2010 and then be replaced. The refurbishment of Unit
3 is expected to begin in late 2009.
In August 2006, Bruce Power filed an application with the Canadian Nuclear
Safety Commission to prepare the Bruce site for potential future construction of
new reactors at the facility.
Cartier Wind
Construction continues on the 109.5 MW Baie des Sables wind farm and remains on
schedule for completion by December 2006. Construction continues on the 100.5
MW Anse a Valleau wind farm, the second of the six wind farms that comprise the
Cartier Wind project in the Gaspe region of Quebec. The Anse a Valleau wind
farm is expected to deliver energy to the Hydro-Quebec grid by December 2007.
TCPL has a 62 per cent interest in the Cartier Wind project which was awarded
six projects by Hydro-Quebec Distribution in October 2004 representing a total
of 739.5 MW.
Portlands Energy Centre
In third quarter 2006, Portlands Energy Centre L.P. (Portlands Energy) signed a
20 year Accelerated Clean Energy Supply (ACES) contract with OPA for a 550 MW
high-efficiency, combined-cycle natural gas generation plant to be constructed
in downtown Toronto. Portlands Energy is a limited partnership between Ontario
Power Generation and TCPL with both parties having a 50 per cent interest. The
capital cost of PEC is estimated to be approximately $730 million. PEC is
expected to be operational in simple-cycle mode, delivering 340 MW of
electricity to the City of Toronto to meet peak summer demand beginning June 1,
2008 with full completion expected in second quarter 2009.
Becancour
In September 2006, construction was completed on the 550 MW Becancour
cogeneration plant. The plant, near Trois-Rivieres, Quebec, was placed in
service in late third quarter 2006 and began fulfilling its obligations to
supply electricity to Hydro-Quebec Distribution under a long-term contract.
Cacouna
The Canadian Environmental Assessment Agency and the Bureau des Audiences
Publiques sur l'Environnement (BAPE) joint review panel on the proposed Cacouna
Energy project requested an extension to consider additional documents and
refinements to this proposed project. Cacouna Energy anticipates receiving
government approvals in early 2007. Cacouna Energy is a partnership between
TCPL and Petro-Canada. The proposed terminal would be capable of receiving,
storing, and re-gasifying imported LNG
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25
with an average throughput capacity of approximately 500 mmcf/d of natural gas.
Broadwater
The U.S. Coast Guard released its Waterways Suitability Report on the Broadwater
Energy project on September 22, 2006. The report determined that the proposed
LNG facility in the New York State waters of Long Island Sound can be operated
safely and securely and has provided a series of mitigation measures. This
report represents another key milestone in the ongoing regulatory review of the
Broadwater Energy project. Broadwater Energy is a partnership between TCPL and
Shell U.S. Gas & Power. The Broadwater terminal would be capable of receiving,
storing, and re-gasifying imported LNG with an average send-out capacity of
approximately one Bcf/d of natural gas.
Edson
Construction of the Edson natural gas storage facility in Alberta was
substantially complete at the end of third quarter 2006 and commissioning will
take place in fourth quarter 2006. Storage capacity is expected to be available
later this year. The Edson facility is expected to have a working natural gas
capacity of approximately 60 petajoules and will connect to the Alberta System.
Share Information
As at September 30, 2006, 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,
2006.
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26
Selected Quarterly Consolidated Financial Data(1)
(unaudited) 2006 2005 2004
(millions of dollars except per share Third Second First Fourth Third Second First Fourth
amounts)
Revenues 1,850 1,685 1,894 1,771 1,494 1,449 1,410 1,480
Net Income
Continuing operations 293 244 244 350 428 199 232 184
Discontinued operations - - 28 - - - - -
293 244 272 350 428 199 232 184
Share Statistics
Net income per share - Basic
Continuing operations $ 0.60 $ 0.51 $ 0.50 $ 0.72 $ 0.89 $ 0.41 $ 0.48 $ 0.38
Discontinued operations - - 0.06 - - - - -
$ 0.60 $ 0.51 $ 0.56 $ 0.72 $ 0.89 $ 0.41 $ 0.48 $ 0.38
--------------------
(1) The selected quarterly consolidated financial data has been
prepared in accordance with Canadian GAAP. Certain comparative figures have been
reclassified to conform with the current year's presentation. For a discussion
on the factors affecting the comparability of the financial data, including
discontinued operations, refer to Note 1, Note 2 and Note 23 of TCPL's 2005
audited consolidated financial statements.
Factors Impacting Quarterly Financial Information
In the Pipelines 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 Energy business, which primarily builds, owns and operates electrical
power generation plants, sells electricity and invests in natural gas storage
facilities, quarter over quarter revenues and net earnings are affected by
seasonal weather conditions, customer demand, market prices, planned and
unplanned plant outages as well as items outside of the normal course of
operations.
Significant items which impacted the last eight quarters' net earnings are as
follows.
* In fourth quarter 2004, TCPL completed the acquisition of GTN and recorded
$14 million of net earnings from the November 1, 2004 acquisition date. Energy
recorded a $16 million pre-tax positive impact of a restructuring transaction
related to power purchase contracts between OSP and Boston Edison in Eastern
Power Operations.
* First quarter 2005 net earnings included a $49 million after-tax gain
related to the sale of PipeLines LP units. Energy's 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.
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27
* 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 Canadian Mainline's 2004 Tolls and Tariff
Application (Phase II). On April 1, 2005, TCPL completed the acquisition of TC
Hydro generation assets from USGen New England, Inc. 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.
* Third quarter 2005 net earnings included after-tax gains of $193 million
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.
* Fourth quarter 2005 net earnings included a $115 million after-tax gain on
sale of Paiton Energy. In addition, Bruce A was formed and Bruce Power's
results were proportionately consolidated effective October 31, 2005.
* First quarter 2006 net earnings included an $18 million after-tax
bankruptcy claim settlement received by the Gas Transmission Northwest System.
In addition, Energy's net earnings included contributions from the December 31,
2005 acquisition of the 756 MW Sheerness PPA.
* Second quarter 2006 net earnings included a $33 million favourable impact
on future income taxes ($23 million in Energy and $10 million in Corporate)
arising from reductions in Canadian federal and provincial corporate income tax
rates. Pipelines earnings included a $13 million after-tax gain related to the
sale of the company's 17.5 per cent general partner interest in Northern Border
Partners, L.P.
* Third quarter 2006 net earnings included an income tax benefit of
approximately $50 million on the resolution of certain income tax matters with
taxation authorities and changes in estimates during the quarter.
--------------------------------------------------------------------------------
Exhibit 13.2
Consolidated Income
(unaudited) Three months ended September Nine months ended September
30 30
(millions of dollars) 2006 2005 2006 2005
Revenues 1,850 1,494 5,429 4,353
Operating Expenses
Cost of sales 382 319 1,224 834
Other costs and expenses 593 438 1,696 1,279
Depreciation 264 247 787 752
1,239 1,004 3,707 2,865
Other Expenses/(Income)
Financial charges 204 210 614 626
Financial charges of joint ventures 22 16 67 49
Equity income (4) (120) (28) (196)
Interest income and other (42) (22) (106) (50)
Gain on sale of Northern Border Partners, L.P. 10 - (13) -
interest
Gains related to the Power LP - (245) - (245)
Gain on sale of PipeLines LP units - - - (82)
190 (161 ) 534 102
Income from Continuing Operations before Income 421 651 1,188 1,386
Taxes and Non-Controlling Interests
Income Taxes
Current 30 189 277 429
Future 75 12 71 38
105 201 348 467
Non-Controlling Interests
Non-controlling interest in PipeLines LP 11 15 32 36
Other 6 1 10 7
17 16 42 43
Net Income from Continuing Operations 299 434 798 876
Net Income from Discontinued Operations - - 28 -
Net Income 299 434 826 876
Preferred Share Dividends 6 6 17 17
Net Income Applicable to Common Shares 293 428 809 859
Net Income Applicable to Common Shares
Continuing operations 293 428 781 859
Discontinued operations - - 28 -
293 428 809 859
See accompanying notes to the consolidated financial statements.
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2
Consolidated Cash Flows
(unaudited) Three months ended September Nine months ended September 30
30
(millions of dollars) 2006 2005 2006 2005
Cash Generated From Operations
Net income 299 434 826 876
Depreciation 264 247 787 752
Gain on sale of Northern Border Partners, L.P. - - (11) -
interest, net of current income tax
Gains related to Power LP, net of current - (166) - (166)
income tax
Gain on sale of PipeLines LP units, net of - - - (31)
current income tax
Equity income in excess of distributions (1) (53) (8) (70)
received
Future income taxes 75 12 71 38
Non-controlling interests 17 16 42 43
Funding of employee future benefits (in excess (2) 12 (17) (5)
of) lower than expense
Other 9 2 26 (16)
Funds generated from operations 661 504 1,716 1,421
(Increase)/decrease in operating working (43) 90 (136) (173)
capital
Net cash provided by operations 618 594 1,580 1,248
Investing Activities
Capital expenditures (372) (166) (1,002) (409)
Acquisitions, net of cash acquired - - (358) (632)
Disposition of assets, net of current income - 444 23 546
tax
Deferred amounts and other (47) 36 (62) 88
Net cash (used in)/provided by investing (419) 314 (1,399) (407)
activities
Financing Activities
Dividends on common shares (162) (154) (478) (454)
Advances from parent 3 - 14 (75)
Distributions paid to non-controlling (10) (14) (30) (41)
interests
Notes payable issued/(repaid), net 4 (696) (449) (163)
Long-term debt issued - - 1,250 799
Reduction of long-term debt (4) (9) (352) (962)
Long-term debt of joint ventures issued 14 4 38 9
Reduction of long-term debt of joint ventures (27) (7) (48) (23)
Common shares issued - - - 80
Net cash used in financing activities (182) (876) (55) (830)
Effect of Foreign Exchange Rate Changes on 1 (12) (8) 10
Cash and Short-Term Investments
Increase in Cash and Short-Term Investments 18 20 118 21
Cash and Short-Term Investments
Beginning of period 312 191 212 190
Cash and Short-Term Investments
End of period 330 211 330 211
Supplementary Cash Flow Information
Income taxes paid 86 102 454 408
Interest paid 195 221 629 676
See accompanying notes to the consolidated financial statements.
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3
Consolidated Balance Sheet
September 30, December 31,
2006 2005
(millions of dollars) (unaudited)
ASSETS
Current Assets
Cash and short-term investments 330 212
Accounts receivable 762 796
Inventories 277 281
Other 265 277
1,634 1,566
Long-Term Investments 77 400
Plant, Property and Equipment 20,846 20,038
Other Assets 2,218 2,109
24,775 24,113
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Notes payable 513 962
Accounts payable 1,330 1,536
Accrued interest 265 222
Current portion of long-term debt 415 393
Current portion of long-term debt of joint ventures 124 41
2,647 3,154
Deferred Amounts 1,109 1,196
Future Income Taxes 773 703
Long-Term Debt 10,306 9,640
Long-Term Debt of Joint Ventures 1,157 937
Preferred Securities 513 536
16,505 16,166
Non-Controlling Interests
Non-controlling interest in PipeLines LP 298 318
Other 83 76
381 394
Shareholders' Equity
Preferred shares 389 389
Common shares 4,712 4,712
Contributed surplus 276 275
Retained earnings 2,607 2,267
Foreign exchange adjustment (95) (90)
7,889 7,553
24,775 24,113
See accompanying notes to the consolidated financial statements.
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4
Consolidated Retained Earnings
(unaudited) Nine months ended September
30
(millions of dollars) 2006 2005
Balance at beginning of period 2,267 1,653
Net income 826 876
Preferred share dividends (17) (17)
Common share dividends (469) (445)
2,607 2,067
See accompanying notes to the consolidated financial statements.
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5
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 audited consolidated financial statements for the
year ended December 31, 2005. 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 2005 audited consolidated financial statements included
in TCPL's 2005 Report. 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. Segmented Information
Effective June 1, 2006, TCPL revised the composition and names of its reportable
business segments to Pipelines and Energy. Pipelines is principally comprised
of the company's pipelines in Canada, the United States and Mexico. Energy
includes the company's power operations, natural gas storage and liquefied
natural gas (LNG) businesses in Canada and the U.S. The financial reporting of
these segments was aligned to reflect the internal organizational structure of
the company. The segmented information has been retroactively restated to
reflect the changes in reportable segments. These changes had no impact on
consolidated net income.
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6
The impacts on segment net income of each of Pipelines and Energy in each
quarter of 2005 and first quarter 2006 are as follows.
2005 2006
(unaudited - millions of dollars) First Second Third Fourth Total First
Pipelines
Net Income - previously reported as Gas 211 165 148 160 684 168
Transmission
Reclassifications:
Natural gas storage (4) (1) (2) (9) (16) (13)
Costs related to LNG 2 2 3 4 11 2
Net Income - revised 209 166 149 155 679 157
Energy
Net Income - previously reported as Power 30 42 292 197 561 89
Reclassifications:
Natural gas storage 4 1 2 9 16 13
Costs related to LNG (2) (2) (3) (4) (11) (2)
Net Income - revised 32 41 291 202 566 100
Three months ended September 30 (unaudited - Pipelines Energy Corporate Total
millions of dollars)
2006 2005 2006 2005 2006 2005 2006 2005
Revenues 1,010 993 840 501 - - 1,850 1,494
Cost of sales - - (382) (319) - - (382) (319)
Other costs and expenses (351) (310) (240) (127) (2) (1) (593) (438)
Depreciation (231) (235) (33) (12) - - (264) (247)
428 448 185 43 (2) (1) 611 490
Financial charges, preferred dividends and (197) (198) - - (30) (34 ) (227) (232)
non-controlling interests
Financial charges of joint ventures (17) (16) (5) - - - (22) (16)
Equity income 4 21 - 99 - - 4 120
Interest income and other 25 8 2 2 5 12 32 22
Gains related to Power LP - - - 245 - - - 245
Income taxes (113) (114) (59) (98) 67 11 (105) (201)
Continuing Operations 130 149 123 291 40 (12) 293 428
Discontinued Operations - -
Net Income Applicable to Common Shares 293 428
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7
Nine months ended September 30 Pipelines Energy Corporate Total
(unaudited - millions of dollars)
2006 2005 2006 2005 2006 2005 2006 2005
Revenues 2,956 2,981 2,473 1,372 - - 5,429 4,353
Cost of sales - - (1,224) (834) - - (1,224) (834)
Other costs and expenses (994) (899) (695) (376) (7) (4) (1,696) (1,279)
Depreciation (692) (700) (95) (52) - - (787) (752)
1,270 1,382 459 110 (7) (4) 1,722 1,488
Financial charges, preferred dividends and (573) (588) - (2) (100) (96) (673) (686)
non-controlling interests
Financial charges of joint ventures (50) (44) (17) (5) - - (67) (49)
Equity income 28 54 - 142 - - 28 196
Interest income and other 59 21 5 5 32 24 96 50
Gain on sale of Northern Border Partners, 23 - - - - - 23 -
L.P. interest
Gain on sale of PipeLines LP units - 82 - - - - - 82
Gains related to Power LP - - - 245 - - - 245
Income taxes (323) (383) (127) (131) 102 47 (348) (467)
Continuing Operations 434 524 320 364 27 (29 ) 781 859
Discontinued Operations 28 -
Net Income Applicable to Common Shares 809 859
Total Assets
September 30, December 31,
2006 2005
(millions of dollars) (unaudited)
Pipelines 17,966 17,872
Energy 5,715 5,303
Corporate 1,094 938
24,775 24,113
3. Risk Management and Financial Instruments
The following represents the material changes to the company's financial
instruments since December 31, 2005.
Energy Price Risk Management
The company executes power, natural gas and heat rate derivatives for overall
management of its asset portfolio. Heat rate contracts are contracts for the
sale or purchase of power that are priced based on a natural gas index. The
fair value and notional volumes of contracts for differences and the swap,
option and heat rate contracts are shown in the tables below.
--------------------------------------------------------------------------------
8
Power
September 30,
2006
Asset/(Liability) (millions of dollars) (unaudited) December 31,
2005
Accounting Fair Fair
Treatment Value Value
Power - swaps and contracts for differences
(maturing 2006 to 2011) Hedge (89) (130)
(maturing 2006 to 2010) Non-hedge (6) 13
Gas - swaps and futures
(maturing 2006 to 2016) Hedge (58) 17
(maturing 2006 to 2008) Non-hedge 26 (11)
Notional Volumes September 30, 2006 (unaudited) Power (GWh) Gas (Bcf)
Accounting Purchases Sales Purchases Sales
Treatment
Power - swaps and contracts for differences
(maturing 2006 to 2011) Hedge 4,946 11,189 - -
(maturing 2006 to 2010) Non-hedge 1,465 917 - -
Gas - swaps and futures
(maturing 2006 to 2016) Hedge - - 81 60
(maturing 2006 to 2008) Non-hedge - - 15 20
Heat rate contracts
(maturing 2006) Non-hedge - 12 - -
Notional Volumes December 31, 2005 Power (GWh) Gas (Bcf)
Accounting Purchases Sales Purchases Sales
Treatment
Power - swaps and contracts for differences Hedge 2,566 7,780 - -
Non-hedge 1,332 456 - -
Gas - swaps and futures Hedge - - 91 69
Non-hedge - - 15 18
Certain of the company's joint ventures use power derivatives to manage energy
price risk exposures. The company's proportionate share of the fair value of
these outstanding power sales derivatives at September 30, 2006 was $55 million
(December 31, 2005 - $(38) million) and relates to contracts which cover the
period 2006 to 2010. The company's proportionate share of the notional sales
volumes associated with this exposure at September 30, 2006 was 4,500 GWh
(December 31, 2005 - 2,058 GWh).
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9
4. Long-Term Debt
In January 2006, the company issued $300 million of 4.3 per cent medium-term
notes due 2011; in March 2006, the company issued US$500 million of 5.85 per
cent senior unsecured notes due 2036; and in October 2006, the company issued
$400 million of 4.65 per cent medium-term notes due October 2016.
In April 2006, TC PipeLines, LP (PipeLines LP) borrowed US$307 million under its
unsecured credit facility to finance the cash portion of the purchase price of
its acquisition of an additional 20 per cent interest in Northern Border
Pipeline Company (Northern Border). The credit facility has a term of two years
and all amounts outstanding will be due and payable on March 31, 2008.
Borrowings under the credit facility will bear interest based, at PipeLines LP's
election, on the London interbank offered rate or the base rate plus, in either
case, an applicable margin.
5. Discontinued Operations
TCPL's net income for the nine months ended September 30, 2006 includes $28
million of net income from discontinued operations, reflecting settlements
received in first quarter 2006 from bankruptcy claims related to TCPL's Gas
Marketing business divested in 2001.
6. Acquisitions and Dispositions
In April 2006, PipeLines LP closed its acquisition of an additional 20 per cent
general partnership interest in Northern Border for US$307 million bringing its
total general partnership interest to 50 per cent. As part of the transaction,
PipeLines LP indirectly assumed approximately US$120 million of debt of Northern
Border. Of the total purchase price, US$114 million was allocated to goodwill
and the remainder was allocated primarily to plant, property and equipment.
Northern Border became a jointly controlled entity and TCPL commenced
proportionately consolidating its investment in Northern Border on a prospective
basis as of April 2006. As part of the transaction, and effective early second
quarter 2007, a subsidiary of TCPL will become the operator of Northern Border
which is currently operated by a subsidiary of ONEOK Inc. (ONEOK).
Concurrent with this transaction, TCPL closed the sale of its 17.5 per cent
general partner interest in Northern Border Partners, L.P. to a subsidiary of
ONEOK, for net proceeds of approximately US$30 million, resulting in an
after-tax gain of $13 million. The net gain was recorded in the Pipelines
segment and the company recorded a $10 million income tax charge, including $12
million of current income tax expense, on this transaction.
7. Income Taxes
In second quarter 2006, TCPL recorded a $37 million future income tax benefit
($23 million in Energy and $14 million in Corporate) as a result of reductions
in Canadian federal and provincial corporate income tax
--------------------------------------------------------------------------------
10
rates enacted in second quarter 2006. In third quarter 2006, TCPL recorded a
net income tax benefit of approximately $75 million on the resolution of certain
income tax matters with taxation authorities and changes in estimates during the
quarter.
8. 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 months and nine months ended
September 30, respectively, is as follows.
Three months ended September 30 Pension Benefit Other Benefit
Plans Plans
(unaudited - millions of dollars) 2006 2005 2006 2005
Current service cost 10 7 1 -
Interest cost 16 16 2 1
Expected return on plan assets (18) (16) (1) -
Amortization of transitional obligation related to regulated business - - 1 1
Amortization of net actuarial loss 6 5 1 -
Amortization of past service costs 1 1 - -
Net benefit cost recognized 15 13 4 2
Nine months ended September 30 Pension Benefit Other Benefit
Plans Plans
(unaudited - millions of dollars) 2006 2005 2006 2005
Current service cost 28 22 2 1
Interest cost 49 48 6 4
Expected return on plan assets (53) (48) (2) -
Amortization of transitional obligation related to regulated business - - 2 2
Amortization of net actuarial loss 20 13 2 1
Amortization of past service costs 3 2 1 -
Net benefit cost recognized 47 37 11 8
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/Myles Dougan at (403)
920-7911. The investor fax line is (403) 920-2457. Media Relations: Jennifer Varey at (403) 920-7859
Visit TCPL's Internet site at: http://www.transcanada.com
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Exhibit 13.3
TRANSCANADA PIPELINES LIMITED
RECONCILIATION TO UNITED STATES GAAP
The unaudited consolidated financial statements of TransCanada PipeLines Limited
(TCPL or the Company) for the three and nine months ended September 30, 2006
have been prepared in accordance with Canadian generally accepted accounting
principles (GAAP), which in some respects differ from U.S. GAAP. The effects of
these differences on the Company's consolidated financial statements for the
three and nine months ended September 30, 2006 are provided in the following
U.S. GAAP condensed consolidated financial statements which should be read in
conjunction with TCPL's audited consolidated financial statements for the year
ended December 31, 2005 and unaudited consolidated financial statements for the
three and nine months ended September 30, 2006 prepared in accordance with
Canadian GAAP.
Condensed Statement of Consolidated Income and Comprehensive Income in
Accordance with U.S. GAAP(1)
Three months ended Nine months ended
September 30 September 30
(millions of dollars) 2006 2005 2006 2005
Revenues 1,492 1,306 4,307 3,870
Cost of sales 321 228 953 637
Other costs and expenses 477 442 1,349 1,270
Depreciation 223 235 668 693
1,021 905 2,970 2,600
471 401 1,337 1,270
Other (income)/expenses
Equity income(1) (134) (173) (352) (340)
Other expenses(2) 191 (33) 542 300
Income taxes 109 191 348 455
166 (15) 538 415
Net income from continuing operations - U.S. GAAP 305 416 799 855
Net income from discontinued operations - U.S. GAAP - - 28 -
Net Income in Accordance with U.S. GAAP 305 416 827 855
Adjustments affecting comprehensive income under U.S. GAAP
Foreign currency translation adjustment, net of tax - (37) (6) (27)
Unrealized (loss)/gain on derivatives, net of tax(3) (2) (59) 32 (98)
Comprehensive Income in Accordance with U.S. GAAP 303 320 853 730
Reconciliation of Income from Continuing Operations
Three months ended Nine months ended
September 30 September 30
(millions of dollars) 2006 2005 2006 2005
Net Income from Continuing Operations in Accordance with Canadian GAAP 298 434 797 876
U.S. GAAP adjustments
Unrealized gain/(loss) on energy contracts(3) 11 (28) - (37)
Tax impact of unrealized gain/(loss) on energy contracts (4) 10 - 13
Equity investment gain(4)(5) - - 1 3
Tax impact of equity investment gain - - - (1)
Unrealized gain on foreign exchange and interest rate derivatives(3) - - 1 1
Tax impact of unrealized gain on foreign exchange and interest rate - - - -
derivatives
Net income from Continuing Operations in Accordance with U.S. GAAP 305 416 799 855
--------------------------------------------------------------------------------
2
Condensed Statement of Consolidated Cash Flows in Accordance with U.S. GAAP(1)
Three months ended Nine months ended
September 30 September 30
(millions of dollars) 2006 2005 2006 2005
Cash Generated from Operations(6)
Net cash provided by operating activities 554 503 1,517 1,039
Investing Activities
Net cash (used in) provided by investing activities (388) 402 (1,333) (226)
Financing Activities
Net cash (used in) financing activities (160) (874) (45) (815)
Effect of Foreign Exchange Rate Changes on Cash and Short-Term 1 (10) (6) 12
Investments
Increase in Cash and Short-Term Investments 7 21 133 10
Cash and Short-Term Investments
Beginning of period 209 115 83 126
Cash and Short-Term Investments
End of period 216 136 216 136
Condensed Consolidated Balance Sheet in Accordance with U.S. GAAP(1)
September December
30, 31,
(millions of dollars) 2006 2005
Current assets(7) 1,148 1,058
Long-term investments(1)(4)(5) 2,793 2,168
Plant, property and equipment 17,163 17,348
Regulatory asset(8) 2,101 2,601
Other assets(4) 1,958 2,028
25,163 25,203
Current liabilities(9) 2,277 2,797
Deferred amounts(3)(5) 1,204 1,298
Long-term debt(3) 10,331 9,675
Deferred income taxes(8) 2,685 3,102
Preferred securities 513 536
Non-controlling interests 381 394
Shareholders' equity 7,772 7,401
25,163 25,203
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, 2005 (89) (77) (58) (224)
Unrealized gain on derivatives, net of tax of $12(3) - - 32 32
Foreign currency translation adjustment, net of tax of (6) - - (6)
$35
Balance at September 30, 2006 (95) (77) (26) (198)
Balance at December 31, 2004 (71) (26) (4) (101)
Unrealized loss on derivatives, net of tax of $52(3) - - (98) (98)
Foreign currency translation adjustment, net of tax of (27) - - (27)
$19
Balance at September 30, 2005 (98) (26) (102) (226)
--------------------------------------------------------------------------------
3
--------------------
(1) In accordance with U.S. GAAP, the Condensed Statement of Consolidated
Income, Statement of Consolidated Cash Flows and Consolidated Balance Sheet of
TCPL are prepared using the equity method of accounting for joint ventures.
(2) Other expenses included an allowance for funds used during
construction of $6 million for the nine months ended September 30, 2006
(September 30, 2005 - $2 million).
(3) 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 Statement of Financial Accounting Standards (SFAS) No.
133 "Accounting for Derivatives and Hedging Activities", all derivatives are
recognized as assets and liabilities on the balance sheet and measured at fair
value. For derivatives designated as fair value hedges, changes in the fair
value are recognized in earnings together with an equal or lesser amount of
changes in the fair value of the hedged item attributable to the hedged risk.
For derivatives designated as cash flow hedges, changes in the fair value of the
derivative that are effective in offsetting the hedged risk are recognized in
other comprehensive income until the hedged item is recognized in earnings. Any
ineffective portion of the change in fair value is also recognized in earnings
each period. Substantially all of the amounts recorded in the nine months ended
September 30, 2006 and 2005 as differences between U.S. and Canadian GAAP, for
income from continuing operations, relate to the differences in accounting
treatment with respect to the hedged item and, for comprehensive income, relate
to cash flow hedges.
Substantially all of the amounts recorded in the nine months ended September 30,
2006 and 2005 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 contracts.
(4) 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 prior year start-up costs incurred by Bruce Power L.P. (Bruce
B), an equity investment, were 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 B, 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.
(5) 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, 2006 was $17 million (December 31, 2005 - $17 million) and relates
to the Company's equity interest in Bruce B and Bruce Power A L.P. The net
income impact with respect to the guarantees for the nine months ended September
30, 2006 was $1 million (September 30, 2005 - nil).
(6) In accordance with U.S. GAAP, all current taxes are included in cash
generated from operations.
(7) Current assets at September 30, 2006 include derivative contracts of
$30 million (December 31, 2005 - $49 million) and hedging deferrals of $72
million (December 31, 2005 - $93 million).
(8) 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. A reduction in Canadian federal and
provincial corporate income tax rates enacted in the second quarter 2006
resulted
--------------------------------------------------------------------------------
4
in a decrease of $406 million in the deferred income tax liability and
corresponding regulatory asset.
(9) Current liabilities at September 30, 2006 include dividends payable of
$162 million (December 31, 2005 - $154 million) and current taxes payable of
$103 million (December 31, 2005 - $251 million).
Other
In May 2005, the Financial Accounting Standards Board (FASB) issued SFAS No. 154
"Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20
and SFAS No. 3" which is effective for fiscal years beginning after December 15,
2005. SFAS No. 154 changes the requirements for the accounting for and
reporting of a change in accounting principle and error correction. It
establishes, unless impracticable, retrospective application as the required
method for reporting a change in accounting principle in the absence of explicit
transition requirements specific to the newly adopted accounting principle.
Adopting the provisions under SFAS No. 154, as of January 1, 2006, had no impact
on the U.S. GAAP financial statements of the Company.
In February 2006, FASB issued SFAS No. 155 "Accounting for Certain Hybrid
Financial Instruments - an amendment of SFAS No. 133 and 140" which is effective
for fiscal years beginning after September 15, 2006. Earlier adoption is
permitted as of the beginning of an entity's fiscal year, provided the entity
has not yet issued financial statements, including interim statements for any
interim period, for that fiscal year. SFAS No. 155 permits fair value
remeasurement of any hybrid instrument that contains an embedded derivative that
otherwise would require bifurcation. Adopting the provisions under SFAS No.
155, as of January 1, 2007, is not expected to have an impact on the U.S. GAAP
financial statements of the Company.
In March 2006, FASB issued SFAS No. 156 "Accounting for Servicing of Financial
Assets - an amendment of FASB Statement No. 140" which is effective for fiscal
years beginning after September 15, 2006. Earlier adoption is permitted as of
the beginning of an entity's fiscal year, provided the entity has not yet issued
financial statements, including interim statements for any interim period, for
that fiscal year. SFAS No. 156 requires recognition of a servicing asset or
liability when an entity enters into arrangements to service financial
instruments in certain situations. Such servicing assets or servicing
liabilities are required to be initially measured at fair value, if practicable.
SFAS No. 156 also allows an entity to subsequently measure its servicing
assets or servicing liabilities using either an amortization method or a fair
value method. Adopting the provisions under SFAS No. 156, as of January 1,
2007, is not expected to have an impact on the U.S. GAAP financial statements of
the Company.
In July 2006, FASB issued FIN 48 "Accounting for Uncertainty in Income Taxes, an
interpretation of FASB Statement No. 109" which is effective for fiscal years
beginning after December 15, 2006. This Interpretation provides guidance for
the financial statement recognition, measurement, presentation and disclosure of
uncertain tax positions taken or expected to be taken in income tax returns.
TransCanada is in the process of assessing the impact, if any, of the
application of FIN 48 on its US GAAP financial statements.
In September 2006, FASB issued SFAS No. 157 "Fair Value Measurements" which is
effective for fiscal years beginning after November 15, 2007. This statement
defines fair value, establishes a framework for measuring fair value, and
expands disclosures about fair value measurements. TransCanada is in the
process of assessing the impact of the application of SFAS No. 157 on its U.S.
GAAP financial statements.
In September 2006, FASB issued SFAS No. 158 "Employers' Accounting for Defined
Benefit Pension and Other Postretirement Plans - an amendment of FASB Statements
No. 87, 88, 106 and 132(R)", which is effective for fiscal years ending after
December 15, 2006. This statement requires an employer to recognize the
overfunded or underfunded status of a defined benefit postretirement plan (other
than a multiemployer plan) as an asset or liability on its balance sheet and to
recognize changes in the funded status in the year in which the changes occur
through comprehensive income. The plan assets and benefit obligations will be
measured as of the balance sheet date. TransCanada is in the process of
assessing the impact of the application of SFAS No. 158 on its U.S. GAAP
financial statements.
--------------------------------------------------------------------------------
5
In September 2006, the SEC staff issued SAB Topic 1N, "Financial Statements -
Considering the Effects of Prior Year Misstatements When Quantifying
Misstatements in Current Year Financial Statements" (SAB No. 108), which
addresses how to quantify the effect of an error on the financial statements.
SAB No. 108 is effective for fiscal years ending December 31, 2006. TransCanada
does not expect SAB No. 108 to have an impact on its U.S. GAAP financial
statements.
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 ended Nine months ended
September 30 September 30
(millions of dollars) 2006 2005 2006 2005
Income
Revenues 364 379 1,068 993
Other costs and expenses (162) (146) (512) (455)
Depreciation (43) (44) (130) (128)
Financial charges and other (25) (19) (74) (73)
Proportionate share of income before income taxes of long-term 134 170 352 337
investments
(millions of dollars) September 30, December 31,
2006 2005
Balance Sheet
Current assets 446 456
Plant, property and equipment 3,812 3,365
Other assets (net) 202 -
Current liabilities (347) (319)
Deferred amounts (net) - (2)
Non-recourse debt (1,293) (1,307)
Deferred income taxes (27) (25)
Proportionate share of net assets of long-term investments 2,793 2,168
--------------------------------------------------------------------------------
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 1, 2006
/s/ Harold N. Kvisle
Harold N. Kvisle
President and Chief Executive Officer
--------------------------------------------------------------------------------
Exhibit 31.2
Certifications
I, Gregory A. Lohnes, 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 1, 2006 / s / Gregory A. Lohnes
Gregory A. Lohnes
Executive Vice-President 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, 2006 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 1, 2006
--------------------------------------------------------------------------------
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, Gregory A. Lohnes, 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, 2006 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 / Gregory A. Lohnes
Gregory A. Lohnes
Chief Financial Officer
November 1, 2006
--------------------------------------------------------------------------------
Exhibit 99.1
TransCanada PipeLines Limited
EARNINGS COVERAGE
SEPTEMBER 30, 2006
The following financial ratios have been calculated on a consolidated basis for
the respective 12 month period ended September 30, 2006 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,
2006
Earnings coverage on long-term debt 2.91 times
Earnings coverage on long-term debt and First 2.81 times
Preferred Shares
--------------------------------------------------------------------------------
This information is provided by RNS
The company news service from the London Stock Exchange
END
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