RNS Number:8345V
TransCanada Pipelines Ld
30 April 2007
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 April 2007
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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I
The documents listed below in this Section and filed as Exhibits 13.1 to 13.3
and 99.1 to this Form 6-K are hereby filed with the Securities and Exchange
Commission for the purpose of being and hereby are incorporated by reference
into Registration Statement on Form F-9 (Reg. No. 333-141122) 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 March 31, 2007.
13.2 Consolidated comparative interim unaudited
financial statements of the registrant for the period ended March 31, 2007
(included in the registrant's First Quarter 2007 Quarterly Report).
13.3 U.S. GAAP reconciliation of the consolidated
comparative interim unaudited financial statements of the registrant contained
in the registrant's First Quarter 2007 Quarterly Report.
99.1 Schedule of earnings coverage calculations at
March 31, 2007.
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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
April 30, 2007
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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 March 31, 2007.
13.2 Consolidated comparative interim unaudited
financial statements of the registrant for the period ended March 31, 2007
(included in the registrant's First Quarter 2007 Quarterly Report).
13.3 U.S. GAAP reconciliation of the consolidated
comparative interim unaudited financial statements of the registrant contained
in the registrant's First Quarter 2007 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
March 31, 2007.
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Exhibit 13.1
TRANSCANADA PIPELINES LIMITED - FIRST QUARTER 2007
Quarterly Report
Management's Discussion and Analysis
The Management's Discussion and Analysis (MD&A) dated April 26, 2007 should be
read in conjunction with the accompanying unaudited Consolidated Financial
Statements of TransCanada PipeLines Limited (TCPL or the Company) for the three
months ended March 31, 2007. It should also be read in conjunction with the
audited Consolidated Financial Statements and notes thereto, and the MD&A
contained in TCPL's 2006 Annual Report for the year ended December 31, 2006.
Additional information relating to TCPL, including the Company's Annual
Information Form and continuous disclosure documents, is available on SEDAR at
www.sedar.com under TransCanada PipeLines Limited. Amounts are stated in
Canadian dollars unless otherwise indicated. Capitalized and abbreviated terms
that are used but not otherwise defined herein are identified in the Glossary of
Terms contained in TCPL's 2006 Annual Report.
Forward-Looking Information
This MD&A may contain certain information that is forward-looking and is subject
to important risks and uncertainties. The words "anticipate", "expect", "may", "
should", "estimate", "project", "outlook", "forecast" or other similar words are
used to identify such forward-looking information. All forward- looking
statements are based on TCPL's beliefs and assumptions based on information
available at the time such statements were made. The results or events predicted
in this information may differ from actual results or events. Factors which
could cause actual results or events to differ materially from current
expectations include, among other things, the ability of TCPL to successfully
implement its strategic initiatives and whether such strategic initiatives will
yield the expected benefits, the availability and price of energy commodities,
regulatory decisions, changes in environmental and other laws and regulations,
competitive factors in the pipeline and energy industry sectors, construction
and completion of capital projects, access to capital markets, interest and
currency exchange rates, technological developments and the current economic
conditions in North America. By its nature, such forward-looking information is
subject to various risks and uncertainties which could cause TCPL's actual
results and experience to differ materially from the anticipated results or
other expectations expressed. For additional information on these and other
factors, see the reports filed by TCPL with Canadian securities regulators and
with the U.S. Securities and Exchange Commission. 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 otherwise, and 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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FIRST QUARTER REPORT 2007
Non-GAAP Measures
The Company uses the measures "comparable earnings", "funds generated from
operations" and "operating income" in this MD&A. These measures do not have any
standardized meaning prescribed by generally accepted accounting principles
(GAAP) and are therefore considered to be non-GAAP measures. These measures are
unlikely to be comparable to similar measures presented by other entities. These
measures have been used to provide readers with additional information on the
Company's operating performance, liquidity and its ability to generate funds to
finance its operations.
Comparable earnings is comprised of net income from continuing operations
adjusted for specified items that are significant and not typical of the
Company's operations. Specified items may include, but are not limited to,
certain income tax refunds and adjustments, gains or losses on sales of assets,
legal settlements and bankruptcy settlements received from former customers. A
reconciliation of comparable earnings to net income is presented in the
Consolidated Results of Operation section in this MD&A.
Funds generated from operations is comprised of net cash provided by operations
before changes in operating working capital. A reconciliation of funds generated
from operations to net cash provided by operations is presented in the Liquidity
and Capital Resources section in this MD&A. Operating income is used in the
Energy segment and is comprised of revenues 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.
Acquisitions
ANR and Great Lakes
On February 22, 2007, TCPL acquired American Natural Resources Company and the
ANR Storage Company (together ANR) and an additional 3.55 per cent interest in
Great Lakes from El Paso Corporation for approximately US$3.4 billion, subject
to certain post-closing adjustments, including US$491 million of assumed
long-term debt. The acquisition of ANR added approximately 17,000 kilometres
(km) of natural gas transmission pipeline with a peak-day capacity of 6.8
billion cubic feet per day (Bcf/d). ANR also owns and operates natural gas
storage facilities with a total capacity of approximately 230 billion cubic feet
(Bcf). TCPL began consolidating ANR and Great Lakes in the Pipelines segment
subsequent to the acquisition date. The acquisition was financed with a
combination of proceeds from the Company's recent issuance of common shares,
cash on hand and funds drawn on existing and newly established loan facilities.
The issuance of common shares and debt financings are discussed in the Liquidity
and Capital Resources section in this MD&A.
Great Lakes
On February 22, 2007, PipeLines LP acquired a 46.45 per cent interest in Great
Lakes from El Paso Corporation for approximately US$942 million, which included
US$209 million of assumed long-term debt, subject to certain post-closing
adjustments. The acquisition was financed with debt from new and existing
facilities, which is discussed in the Liquidity
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and Capital Resources section in this MD&A, and a private placement offering,
discussed below.
In February 2007, PipeLines LP completed a private placement offering of
17,356,086 common units at a price of US$34.57 per unit, of which 50 per cent
were acquired by TCPL for US$300 million. Additionally, TCPL invested US$12
million to maintain its general partnership ownership interest in PipeLines LP.
As a result of TCPL's additional investments in PipeLines LP, its ownership
interest in PipeLines LP increased to 32.1 per cent from 13.4 per cent. The
total private placement plus TCPL's additional investment resulted in gross
proceeds to PipeLines LP of US$612 million, which were used to partially finance
its Great Lakes acquisition.
Consolidated Results of Operations
Reconcilation of Comparable Earnings to Net Income
Three months ended March 31
(unaudited)
(millions of dollars except per share amounts) 2007 2006
Pipelines
Comparable earnings 155 139
Specified item:
Bankruptcy settlement with Mirant - 18
Net earnings 155 157
Energy 106 100
Corporate
Comparable expenses (13 ) (13 )
Specified item:
Corporate income tax adjustments 15 -
Net earnings/(expenses) 2 (13 )
Net Income Applicable to Common Shares
Continuing operations (1) 263 244
Discontinued operations - 28
263 272
--------------------
(1)Comparable Earnings 248 226
Specified items (net of tax, where applicable):
Bankruptcy settlement with Mirant - 18
Corporate income tax adjustments 15 -
Net Income Applicable to Common Shares from Continuing Operations 263 244
TCPL's net income applicable to common shares for first quarter 2007 was $263
million compared to $272 million for first quarter 2006. Net income applicable
to common shares from continuing operations (net earnings) for the same period
in 2007 was $263 million compared to $244 million in 2006. The 2007 net earnings
were higher than 2006 by $19 million primarily due to income from the
acquisition of ANR, start-up of the Becancour cogeneration plant and the
commencement of operations of Tamazunchale. Net earnings also increased due to
positive adjustments in the first quarter of 2007, including the resolution of
certain income
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tax matters and an internal restructuring.
Comparable earnings for first quarter 2007 was $248 million compared to $226
million for the same period in 2006. Comparable earnings excluded positive
income tax adjustments of $15 million in first quarter 2007. In first quarter
2006, comparable earnings excluded an $18 million ($29 million pre-tax)
bankruptcy settlement with Mirant Corporation and certain of its subsidiaries
(Mirant), a former shipper on the Gas Transmission Northwest System.
TCPL's net income for the three months ended March 31, 2006 included net income
from discontinued operations of $28 million reflecting bankruptcy settlements
with Mirant received in first quarter 2006 related to TCPL's Gas Marketing
business divested in 2001.
Results from each business segment for the three months ended March 31, 2007 are
discussed further in the Pipelines, Energy and Corporate sections of this MD&A.
Funds generated from operations of $579 million for the three months ended March
31, 2007 increased $63 million when compared to the same period in 2006.
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Pipelines
The Pipelines business generated net earnings of $155 million for the three
months ended March 31, 2007, compared to $157 million for the same period in
2006.
Pipelines Results-at-a-Glance
Three months ended March 31
(unaudited)
(millions of dollars) 2007 2006
Wholly Owned Pipelines
Canadian Mainline 57 59
Alberta System 31 33
ANR (1) 21 -
GTN 11 32
Foothills (2) 6 7
126 131
Other Pipelines
Great Lakes (3) 14 12
Iroquois 5 4
Portland 5 6
PipeLines LP (4) 2 1
Ventures LP 3 3
TQM 2 2
TransGas 3 3
Tamazunchale 3 -
Northern Development (1 ) (1 )
General, administrative, support costs and other (7 ) (4 )
29 26
Net Earnings 155 157
--------------------
(1) ANR includes results of operations since February 22, 2007.
(2) Foothills reflects the combined operations of Foothills and the
BC System.
(3) Great Lakes' results reflect TCPL's 53.55 per cent ownership in
Great Lakes since February 22, 2007.
(4) PipeLines LP's results include TCPL's effective ownership of an
additional 15 per cent in Great Lakes as a result of TCPL's 32.1 per cent
interest in PipeLines LP since February 22, 2007.
Wholly Owned Pipelines
Canadian Mainline's first quarter 2007 net earnings decreased $2 million
compared to first quarter 2006. The decrease was primarily due to a lower
investment base and a lower rate of return on common equity (ROE) as determined
by the National Energy Board (NEB) of 8.46 per cent in 2007, compared to 8.88
per cent in 2006, on a deemed common equity ratio of 36 per cent.
The Alberta System's net earnings for first quarter 2007 decreased $2 million
compared to the same period in 2006. The decrease was primarily due to a lower
investment base and a lower ROE in 2007. Net earnings
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in 2007 reflect an ROE of 8.51 per cent on a deemed common equity ratio of 35
per cent compared to an ROE of 8.93 per cent on a deemed common equity ratio of
35 per cent in 2006.
TCPL completed the acquisition of ANR on February 22, 2007 and included net
earnings from this date. ANR's revenues are primarily derived from its
interstate natural gas transmission, storage, gathering and related services.
GTN's net earnings for the three months ended March 31, 2007 decreased $21
million from the same period in 2006 primarily due to the receipt of the $18
million bankruptcy settlement ($29 million pre-tax) in first quarter 2006 with
Mirant, a former shipper on the Gas Transmission Northwest System. Also
contributing to the decrease are lower operating revenues in 2007 due to lower
contracted long-term firm volumes and a provision taken in first quarter 2007
for non-payment of contract transportation revenues from a subsidiary of Calpine
Corporation (Calpine) that filed for bankruptcy protection.
Operating Statistics
Three months ended March 31
Canadian Alberta ANR Gas Transmission
Northwest
Mainline(1) System(2) (3) (4) System(3) Foothills System
(5)
2007 2006 2007 2006 2007 2007 2006 2007 2006
(unaudited)
Average investment base
($ millions) 7,401 7,471 4,261 4,319 n/a n/a n/a 818 870
Delivery volumes (Bcf)
Total 881 829 1,070 1,062 172 193 171 356 345
Average per day 9.8 9.2 11.9 11.8 4.6 2.1 1.9 4.0 3.8
--------------------
(1) Canadian Mainline deliveries originating at the Alberta border
and in Saskatchewan for the three months ended March 31, 2007 were 576 Bcf (2006
- 584 Bcf); average per day was 6.4 Bcf (2006 - 6.5 Bcf).
(2) Field receipt volumes for the Alberta System for the three
months ended March 31, 2007 were 1,005 Bcf (2006 - 1,021 Bcf); average per day
was 11.2 Bcf (2006 - 11.3 Bcf).
(3) ANR and the Gas Transmission Northwest System operate under a
fixed rate model approved by the United States Federal Energy Regulatory
Commission (FERC) and, as a result, the systems' current results are not
dependent on average investment base.
(4) ANR includes results of operations since February 22, 2007.
(5) Foothills reflects the combined operations of Foothills and the
BC System.
Other Pipelines
TCPL's proportionate share of net earnings from Other Pipelines was $29 million
for the three months ended March 31, 2007 compared to $26 million for the same
period in 2006. The increase was mainly due to earnings from the Tamazunchale
pipeline, which commenced operations in December 2006, and increased earnings
from Great Lakes reflecting an effective 19 per cent increase in ownership
interest. These increases were partially offset by the impact of higher project
development and support costs in 2007.
As at March 31, 2007, TCPL had advanced $125 million to the Aboriginal Pipeline
Group with respect to the Mackenzie Gas Pipeline Project and had capitalized $43
million related to the Keystone pipeline.
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Energy
Energy's net earnings of $106 million in first quarter 2007 increased $6 million
compared to $100 million in first quarter 2006.
Energy Results-at-a-Glance
Three months ended March 31
(unaudited)
(millions of dollars) 2007 2006
Bruce Power 29 63
Western Power Operations 73 58
Eastern Power Operations 67 49
Natural Gas Storage 30 22
General, administrative, support costs and other (36 ) (30 )
Operating income 163 162
Financial charges (4 ) (7 )
Interest income and other 3 2
Income taxes (56 ) (57 )
Net Earnings 106 100
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Bruce Power
Bruce Power Results-at-a-Glance(1)
Three months ended March 31
(unaudited) 2007 2006
Bruce Power (100 per cent basis)
(millions of dollars)
Revenues
Power 460 479
Other (2) 20 17
480 496
Operating expenses
Operations and maintenance (295 ) (220 )
Fuel (25 ) (20 )
Supplemental rent (43 ) (43 )
Depreciation and amortization (36 ) (31 )
(399 ) (314 )
Operating Income 81 182
TCPL's proportionate share 31 62
Adjustments (2 ) 1
TCPL's operating income from
Bruce Power 29 63
Bruce Power - Other Information
Plant availability
Bruce A 90 % 78 %
Bruce B 78 % 95 %
Combined Bruce Power 82 % 90 %
Sales volumes (GWh) (3)
Bruce A - 100 per cent 2,910 2,520
Bruce B - 100 per cent 5,430 6,620
Combined Bruce Power - 100 per cent 8,340 9,140
TCPL's proportionate share 3,129 3,306
Results per MWh (4)
Bruce A revenues $ 59 $ 57
Bruce B revenues $ 53 $ 50
Combined Bruce Power revenues $ 55 $ 52
Combined Bruce Power fuel $ 3 $ 2
Combined Bruce Power operating expenses (5) $ 47 $ 34
Percentage of output sold to spot market 35 % 38 %
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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 $8 million for
first quarter 2007 and $6 million for first quarter 2006.
(3) Gigawatt hours.
(4) Megawatt hours.
(5) Net of fuel cost recoveries.
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TCPL's operating income of $29 million from its investment in Bruce Power
decreased $34 million in first quarter 2007 compared to first quarter 2006,
primarily due to lower generation volumes and higher operating costs associated
with additional planned outage days. The increase in Bruce Power's operations
and maintenance expense is primarily due to the significant increase in planned
outage days from 86 reactor days in first quarter 2007, compared to only 30 days
in first quarter 2006. In addition, higher post-employment benefit costs
contributed to higher operating costs. These impacts were partially offset by
higher realized prices.
TCPL's share of Bruce Power's generation for first quarter 2007 decreased 177
GWh to 3,129 GWh, compared to first quarter 2006 generation of 3,306 GWh, as a
result of an increase in planned maintenance outage days in first quarter 2007.
Bruce Power prices achieved during first quarter 2007 (excluding other revenues)
were $55 per MWh, compared to $52 per MWh in first quarter 2006. Bruce Power's
combined operating expenses (net of fuel cost recoveries) in first quarter 2007
increased to $47 per MWh from $34 per MWh in first quarter 2006 primarily due to
higher outage and other operating costs combined with lower output in first
quarter 2007.
Approximately 86 reactor days of planned maintenance outages as well as
approximately 4 reactor days of unplanned outages occurred on the six operating
units in first quarter 2007. In first quarter 2006, Bruce Power experienced
approximately 30 reactor days of planned maintenance outages and 13 reactor days
of unplanned outages. The Bruce Power units ran at a combined average
availability of 82 per cent in first quarter 2007, compared to a 90 per cent
average availability in first quarter 2006.
The overall plant availability percentage in 2007 is expected to be in the low
90s for the four Bruce B units and in the mid 70s for the two operating Bruce A
units. Two planned outages are scheduled for Bruce A Unit 3 in 2007, with the
first outage expected to last one month in second quarter 2007 and a second
outage expected to last approximately two months beginning in late third quarter
2007. A planned one month outage for Bruce A Unit 4 and a planned two and a half
month maintenance outage for Bruce B Unit 6 were both completed in April 2007.
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), all of the output from Bruce A in first quarter 2007 was sold
at a fixed price of $58.63 per MWh (before recovery of fuel costs from the OPA)
compared to $57.37 per MWh in first quarter 2006. In addition, sales from the
Bruce B Units 5 to 8 were subject to a floor price of $45.99 per MWh in first
quarter 2007 and $45.00 per MWh in first quarter 2006. Both of these reference
prices are adjusted annually for inflation on April 1. Effective April 1, 2007,
the Bruce A price is $59.69 per MWh and the Bruce B floor price is $46.82 per
MWh. Payments received pursuant to the Bruce B floor price mechanism may be
subject to a recapture payment dependent on annual 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 5,900 GWh of output for the remainder of 2007 and 5,400 GWh for
2008.
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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 March 31, 2007, Bruce A had incurred $1.338
billion with respect to the restart and refurbishment project. The Bruce A
restart project remains on schedule and on budget.
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Western Power Operations
Western Power Operations Results-at-a-Glance
Three months ended March 31
(unaudited)
(millions of dollars) 2007 2006
Revenues
Power 286 275
Other (1) 28 64
314 339
Commodity purchases resold
Power (179 ) (190 )
Other (1) (23 ) (48 )
(202 ) (238 )
Plant operating costs and other (34 ) (38 )
Depreciation (5 ) (5 )
Operating income 73 58
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(1) Other includes Cancarb Thermax and natural gas.
Western Power Operations Sales Volumes
Three months ended March 31
(unaudited)
(GWh) 2007 2006
Supply
Generation 592 585
Purchased
Sundance A & B and Sheerness PPAs 3,253 3,391
Other purchases 449 486
4,294 4,462
Contracted vs. Spot
Contracted 3,492 3,164
Spot 802 1,298
4,294 4,462
Western Power Operations' operating income of $73 million in first quarter 2007
increased $15 million compared to the $58 million earned in first quarter 2006.
This increase was primarily due to increased margins from higher overall
realized power prices on both contracted and uncontracted volumes of power sold.
Average spot market power prices in Alberta increased 12 per cent, or $6.85 per
MWh, in first quarter 2007 compared to first quarter 2006. The power price
increase was also the main contributor to an approximately 15 per cent increase
in market heat rates in first quarter 2007 as average spot market natural gas
prices remained relatively unchanged from first quarter 2006. 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.
Western Power Operations' revenues increased in first quarter 2007, compared to
first quarter 2006, primarily due to the higher overall power sales prices
realized in first quarter 2007 and slightly higher
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generation volumes, while commodity purchases resold decreased $11 million due
to a decrease in purchased power volumes. Other revenues and commodity purchases
resold decreased in first quarter 2007, compared to first quarter 2006, due to
increased natural gas transactions recorded in first quarter 2006. Western Power
Operations manages the sale of its supply volumes on a portfolio basis. A
portion of its supply is held for sale in the spot market for operational
reasons and is dependent upon the ability to transact in forward sales markets
at acceptable contract terms. This approach to portfolio management assists in
minimizing costs in situations where Western Power Operations would otherwise
have to purchase electricity in the open market to fulfill its contractual sales
obligations. Approximately 19 per cent of power sales volumes were sold into the
spot market in first quarter 2007 compared to 29 per cent in first quarter 2006.
To reduce its exposure to spot market prices on uncontracted volumes, as at
March 31, 2007, Western Power Operations had fixed price power sales contracts
to sell approximately 8,000 GWh for the remainder of 2007 and 7,400 GWh for
2008.
Eastern Power Operations
Eastern Power Operations Results-at-a-Glance (1)
Three months ended March 31
(unaudited)
(millions of dollars) 2007 2006
Revenue
Power 354 161
Other (2) 83 117
437 278
Commodity purchases resold
Power (177 ) (101 )
Other (2) (58 ) (96 )
(235 ) (197 )
Plant operating costs and other (124 ) (25 )
Depreciation (11 ) (7 )
Operating income 67 49
--------------------
(1) Eastern Power Operations includes Becancour and Baie-des-Sables
effective September 17, 2006 and November 21, 2006, respectively.
(2) Other includes natural gas.
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Eastern Power Operations Sales Volumes (1)
Three months ended March 31
(unaudited) 2007 2006
(GWh)
Supply
Generation 2,023 705
Purchased 1,526 730
3,549 1,435
Contracted vs. Spot
Contracted 3,357 1,383
Spot 192 52
3,549 1,435
--------------------
(1) Eastern Power Operations includes Becancour and Baie-des-Sables
effective September 17, 2006 and November 21, 2006, respectively.
Eastern Power Operations' operating income of $67 million in first quarter 2007
increased $18 million compared to the $49 million earned first quarter 2006.
The increase was primarily due to incremental income earned in 2007 from the
startup of both the 550 MW Becancour cogeneration plant in September 2006 and
the first of six wind farms (Baie-des-Sables) at the Cartier Wind project in
November 2006.
Generation volumes in first quarter 2007 of 2,023 GWh increased 1,318 GWh
compared to 705 GWh generated in first quarter 2006 primarily due to the placing
into service of the Becancour and Baie-des-Sables facilities, as well as
increased dispatch of the OSP facility.
Eastern Power Operations' revenues of $354 million increased $193 million in
first quarter 2007, compared to first quarter 2006, primarily due to the placing
into service of the Becancour facility and increased sales volumes to commercial
and industrial customers. Power commodity purchases resold of $177 million and
purchased power volumes of 1,526 GWh were higher in first quarter 2007, compared
to first quarter 2006, primarily due to the impact of increased purchases to
supply sales contracts. First quarter 2007 other revenue and other commodity
purchases resold of $83 million and $58 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.
Plant operating costs and other of $124 million, which includes fuel gas
consumed in generation, increased in first quarter 2007 from the prior year
primarily as a result of the startup of the Becancour facility.
In first quarter 2007, approximately five per cent of power sales volumes were
sold into the spot market compared to approximately four per cent in first
quarter 2006. 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
March 31, 2007, Eastern Power Operations had entered into fixed price power
sales contracts to sell approximately 10,100 GWh for the remainder of 2007 and
10,300 GWh for
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2008, although certain contracted volumes are dependent on customer usage
levels.
Power Plant Availability
Weighted Average Power Plant Availability (1)
Three months ended March 31
(unaudited) 2007 2006
Bruce Power 82 % 90 %
Western Power Operations 99 % 90 %
Eastern Power Operations (2) 97 % 95 %
All plants, excluding Bruce Power 97 % 94 %
All plants 91 % 91 %
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(1) Plant availability represents the percentage of time in the
period that the plant is available to generate power, whether actually running
or not and is reduced by planned and unplannned outages.
(2) Eastern Operations includes Becancour and Baie-des-Sables
effective September 17, 2006 and November 21, 2006, respectively.
Natural Gas Storage
Natural Gas Storage operating income of $30 million in first quarter 2007
increased $8 million compared to $22 million in first quarter 2006. The
increase was primarily due to higher earnings from CrossAlta as a result of
increased capacity and higher natural gas storage spreads as well as incremental
income earned in 2007 from the startup of the Edson facility in December 2006.
General, Administrative and Support Costs
General, administrative and support costs of $36 million in first quarter 2007
increased $6 million compared to first quarter 2006 primarily due to higher
costs associated with growing the Energy business.
As at March 31, 2007, TCPL had capitalized $32 million related to the Broadwater
liquefied natural gas (LNG) project.
Corporate
Net earnings from Corporate for the three months ended March 31, 2007 were $2
million, compared to net expenses of $13 million for the same period in 2006.
The increase in earnings was primarily due to favourable income tax adjustments
recorded in first quarter 2007, including a $10 million benefit on the
resolution of certain income tax matters, a $5 million benefit resulting from an
internal restructuring, as well as certain other tax items relating to changes
in estimates and tax rate differentials. Partially offsetting these increases
was an increase to financial charges as a result of financing the recent ANR and
Great Lakes acquisitions.
14
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Liquidity and Capital Resources
Funds Generated from Operations
Three months ended March 31
(unaudited)
(millions of dollars) 2007 2006
Cash Flows
Funds generated from operations (1) 579 516
Decrease/(increase) in operating working capital 41 (1 )
Net cash provided by operations 620 515
--------------------
(1) For a further discussion on funds generated from operations,
refer to the Non-GAAP Measures section in this MD&A.
Net cash provided by operations increased $105 million in first quarter 2007
compared to first quarter 2006. The increase in cash was primarily due to a
decrease in operating working capital. Funds generated from operations were $579
million for the three months ended March 31, 2007, compared to $516 million for
the same period in 2006. The increase was mainly due to an increase in cash
generated through earnings.
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,
2006.
Investing Activities
Acquisitions, net of cash acquired, for the three months ended March 31, 2007
were $4,265 million (2006 - nil) due to the acquisition of ANR and an
additional 3.55 per cent interest in Great Lakes for approximately US$3.4
billion, including US$491 million of assumed long-term debt. Acquisitions also
include PipeLines LP's 46.45 per cent interest in Great Lakes for approximately
US$942 million, including US$209 million of assumed long-term debt. These
acquisitions are discussed further in the Acquisitions section of this MD&A.
For the three months ended March 31, 2007, capital expenditures totalled $306
million (2006 - $303 million) and related to the restart and refurbishment of
Bruce A Units 1 and 2, the construction of new power plants and capital
expenditures in Pipelines.
Financing Activities
TCPL retired $325 million of long-term debt in the three months ended March 31,
2007 ($140 million - March 31, 2006), and issued $1.362 billion of long-term
debt ($878 million - March 31, 2006). For the three months ended March 31, 2007,
notes payable increased $502 million, and cash and short-term investments
decreased $54 million.
On March 20, 2007, TCPL filed debt shelf prospectuses in Canada and the U.S.
qualifying for the issuance of $1.5 billion of medium-term notes and US$1.5
billion of debt securities, respectively.
On March 20, 2007, ANR Pipeline Company provided notice to the New York Stock
Exchange of its intention to voluntarily withdraw from listing its 9.625 per
cent Debentures due 2021, 7.375 per cent Debentures due 2024, and 7.0 per cent
Debentures due 2025. Following the delisting, which became effective April 12,
2007, ANR Pipeline Company deregistered these securities from registration with
the U.S. Securities Exchange
15
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Commission (SEC).
In February and March 2007 TCPL issued 34,210,526 and 4,515,914 common shares,
respectively, to TransCanada Corporation at a price of $38.00 each. This
resulted in gross proceeds to TCPL of $1.5 billion which were used towards
financing the acquisition of ANR.
In February 2007, the Company, through a wholly owned subsidiary, established a
US$1.0 billion committed, unsecured credit facility, consisting of a US$700
million five-year term loan and a US$300 million five-year, extendible revolving
facility. Interest is charged at a floating rate based on London Interbank
Offered Rate (LIBOR). The Company utilized US$1.0 billion from this facility and
an additional US$100 million from an existing demand line to partially finance
the ANR acquisition as well as its additional investment in PipeLines LP
described previously. At March 31, 2007, the Company had an outstanding balance
of US$1.0 billion on the credit facility and US$85 million on the demand line.
On February 22, 2007, PipeLines LP increased the size of its syndicated
revolving credit and term loan facility in connection with its Great Lakes
acquisition. The amount available under the facility increased from US$410
million to US$950 million, consisting of a US$700 million senior term loan and a
US$250 million senior revolving credit facility, with US$194 million of the
senior term loan available being terminated upon closing of the Great Lakes
acquisition. Interest is charged at a floating rate based on LIBOR.
Dividends
On April 26, 2007, TCPL's Board of Directors declared a quarterly dividend for
the quarter ending June 30, 2007 in an aggregate amount equal to the quarterly
dividend to be paid on July 31, 2007 by TransCanada Corporation (TransCanada) on
the outstanding common shares at the close of business on June 29, 2007. The
Board also declared regular dividends on TCPL's preferred shares.
TransCanada's Board of Directors also approved the issuance of common shares
from treasury at a two percent discount under TransCanada's Dividend
Reinvestment and Share Purchase Plan for the dividend payable July 31, 2007.
TransCanada reserves the right to alter the discount or return to purchasing
shares on the open market at any time. TCPL preferred shareholders may reinvest
their dividends to obtain TransCanada common shares.
Changes in Accounting Policy
Changes for 2007
Effective January 1, 2007, the Company adopted the new Canadian Institute of
Chartered Accountants (CICA) Handbook accounting requirements for Section 1506 "
Accounting Changes", Section 1530 "Comprehensive Income", Section 3251 "Equity",
Section 3855 "Financial Instruments - Recognition and Measurement", Section 3861
"Financial Instruments - Disclosure and Presentation", and Section 3865 "Hedges
". Adjustments to first quarter consolidated financial statements for 2007 have
been
16
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made in accordance with the transitional provisions for these new standards.
Comprehensive Income and Equity
The Company's financial statements include a statement of Consolidated
Comprehensive Income. In addition, as required by Section 3251, the Company now
presents separately in its Changes in Consolidated Shareholders' Equity the
changes for each of its components of Shareholders' Equity. A new component,
Accumulated Other Comprehensive Income, has been added to the Company's
Shareholders' Equity as a result of the implementation of this new standard.
Financial Instruments
All financial instruments, including derivatives, are included on the balance
sheet initially at fair value. The financial assets are classified as
held-for-trading, held-to-maturity, loans and receivables, or
available-for-sale. Financial liabilities are classified as held-for-trading or
other financial liabilities. Subsequent measurement is determined by
classification.
Held-for-trading financial assets and liabilities are entered into with the
intention of generating a profit and consist of swaps, options, forwards and
futures. These financial instruments are initially accounted for at their fair
value and changes to fair value are recorded in income. Held-to-maturity
financial assets are accounted for at their amortized cost using the effective
interest method. The Company did not have any of these financial instruments at
March 31, 2007. Loans and receivables are accounted for at their amortized cost
using the effective interest method. The available-for-sale classification
includes non-derivative financial assets that are designated as
available-for-sale or are not included in the other three classifications. These
instruments are initially accounted for at their fair value and changes to fair
value are recorded through Other Comprehensive Income. Income earned from these
assets is included in Interest Income and Other.
Other financial liabilities not classified as held-for-trading are accounted for
at their amortized cost, using the effective interest method. Interest expense
is included in Financial Charges and Financial Charges of Joint Ventures.
Derivatives embedded in other financial instruments or contracts (the host
instrument) are recorded as separate derivatives and are measured at fair value
if the economic characteristics of the embedded derivative are not closely
related to the host instrument, the terms of the embedded derivative are the
same as those of a stand-alone derivative and the total contract is not
held-for-trading or accounted for at fair value. Changes in fair value of the
embedded derivative are included in income. All derivatives, other than those
that meet the normal purchases and sales exceptions, are carried on the balance
sheet at fair value. The Company used January 1, 2003 as the transition date for
embedded derivatives.
Transaction costs are incremental costs that are directly attributable to the
acquisition, issue or disposal of a financial instrument. Effective January 1,
2007, the Company began offsetting long-term debt transaction costs against the
associated debt and began amortizing these
17
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costs using the effective interest method. Previously, these costs were
amortized straight-line over the life of the debt. There was no material effect
on the Company's financial statements as a result of this change in policy. In
first quarter 2007, the charge to Net Income for the amortization of transaction
costs using the effective interest method was immaterial.
As part of the accounting for the Company's regulated operations, gains or
losses from the changes in the fair value of financial instruments within the
regulated operations are included in regulatory assets or regulatory
liabilities.
Hedges
The new standard specifies the circumstances under which hedge accounting is
permissible, how hedge accounting may be performed and where the impacts should
be recorded. The standard introduces three specific types of hedging
relationships: fair value hedges, cash flow hedges and hedges of a net
investment in self-sustaining foreign operations.
As part of its asset and liability management, the Company uses derivatives for
hedging positions to reduce its exposure to credit and market risk. The Company
designates certain derivatives as hedges and prepares documentation at the
inception of the hedging contract. The Company performs an assessment at
inception and during the term of the contract to determine if the derivative
used as a hedge is effective in offsetting the risks in the values or cash flows
of the hedged financial instrument. All derivatives are initially recorded at
fair value and adjusted to fair value at each reporting date.
Fair value hedges primarily consist of interest rate swaps used to mitigate the
effect of changes in the fair value of fixed-rate long-term financial
instruments due to movements in market interest rates. Changes in the value of
fair value hedges are recorded in Financial Charges and Interest Income and
Other, for interest rate and foreign exchange hedges, respectively. Any gains or
losses arising from the ineffectiveness are recognized immediately in income in
the same financial category as the underlying transaction.
The Company uses cash flow hedges to reduce its exposure to fluctuations in
interest rates, foreign exchange and changes in commodity prices. The effective
portion of changes in the value of cash flow hedges is recognized in Other
Comprehensive Income. Ineffective portions and amounts excluded from
effectiveness testing of hedges are included in income in the same financial
category as the underlying transaction. Gains or losses from cash flow hedges
that have been included in Accumulated Other Comprehensive Income are included
in Net Income when the underlying transaction has occurred or becomes probable
of not occurring. The maximum length of time the Company is hedging its exposure
to variability in future cash flows is 10 years.
The Company hedges its foreign currency exposure of investments in
self-sustaining foreign operations with certain cross-currency swaps, forward
exchange contracts and options. These financial instruments are adjusted to fair
value and the effective portion of gains or losses associated with these
adjustments are included in Other Comprehensive Income. In addition, the Company
hedges its net investment with U.S.
18
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dollar-denominated debt, which is valued at period-end foreign exchange rates.
Gains or losses arising from ineffective portions of the hedge are included in
income. Gains or losses from these hedges that have been included in Accumulated
Other Comprehensive Income are reclassified to Net Income in the event the
Company settles or otherwise reduces its investment.
Net Effect of Accounting Policy Changes
The net effect to the Company's financial statements at January 1, 2007
resulting from the above-mentioned changes in accounting policies is as follows.
Increases/(decreases)
(unaudited)
(millions of dollars)
Other current assets (127 )
Other assets (203 )
Accounts payable (29 )
Deferred amounts (75 )
Future income taxes (42 )
Long-term debt (85 )
Long-term debt of joint ventures (7 )
Accumulated other comprehensive loss (186 )
Foreign exchange adjustment 90
Retained earnings 4
Future Accounting Changes
Section 1535 Capital Disclosures
Effective for interim and annual financial statements for fiscal years beginning
on or after October 1, 2007, the new CICA Handbook Section 1535 "Capital
Disclosures" requires the disclosure of qualitative and quantitative information
about the Company's objectives, policies and processes for managing capital.
Section 3862 Financial Instruments - Disclosures and Section 3863 - Financial
Instruments - Presentation
Effective for interim and annual financial statements for fiscal years beginning
on or after October 1, 2007, the new CICA Handbook Sections 3862 and 3863 will
replace Section 3861 to prescribe the requirements for presentation and
disclosure of financial instruments.
Contractual Obligations
As a result of TCPL's acquisition of ANR, Pipelines' future purchase
obligations, primarily consisting of operating lease and purchase obligations,
increased $152 million at March 31, 2007, compared to December 31, 2006.
19
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Other than the above-mentioned ANR commitments and future debt and interest
payments on debt utilized to acquire ANR, there have been no material changes to
TCPL's contractual obligations from December 31, 2006 to March 31, 2007,
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 2006
Annual Report.
Financial and Other Instruments
Interest, Foreign Exchange and Energy Risk Management
During the three-month period ended March 31, 2007, the Company had positions in
the following types of derivatives:
* Forwards and future contracts - contractual agreements to buy
or sell a specific financial instrument at a specified price and date in the
future. The Company enters into foreign exchange and commodity forwards and
futures to mitigate volatility in changes in foreign exchange rates and power
and gas prices, respectively.
* Swaps - contractual agreements between two parties to
exchange streams of payments over time according to specified terms. The Company
enters into interest rate and cross-currency swaps to mitigate changes in
interest rates and foreign exchange, respectively.
* Options - contractual agreements to convey the right, but not
the obligation, for the purchaser either to buy or sell a specific amount of a
financial instrument at a fixed price, either at a fixed date or at any time
within a specified period. The Company enters into option agreements to mitigate
changes in interest rates, foreign exchange and commodity prices.
The Company has long-term debt, interest rate swaps and interest rate options
that have a fixed interest rate and, therefore, are subject to interest rate
price risk. The Company has long-term debt, interest-rate swaps and
interest-rate options, which have a floating interest rate and, therefore, are
subject to interest rate cash flow risk.
The Company calculated the fair value of foreign exchange and interest rate
derivatives using quoted market rates. The changes in fair value for interest
rate and foreign exchange derivatives are included in Financial Charges and
Interest Income and Other, respectively.
The Company executes power, natural gas and heat rate derivatives for overall
management of its asset portfolio. Heat rate contracts are agreements for the
sale or purchase of power that are priced based on a natural gas index. The fair
value of power and natural gas derivatives was calculated using estimated
forward prices for the relevant period. In accordance with the Company's
accounting policy, the fair values of these derivatives are recorded as
financial assets and liabilities.
At March 31, 2007, the Company had included net losses of $4 million (March 31,
2006 - net gains of $5 million) in Net Income as a result of its swaps, futures,
options and contracts. At March 31, 2007, there were unrealized gains from
unsettled derivatives of $52 million (December 31, 2006 - $41 million)
20
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included in Other Current Assets and $210 million (December 31, 2006 - $39
million) included in Other Assets. At March 31, 2007, unrealized losses of $116
million (December 31, 2006 - $144 million) were included in Accounts Payable and
$259 million (December 31, 2006 - $158 million) included in Deferred Amounts.
The Company hedges its net investment in self-sustaining foreign operations with
U.S. dollar-denominated debt, cross-currency swaps, forward exchange contracts
and options. At March 31, 2007, the Company had designated U.S.
dollar-denominated debt with a carrying value of $2,771 million (US$2,403
million) and a fair value of $2,948 million (US$2,557 million) as a portion of
this hedge and swaps, forwards and options with a fair value of $73 million
(US$64 million) as net investment hedges.
Other Risk Management
Currency risk arises when the fair value or future cash flows of a financial
instrument fluctuate due to changes in foreign exchange rates. The Company
manages currency risk through the use of derivatives such as cross-currency
swaps, options and forward foreign exchange contracts. Market risk is the risk
that the fair value of future cash flows of financial instruments will fluctuate
due to changes in market variables such as interest rates, foreign exchange and
commodity prices. In order to manage market risk, the Company enters into
offsetting physical positions and derivative financial instruments. Liquidity
risk is the risk that an entity will encounter difficulty in meeting obligations
associated with financial instruments. Additional, risks faced by the Company
are discussed in the MD&A in TCPL's 2006 Annual Report. These risks have not
had a material effect on the Company's financial results at March 31, 2007 and
have been mitigated by risk management strategies.
TCPL's market, financial and counterparty risks remain substantially unchanged
since December 31, 2006. For further information on risks, refer to the MD&A in
TCPL's 2006 Annual Report.
Risk and Risk Management Related to Environmental Regulations
In March 2007, the Alberta Government released its Climate Change and Emissions
Management Act aimed at reducing greenhouse gas starting in July 2007. The
Alberta Government is currently seeking comments on the proposed regulations and
many of the specifics have yet to be determined. The Canadian Federal Government
is expected to release similar legislation imminently. As these legislative
initiatives have the potential to significantly impact the energy industry, the
Company continues to assess and monitor the implications to TCPL's businesses.
Controls and Procedures
As of March 31, 2007, an evaluation was carried out under the supervision of,
and with the participation of, management including the President and Chief
Executive Officer and Chief Financial Officer, of the effectiveness of TCPL's
disclosure controls and procedures as defined under the rules adopted by the
Canadian securities regulatory authorities and by the U.S. Securities and
Exchange Commission. Based on that evaluation, the President and Chief Executive
Officer and Chief Financial
21
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Officer concluded that the design and operation of TCPL's disclosure controls
and procedures were effective as at March 31, 2007.
During the recent fiscal quarter, there have been no changes in TCPL's internal
control over financial reporting that have materially affected, or are
reasonably likely to materially affect, TCPL's internal control over financial
reporting. With respect to the recent acquisitions, the Company has not yet
determined whether or not to apply the acquisitions exemption allowed under the
Sarbanes-Oxley Act of 2002.
Significant Accounting Policies and Critical Accounting Estimates
Since determining the value of certain 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 significant accounting policies and critical accounting estimates are the
use of regulatory accounting for the Company's regulated operations and the
policies the Company adopts to account for derivatives and depreciation and
amortization expense. Effective January 1, 2007, the Company adopted the new
accounting standards for financial instruments and hedges, as discussed in the
section Changes in Accounting Policies in this MD&A. For further information on
the Company's accounting policies and estimates refer to the MD&A in TCPL's 2006
Annual Report.
Outlook
Excluding the $15 million of income tax adjustments recorded in first quarter
2007, the Company's outlook is relatively unchanged since the disclosure in the
Company's 2006 Annual Report. For further information on outlook, refer to the
MD&A in TCPL's 2006 Annual Report.
TCPL's senior unsecured debt is rated A, with a stable outlook, by DBRS; A2,
with a stable outlook, by Moody's Investors Service; and A-, with a stable
outlook, by Standard & Poor's.
Other Recent
Developments
Pipelines
Wholly Owned Pipelines
Canadian Mainline
In February 2007, TCPL reached a multi-year tolls settlement for the years 2007
to 2011 on the Canadian Mainline.
TCPL and its stakeholders agreed that the cost of capital will reflect an ROE,
as determined by the NEB's return on equity formula, on a deemed common equity
ratio of 40 per cent, an increase from 36 per cent. The remaining capital
structure will consist of senior debt following the agreed upon redemption of
US$460 million Preferred Securities currently included in the Canadian
Mainline's investment base.
22
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The settlement also establishes certain elements of the Canadian Mainline's
fixed operating, maintenance and administration (OM&A) costs for each year of
the settlement. Any variance between actual OM&A costs and those agreed to in
the settlement will accrue to TCPL from 2007 to 2009. Variances in certain
elements of OM&A costs will be shared equally between TCPL and its customers in
2010 and 2011. All other cost elements of the revenue requirement will be
treated on a flow-through basis.
The performance-based incentive arrangements, similar to those agreed to in the
2006 settlement, are focused on aligning interests in achieving cost savings and
increased value, thereby providing mutual benefits to both TCPL and its
customers. TCPL and its stakeholders have agreed to a slight decrease in the
depreciation rate for the term of the settlement and to seek NEB approval to put
the requirement for an updated depreciation study due in 2008 into abeyance
until 2012.
Interim tolls as approved by the NEB in March 2007 will continue to be charged
for transportation service on the Canadian Mainline until final tolls are
approved by the NEB pursuant to this settlement. In March 2007, TCPL applied to
the NEB for approval of this settlement, and a decision is expected in second
quarter 2007. Until this decision is received, TCPL is recording its Canadian
Mainline net earnings using the NEB ROE formula on a deemed common equity ratio
of 36 per cent.
Alberta System
In March 2007, the Alberta Energy and Utilities Board (EUB) approved the 2007
final rates for the Alberta System as filed. The rates are effective April 1,
2007 to December 31, 2007 and reflect the 2005-2007 Revenue Requirement
Settlement on the Alberta System.
Northern Border
Effective April 1, 2007, TCPL became the operator of Northern Border. TCPL owns
16 per cent of Northern Border through its 32.1 per cent ownership of PipeLines
LP.
BC System and Foothills
In February 2007, the NEB approved the integration of the BC System into
Foothills. In March 2007, the NEB approved a compliance filing confirming an
April 1, 2007 effective date for the transfer and providing final 2007 tolls.
Gas Transmission Northwest System
TCPL filed a rate case with the FERC for its Gas Transmission Northwest System.
In January 2007, TCPL received a procedural order from the FERC establishing a
timeline for the System's rate case proceeding with a hearing scheduled to
commence on October 31, 2007. In April 2007, the Company initiated settlement
discussions with its customers and the FERC.
23
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Beginning January 1, 2007, GTN increased its transportation rates in accordance
with the FERC's July 31, 2006 suspension order. The additional revenue collected
is subject to refund based upon the outcome of GTN's rate case proceeding. Until
final approval of rates is received from the FERC, the Company has been
recording a provision for rate refund equal to the difference in transportation
revenue based on GTN's new rates and the rates that were in effect prior to
January 1, 2007.
North Baja Pipeline Expansion
TCPL's North Baja Pipeline has filed an application with the FERC to expand and
modify its existing system to facilitate the importation of regassified LNG from
Mexico into the California and Arizona markets. The FERC has 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. TCPL expects that the final Environmental Impact Statement will be
completed and the FERC will issue its final order authorizing the project by mid
year 2007.
Mackenzie Gas Pipeline Project
In March 2007, the proponents of the Mackenzie Gas Project (MGP) filed updated
capital cost estimates for the project with the NEB and a Joint Review Panel
(JRP). These estimates include $3.5 billion for the gas gathering system, $7.8
billion for the pipeline and $4.9 billion for the development of the proponent's
gas fields. Additional project update information is expected to be filed in
June 2007, describing further project adjustments and refinements.
The MGP proponents continue to participate in public hearings convened by the
JRP, assessing socio-economic and environmental aspects of the project. These
regulatory hearings are expected to conclude in the second half of 2007, with
the JRP's report to follow.
Alaska Highway Pipeline Project
TCPL is continuing its discussions with the Alaska North Slope producers. The
Alaska State administration has introduced the Alaska Gasline Inducement Act
(AGIA) as their new process for the portion of the pipeline project in Alaska.
The Alaska State Legislature is currently reviewing the bill, with final
disposition expected by approximately June 2007. If AGIA is passed in its
current form, it is expected the State will choose a licensee for the pipeline
project near the end of 2007.
Energy
Broadwater
Broadwater is a partnership between TCPL and Shell US Gas & Power to construct
an LNG facility in the New York State waters of Long Island Sound. TCPL
anticipates that the FERC will issue a Final Environmental Impact Statement in
third quarter 2007. A similar timeline is anticipated
24
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for the State of New York to render a decision on whether the Broadwater project
is consistent with its coastal management policies.
Share Information
As at March 31 2007, TCPL had 522,070,549 issued and outstanding common shares
to TransCanada Corporation.
Selected Quarterly Consolidated Financial Data(1)
(unaudited) 2007 2006 2005
(millions of dollars except per share First Fourth Third Second First Fourth Third Second
amounts)
Revenues 2,249 2,091 1,850 1,685 1,894 1,771 1,494 1,449
Net Income Applicable to Common Shares
Continuing operations 263 268 293 244 244 349 428 199
Discontinued operations - - - - 28 - - -
263 268 293 244 272 349 428 199
Per Common Share Data
Net income per share - Basic and
Diluted
Continuing operations $ 0.50 $ 0.56 $ 0.60 $ 0.51 $ 0.50 $ 0.72 $ 0.89 $ 0.41
Discontinued operations - - - - 0.06 - - -
$ 0.50 $ 0.56 $ 0.60 $ 0.51 $ 0.56 $ 0.72 $ 0.89 $ 0.41
--------------------
(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.
Factors Impacting Quarterly Financial Information
In Pipelines, which consists primarily of the Company's investments in regulated
pipelines and natural gas storage facilities, 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 resulting from adjustments being recorded due to regulatory
decisions and negotiated settlements with shippers, seasonal fluctuations in
short-term throughput on U.S. pipelines and items outside of the normal course
of operations.
In Energy, which consists primarily of the Company's investments in electrical
power generation plants and non-regulated 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.
* Second quarter 2005 net earnings included $21 million ($13 million
related to 2004 and $8 million related to 2005) with respect to the NEB's
decision on the Canadian Mainline's 2004
25
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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 income from equity investments was lower than previous quarters due to
the continuing impact of planned maintenance outages and an unplanned
maintenance outage on Unit 6 relating to a transformer fire.
* In third quarter 2005, net earnings included a $193 million
after-tax gain related to the sale of the Company's ownership interest in
TransCanada Power, LP. In addition, Bruce Power's income from equity
investments increased from prior quarters due to higher realized power prices
and slightly higher generation volumes.
* In fourth quarter 2005, net earnings included a $115 million
after-tax gain on the sale of P.T. Paiton Energy Company. In addition, Bruce A
was formed and Bruce Power's results were proportionately consolidated,
effective October 31, 2005.
* In first quarter 2006, net earnings included an $18 million after-tax
bankruptcy claim settlement from a former shipper on 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.
* In second quarter 2006, net earnings included $33 million of future income
tax benefits ($23 million in Energy and $10 million in Corporate) as a result of
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 general partner interest in Northern Border Partners, L.P.
* In 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.
* In fourth quarter 2006, net earnings included approximately $12
million related to income tax refunds and related interest.
* In first quarter 2007, net earnings included approximately $15
million related to positive income tax adjustments. In addition, Pipelines' net
earnings included contributions from the February 22, 2007 acquisition of ANR
and additional interests in Great Lakes.
26
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Exhibit 13.2
Consolidated Income
Three months ended March 31
(unaudited)
(millions of dollars) 2007 2006
Revenues 2,249 1,894
Operating Expenses
Plant operating costs and other 732 537
Commodity purchases resold 576 505
Depreciation 290 257
1,598 1,299
651 595
Other Expenses/(Income)
Financial charges 239 203
Financial charges of joint ventures 21 21
Income from equity investments (6 ) (18 )
Interest income and other (24 ) (49 )
230 157
Income from Continuing Operations before Income
Taxes and Non-Controlling Interests 421 438
Income Taxes
Current 167 210
Future (37 ) (41 )
130 169
Non-Controlling Interests
Non-controlling interest in PipeLines LP 17 13
Other 5 6
22 19
Net Income from Continuing Operations 269 250
Net Income from Discontinued Operations - 28
Net Income 269 278
Preferred Share Dividends 6 6
Net Income Applicable to Common Shares 263 272
Net Income Applicable to Common Shares
Continuing operations 263 244
Discontinued operations - 28
263 272
See accompanying notes to the consolidated financial statements.
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Consolidated Cash Flows
Three months ended March 31
(unaudited)
(millions of dollars) 2007 2006
Cash Generated From Operations
Net income 269 250
Depreciation 290 257
Income from equity investments in excess of distributions received (6 ) (4 )
Future income taxes (37 ) (41 )
Non-controlling interests 22 19
Funding of employee future benefits lower than/(in excess of) expense 12 (2 )
Other 29 37
579 516
Decrease/(increase) in operating working capital 41 (1 )
Net cash provided by operations 620 515
Investing Activities
Capital expenditures (306 ) (303 )
Acquisitions, net of cash acquired (4,265 ) -
Deferred amounts and other (43 ) (9 )
Net cash used in investing activities (4,614 ) (312 )
Financing Activities
Dividends on common and preferred shares (162 ) (155 )
Advances from parent 756 -
Distributions paid to non-controlling interests (10 ) (10 )
Notes payable issued/(repaid), net 502 (633 )
Long-term debt issued 1,362 878
Reduction of long-term debt (325 ) (140 )
Long-term debt of joint ventures issued 12 2
Reduction of long-term debt of joint ventures (12 ) (6 )
Partnership units of subsidiary issued 348 -
Common shares issued 1,472 -
Net cash provided by/(used in) financing activities 3,943 (64 )
Effect of Foreign Exchange Rate Changes on Cash and Short-Term Investments (3 ) 2
(Decrease)/increase in Cash and Short-Term Investments (54 ) 141
Cash and Short-Term Investments
Beginning of period 401 212
Cash and Short-Term Investments
End of period 347 353
Supplementary Cash Flow Information
Income taxes paid 87 217
Interest paid 273 199
See accompanying notes to the consolidated financial statements.
2
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Consolidated Balance Sheet
(unaudited) March 31, December
31,
(millions of dollars) 2007 2006
ASSETS
Current Assets
Cash and short-term investments 347 401
Accounts receivable 1,135 1,001
Inventories 478 392
Other 116 297
2,076 2,091
Long-Term Investments 76 71
Plant, Property and Equipment 24,181 21,487
Goodwill 2,878 281
Other Assets 1,888 1,978
31,099 25,908
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Notes payable 968 467
Accounts payable 2,416 1,582
Accrued interest 278 264
Current portion of long-term debt 494 616
Current portion of long-term debt of joint ventures 137 142
4,293 3,071
Deferred Amounts 1,097 1,029
Future Income Taxes 1,216 876
Long-Term Debt 12,945 10,887
Long-Term Debt of Joint Ventures 864 1,136
Preferred Securities 530 536
20,945 17,535
Non-Controlling Interests
Non-controlling interest in PipeLines LP 634 287
Other 83 79
717 366
Shareholders' Equity
Preferred shares 389 389
Common shares 6,184 4,712
Contributed surplus 278 277
Retained earnings 2,804 2,719
Accumulated other comprehensive loss (218 ) (90 )
9,437 8,007
31,099 25,908
See accompanying notes to the consolidated financial statements.
3
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Consolidated Comprehensive Income
Three months ended March 31
(unaudited)
(millions of dollars) 2007 2006
Net income 263 272
Other comprehensive loss, net of tax
Change in foreign currency translation gains and losses on investments in foreign operations(1) (37 ) (1 )
Change in gains and losses on hedges of investments in foreign operations(2) 9 (3 )
Change in gains and losses on derivative instruments designated as cash flow hedges(3) (1 )
Reclassification to net income of gains and losses on derivative instruments designated as cash (3 )
flow hedges pertaining to prior periods(4) (5)
Other comprehensive loss for the period (32 ) (4 )
Comprehensive income for the period 231 268
--------------------
(1) Net of tax recovery of $5 million (2006 - expense of $1
million).
(2) Net of tax recovery of $5 million (2006 - expense of $2
million).
(3) Net of tax recovery of $5 million.
(4) Net of tax recovery of $2 million.
(5) During the next 12 months, the Company expects to reclassify to
net income $86 million ($60 million after tax) of realized net losses for cash
flow hedges.
See accompanying notes to the consolidated financial statements.
4
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Consolidated Shareholders' Equity
Three months ended March 31
(unaudited)
(millions of dollars) 2007 2006
Preferred Shares $ 389 $ 389
Common Shares
Balance at beginning of period 4,712 4,712
Proceeds from common shares issued 1,472 -
Proceeds from shares issued on exercise of stock options - -
Balance at end of period 6,184 4,712
Contributed Surplus
Balance at beginning of period 277 275
Issuance of stock options 1 -
Balance at end of period 278 275
Retained Earnings
Balance at beginning of period 2,719 2,267
Transition adjustment resulting from adopting new financial instruments accounting standards 4
Net income 269 278
Preferred share dividends (6 ) (6 )
Common share dividends (182 ) (156 )
Balance at end of period 2,804 2,383
Accumulated Other Comprehensive Loss, net of income taxes
Balance at beginning of period (90 ) (90 )
Transition adjustment resulting from adopting new financial instruments accounting standards (96 )
Change in foreign currency translation gains and losses on investments in foreign operations (28 ) (4 )
Change in gains and losses on derivative instruments designated as cash flow hedges (1 )
Reclassification to net income of gains and losses on derivative instruments designated as (3 )
cash flow hedges pertaining to prior periods
Balance at end of period (218 ) (94 )
Total Shareholders' Equity $ 9,437 $ 7,665
See accompanying notes to the consolidated financial statements.
5
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Notes to Consolidated Financial Statements
(Unaudited)
1. Significant Accounting Policies
The consolidated financial statements of TransCanada PipeLines Limited (TCPL or
the Company) have been prepared in accordance with Canadian generally accepted
accounting principles (GAAP). The accounting policies applied are consistent
with those outlined in TCPL's annual audited consolidated financial statements
for the year ended December 31, 2006, except for the changes noted below. These
consolidated financial statements reflect all normal recurring adjustments that
are, in the opinion of management, necessary to present fairly the financial
position and results of operations for the respective periods. These
consolidated financial statements do not include all disclosures required in the
annual financial statements and should be read in conjunction with the 2006
audited consolidated financial statements included in TCPL's 2006 Annual Report.
Amounts are stated in Canadian dollars unless otherwise indicated. Certain
comparative figures have been reclassified to conform with current period's
presentation.
In Pipelines, which consists primarily of the Company's investments in regulated
pipelines and natural gas storage facilities, 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 resulting from adjustments being recorded due to regulatory
decisions and negotiated settlements with shippers, seasonal fluctuations in
short-term throughput on U.S. pipelines and items outside of the normal course
of operations.
In Energy, which consists primarily of the Company's investments in electrical
power generation plants and non-regulated 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.
Since a determination of the value 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. Changes In Accounting Policies
Changes for 2007
Effective January 1, 2007, the Company adopted the new Canadian Institute of
Chartered Accountants (CICA) Handbook accounting requirements for Section 3855 "
Financial Instruments - Recognition and Measurement", Section 3865 "Hedges",
Section 3861 "Financial Instruments - Disclosure and Presentation", Section 1530
"Comprehensive Income", Section 3251 "Equity" and Section 1506 "Accounting
Changes". Adjustments to first quarter consolidated financial statements for
2007
6
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have been made in accordance with the transitional provisions for these new
standards.
7
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Financial Instruments
All financial instruments, including derivatives, are included on the balance
sheet initially at fair value. The financial assets are classified as
held-for-trading, held-to-maturity, loans and receivables, or
available-for-sale. Financial liabilities are classified as held-for-trading or
other financial liabilities. Subsequent measurement is determined by
classification.
Held-for-trading financial assets and liabilities are entered into with the
intention of generating a profit and consist of swaps, options, forwards and
futures. These financial instruments are initially accounted for at their fair
value and changes to fair value are recorded in income. Held-to-maturity
financial assets are accounted for at their amortized cost using the effective
interest method. The Company did not have any of these financial instruments at
March 31, 2007. Loans and receivables are accounted for at their amortized cost
using the effective interest method. The available-for-sale classification
includes non-derivative financial assets that are designated as
available-for-sale or are not included in the other three classifications. These
instruments are initially accounted for at their fair value and changes to fair
value are recorded through Other Comprehensive Income. Income earned from these
assets is included in Interest Income and Other.
Other financial liabilities not classified as held-for-trading are accounted for
at their amortized cost, using the effective interest method. Interest expense
is included in Financial Charges and Financial Charges of Joint Ventures.
Derivatives embedded in other financial instruments or contracts (the host
instrument) are recorded as separate derivatives and are measured at fair value
if the economic characteristics of the embedded derivative are not closely
related to the host instrument, the terms of the embedded derivative are the
same as those of a stand-alone derivative and the total contract is not
held-for-trading or accounted for at fair value. Changes in fair value are
included in income. All derivatives, other than those that meet the normal
purchases and sales exceptions, are carried on the balance sheet at fair value.
The Company used January 1, 2003 as the transition date for embedded
derivatives.
Transaction costs are incremental costs that are directly attributable to the
acquisition, issue or disposal of a financial instrument. Effective January 1,
2007, the Company began offsetting long-term debt transaction costs against the
associated debt and began amortizing these costs using the effective interest
rate method. Previously, these costs were amortized straight-line over the life
of the debt. There was no material effect on the Company's financial statements
as a result of this change in policy. In first quarter 2007, the charge to Net
Income for the amortization of transaction costs using the effective interest
method was not material.
As part of the accounting for the Company's regulated operations, gains or
losses from the changes in the fair value of financial instruments within the
regulated operations are included in regulatory assets or regulatory
liabilities.
8
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Hedges
The new standard specifies the circumstances under which hedge accounting is
permissible, how hedge accounting may be performed and where the impacts should
be recorded. The standard introduces three specific types of hedging
relationships: fair value hedges, cash flow hedges and hedges of a net
investment in self-sustaining foreign operations.
As part of its asset and liability management, the Company uses derivatives for
hedging positions to reduce its exposure to credit and market risk. The Company
designates certain derivatives as hedges and prepares documentation at the
inception of the hedging contract. The Company performs an assessment at
inception and during the term of the contract to determine if the derivative
used as a hedge is effective in offsetting the risks in the values or cash flows
of the hedged financial instrument. All derivatives are initially recorded at
fair value and adjusted to fair value at each reporting date.
Fair value hedges primarily consist of interest rate swaps used to mitigate the
effect of changes in the fair value of fixed-rate long-term financial
instruments due to movements in market interest rates. Changes in the value of
fair value hedges are recorded in Financial Charges and Interest Income and
Other, for interest-rate and foreign exchange hedges, respectively. Any gains or
losses arising from the ineffectiveness are recognized immediately in income in
the same financial category as the underlying transaction.
The Company uses cash flow hedges to reduce its exposure to fluctuations in
interest rates, foreign exchange and changes in commodity prices. The effective
portion of changes in the value of cash flow hedges is recognized in Other
Comprehensive Income. Ineffective portions and amounts excluded from
effectiveness testing of hedges are included in income in the same financial
category as the underlying transaction. Gains or losses from cash flow hedges
that have been included in Accumulated Other Comprehensive Income are included
in Net Income when the underlying transaction has occurred or becomes probable
of not occurring. The maximum length of time the Company is hedging its exposure
to variability in future cash flows is 10 years.
The Company hedges its foreign currency exposure of investments in
self-sustaining foreign operations with certain cross-currency swaps, forward
exchange contracts and options. These financial instruments are adjusted to fair
value and the effective portion of gains or losses associated with these
adjustments are included in Other Comprehensive Income. In addition, the Company
hedges its net investment with certain U.S. dollar-denominated long-term debt,
which is valued at period-end foreign exchange rates. Gains or losses arising
from ineffective portions of the hedge are included in income. Gains or losses
from these hedges that have been included in Accumulated Other Comprehensive
Income are reclassified to Net Income in the event the Company settles or
otherwise reduces its investment.
Comprehensive Income and Equity
The Company's financial statements include a statement of Consolidated
Comprehensive Income. In addition, as required by Section 3251, the Company now
presents separately in its Changes in Consolidated
9
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Shareholders' Equity the changes for each of its components of Shareholders'
Equity. A new component, Accumulated Other Comprehensive Income, has been added
to the Company's Shareholders' Equity as a result of the implementation of this
new standard.
10
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Net Effect of Accounting Policy Changes
The net effect to the Company's financial statements at January 1, 2007
resulting from the above-mentioned changes in accounting policies is as follows.
Increases/(decreases)
(unaudited)
(millions of dollars)
Other current assets (127 )
Other assets (203 )
Accounts payable (29 )
Deferred amounts (75 )
Future income taxes (42 )
Long-term debt (85 )
Long-term debt of joint ventures (7 )
Accumulated other comprehensive loss (186 )
Foreign exchange adjustment 90
Retained earnings 4
Future Accounting Changes
Section 1535 Capital Disclosures
Effective for interim and annual financial statements for fiscal years beginning
on or after October 1, 2007, the new CICA Handbook Section 1535 "Capital
Disclosures" requires the disclosure of qualitative and quantitative information
about the Company's objectives, policies and processes for managing capital.
Section 3862 Financial Instruments - Disclosures and Section 3863 - Financial
Instruments - Presentation
Effective for interim and annual financial statements for fiscal years beginning
on or after October 1, 2007, the new CICA Handbook Sections 3862 and 3863 will
replace Section 3861 to prescribe the requirements for presentation and
disclosure of financial instruments.
11
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3. Segmented Information
Three months ended March 31 Pipelines Energy Corporate Total
(unaudited - millions of dollars) 2007 2006 2007 2006 2007 2006 2007 2006
Revenues 1,124 977 1,125 917 - - 2,249 1,894
Plant operating costs and other (383 ) (317 ) (347 ) (219 ) (2 ) (1 ) (732 ) (537 )
Commodity purchases resold - - (576 ) (505 ) - - (576 ) (505 )
Depreciation (251 ) (226 ) (39 ) (31 ) - - (290 ) (257 )
490 434 163 162 (2 ) (1 ) 651 595
Financial charges and non-controlling (217 ) (192 ) 1 - (51 ) (36 ) (267 ) (228 )
interests
Financial charges of joint ventures (16 ) (14 ) (5 ) (7 ) - - (21 ) (21 )
Income from equity investments 6 18 - - - - 6 18
Interest income and other 7 32 3 2 14 15 24 49
Income taxes (115 ) (121 ) (56 ) (57 ) 41 9 (130 ) (169 )
Income from Continuing Operations 155 157 106 100 2 (13 ) 263 244
Income from Discontinued Operations - 28
Net Income Applicable to Common Shares 263 272
Total Assets
December 31,
(unaudited - millions of dollars) March 31, 2006
2007
Pipelines 23,764 18,320
Energy 6,292 6,500
Corporate 1,043 1,088
31,099 25,908
4. Acquisitions and Dispositions
ANR and Great Lakes
In February 2007, TCPL acquired American Natural Resources Company and ANR
Storage Company (together ANR) and an additional 3.55 per cent interest in Great
Lakes from El Paso Corporation for approximately US$3.4 billion, subject to
certain post-closing adjustments, including US$491 million of assumed long-term
debt. The acquisition was accounted for using the purchase method of accounting.
TCPL began consolidating ANR and Great Lakes, in the Pipelines segment,
subsequent to the acquisition date. The preliminary allocation of the purchase
price was as follows.
Purchase Price Allocation
(unaudited)
(millions of US dollars) ANR Great Total
Lakes
Current assets 260 4 264
Plant, property and equipment 1,871 35 1,906
Other non-current assets 84 - 84
Goodwill 1,759 21 1,780
Current liabilities (169 ) (3 ) (172 )
Long-term debt (475 ) (16 ) (491 )
Other non-current liabilities (441 ) (13 ) (454 )
2,889 28 2,917
A preliminary allocation of the purchase price has been made using fair values
of the net assets at the date of acquisition. As ANR's and Great Lakes' tolls
are subject to rate regulation based on historical costs,
12
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the regulated net assets, other than gas held for sale, were determined to have
a fair value equal to their rate regulated values.
Goodwill will be evaluated on an annual basis for impairment. Factors that
contributed to goodwill included the opportunity to expand in the US market and
gaining a stronger competitive position in the North American gas transmission
business. The goodwill recognized on this transaction is not amortizable for tax
purposes.
PipeLines LP Acquisition of Great Lakes
In February 2007, PipeLines LP acquired a 46.45 per cent interest in Great Lakes
from El Paso Corporation for approximately US$942 million, subject to certain
post-closing adjustments, including US$209 million of assumed long-term debt.
The acquisition was accounted for using the purchase method of accounting. TCPL
began consolidating Great Lakes in the Pipelines segment subsequent to the
acquisition date. The preliminary allocation of the purchase price was as
follows.
Purchase Price Allocation
(unaudited)
(millions of US dollars)
Current assets 42
Plant, property and equipment 465
Other non-current assets 1
Goodwill 457
Current liabilities (23 )
Long-term debt (209 )
733
A preliminary allocation of the purchase price has been made using fair values
of the net assets at the date of acquisition. As Great Lakes' tolls are subject
to rate regulation based on historical costs, the regulated net assets, other
than gas held for sale, were determined to have a fair value equal to their rate
regulated values.
Goodwill will be evaluated on an annual basis for impairment. Factors that
contributed to goodwill included the opportunity to expand in the US market and
gaining a stronger competitive position in the North American gas transmission
business. The goodwill recognized on this transaction is amortizable for tax
purposes.
PipeLines LP
In February 2007, PipeLines LP completed a private placement offering of
17,356,086 common units at a price of US$34.57 per unit, of which 50 per cent of
the units were acquired by TCPL for US$300 million. TCPL also invested an
additional US$12 million to maintain its general partnership ownership interest
in PipeLines LP. As a result of these additional investments in PipeLines LP,
TCPL's ownership in PipeLines LP increased to 32.1 per cent on February 22,
2007. The total private placement plus TCPL's additional investment resulted in
gross proceeds to PipeLines LP of US$612 million, which were used to partially
finance its Great Lakes acquisition.
13
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5. Notes Payable and Long-Term Debt
In March 2007, TCPL filed debt shelf prospectuses in Canada and the U.S.
qualifying for the issuance of $1.5 billion of medium-term notes and US$1.5
billion of debt securities, respectively.
On March 20, 2007, ANR Pipeline Company provided notice to the New York Stock
Exchange of its intention to voluntarily withdraw from listing its 9.625 per
cent Debentures due 2021, 7.375 per cent Debentures due 2024, and 7.0 per cent
Debentures due 2025. Following the delisting, which became effective April 12,
2007, ANR Pipeline Company deregistered these securities from registration with
the U.S. Securities Exchange Commission (SEC).
In February 2007, the Company utilized $1.5 billion and US$700 million of a
US$2.2 billion, one-year bridge facility to partially finance the ANR and Great
Lakes acquisitions. Interest is charged at a floating rate based on London
Interbank Offered Rate (LIBOR). At March 31, 2007, the Company had an
outstanding balance of US$488 million on this facility.
Also in February 2007, the Company, through a wholly owned subsidiary, drew
US$1.0 billion on a newly-established credit facility consisting of a US$700
million five-year term loan and a US$300 million five-year extendible revolving
facility. Interest is charged at a floating rate based on LIBOR. These funds,
together with an additional US$100 million from an existing demand line, were
used to partially finance the ANR and Great Lakes acquisitions, as well as its
additional investment in PipeLines LP. At March 31, 2007, the Company had an
outstanding balance of US$1.0 billion on the credit facility and US$85 million
on the demand line.
On February 22, 2007, PipeLines LP increased the size of its syndicated
revolving credit and term loan facility in connection with its Great Lakes
acquisition. The amount available under the facility increased from US$410
million to US$950 million, consisting of a US$700 million senior term loan and a
US$250 million senior revolving credit facility, with US$194 million of the
senior term loan available being terminated upon closing of the Great Lakes
acquisition Interest was charged at a floating rate based on LIBOR.
6. Share Capital
In February and March 2007, TCPL issued 34,210,526 and 4,515,914 common shares,
respectively, to TransCanada Corporation at a price of $38.00 each. The gross
proceeds of approximately $1.5 billion were used towards financing the
acquisition of ANR and Great Lakes.
14
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7. Financial Instruments and Risk Management
The carrying values of the financial assets and liabilities represented on the
Consolidated Balance Sheet approximate fair values except for long-term debt.
The fair value of long-term debt at March 31, 2007 approximated the reported
amount at December 31, 2006.
The fair values of financial instruments that are included in Other Current
Assets, Other Assets, Accounts Payable and Deferred Amounts at March 31, 2007
are as follows.
Financial Instruments Summary (1) (2)
March 31, 2007
(unaudited) Fair
(millions of dollars) Value
FINANCIAL ASSETS (3)
Held-for-trading (4) (5) 119
Loans and Receivables 236
Available-for-sale (4) 15
Total 370
Hedges (6)
Cash flow hedges 69
Fair value hedges 1
Net investment hedges 73
Total 143
513
FINANCIAL LIABILITIES (7)
Held-for-trading (4) (5) 135
Other financial liabilities 73
Total 208
Hedges (6)
Cash flow hedges 240
448
--------------------
(1) Includes derivatives used in our regulatory operations at their
regulatory values.
(2) Consolidated Net Income for the three months ended March 31,
2007 included $4 million of net losses related to fair value adjustments of
financial assets and liabilities.
(3) At March 31, 2007, Other Current Assets included $20 million of
held-for-trading financial assets and $32 million of cash flow hedges. The
remainder of the financial assets are included in Other Assets.
(4) At December 31, 2006, Other Assets included $103 million and
$14 million of financial instruments that would be classified in 2007 as
held-for-trading and available-for-sale, respectively. Deferred amounts included
$69 million of financial instruments that would be classified in 2007 as
held-for-trading.
(5) Consolidated Net Income for the three months ended March 31,
2007 included $4 million of net losses related to fair value adjustments of
held-for-trading financial instruments.
(6) Consolidated Net Income for the three months ended March 31,
2007 did not include any amounts for the change in fair value of cash flow
hedges and fair value hedges that was ineffective in offsetting the change in
fair value of their related underlyings.
(7) At March 31, 2007, Accounts Payable included $8 million of
held-for-trading financial liabilities and $108 million of cash flow hedges. The
remainder of the financial liablitites are included in Deferred Amounts.
15
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Interest, Foreign Exchange and Energy Risk Management
During the period, the Company had positions in the following types of
derivatives:
Forwards and futures contracts are contractual agreements to buy or sell a
specific financial instrument at a specified price and date in the future. The
Company enters into foreign exchange and commodity forwards and futures to
mitigate volatility in changes in foreign exchange rates and power and gas
prices, respectively.
Swaps are contractual agreements between two parties to exchange movements in
interest or foreign currency rates. The Company enters into interest rate and
cross-currency swaps to mitigate changes in interest rates and foreign exchange,
respectively.
Options are contractual agreements to convey the right, but not the obligation,
for the purchaser either to buy or sell a specific amount of a financial
instrument at a fixed price, either at a fixed date or at any time within a
specified period. The Company enters into option agreements to mitigate changes
in interest rates, foreign exchange and commodity prices.
The Company has long-term debt, interest rate swaps and interest rate options
that have a fixed interest rate and, therefore, are subject to interest rate
price risk. The Company has long-term debt, interest-rate swaps and
interest-rate options, which have a floating interest rate and, therefore, are
subject to interest rate cash flow risk.
The Company calculated the fair value of foreign exchange and interest rate
derivatives using quoted market rates. The fair value of power and natural gas
derivatives was calculated using estimated forward prices for the relevant
period. The changes in fair value for interest rate and foreign exchange
derivatives are included in Financial Charges and Interest Income and Other,
respectively.
The Company executes power, natural gas and heat rate derivatives for overall
management of its asset portfolio. Heat rate contracts are agreements for the
sale or purchase of power that are priced based on a natural gas index. In
accordance with the Company's accounting policy, the fair values of these
derivatives are recorded as financial assets and liabilities.
The Company hedges its net investment in self-sustaining foreign operations with
U.S. dollar-denominated debt, cross-currency swaps, forward foreign exchange
contracts and options. At March 31, 2007, the Company had designated U.S.
dollar-denominated debt with a carrying value of $2,771 million (US$2,403
million) and a fair value of $2,948 million (US$2,557 million) and swaps,
forwards and options with a fair value of $73 million (US$64 million) as net
investment hedges.
Other Risk Management
Currency risk arises when the fair value or future cash flows of a financial
instrument fluctuate due to changes in foreign exchange rates. The Company
manages currency risk through the use of derivatives such as currency swaps,
options and forward foreign exchange contracts.
16
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Market risk is the risk that the fair value of future cash flows of financial
instruments will fluctuate due to changes in market variables such as interest
rates, foreign exchange and commodity prices. In order to manage market risk,
the Company enters into offsetting physical positions and derivative financial
instruments. Liquidity risk is the risk that an entity will encounter difficulty
in meeting obligations associated with financial instruments.
8. Income Taxes
In first quarter 2007, TCPL recorded income tax benefits of approximately $10
million from the resolution of certain income tax matters, as well as a $5
million income tax benefit from an internal restructuring.
9. 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 ended March 31, 2007 is
as follows.
Three months ended March 31 Pension Benefit Other Benefit
Plans Plans
(unaudited - millions of dollars) 2007 2006 2007 2006
Current service cost 11 9 - -
Interest cost 17 17 1 2
Expected return on plan assets (19 ) (18 ) - -
Amortization of transitional obligation related to regulated business - - 1 1
Amortization of net actuarial loss 6 7 1 1
Amortization of past service costs 1 1 - -
Net benefit cost recognized 16 16 3 4
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: Shela Shapiro at (403) 920-2240
Visit TCPL's Internet site at: http://www.transcanada.com
17
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Exhibit 13.3
TRANSCANADA PIPELINES LIMITED
RECONCILIATION TO UNITED STATES GAAP
March 31, 2007
--------------------------------------------------------------------------------
TRANSCANADA PIPELINES LIMITED
RECONCILIATION TO UNITED STATES GAAP
The unaudited consolidated financial statements of TransCanada Pipelines Limited
(TCPL or the Company) for the three months ended March 31, 2007 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
months ended March 31, 2007 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,
2006 and unaudited consolidated financial statements for the three months ended
March 31, 2007 prepared in accordance with Canadian GAAP.
Condensed Statement of Consolidated Income and Other Comprehensive Income in
Accordance with U.S. GAAP(1)
(unaudited) Three months ended
March 31
(millions of dollars except per share amounts) 2007 2006
Revenues 1,894 1,493
Plant operating costs and other 587 430
Commodity purchases resold 522 365
Depreciation 249 223
1,358 1,018
536 475
Other (income)/expenses
Income from equity investments(1) (103 ) (119 )
Other expenses(2) 244 174
Income taxes 129 169
270 224
Income from continuing operations - U.S. GAAP 266 251
Net income from discontinued operations - U.S. GAAP - 28
Net Income in Accordance with U.S. GAAP 266 279
Adjustments affecting comprehensive income under U.S. GAAP
Foreign currency translation adjustment, net of tax (28 ) (4 )
Change in funded status of postretirement plan liability, net of tax(3) 2 -
Change in equity investment funded status of postretirement plan liability, net of tax(3) 9 -
Unrealized (loss)/gain on derivatives, net of tax (9 ) 18
Comprehensive Income in Accordance with U.S. GAAP(4) 240 293
Reconciliation of Income from Continuing Operations
(unaudited) Three months ended
March 31
(millions of dollars) 2007 2006
Net Income from Continuing Operations in Accordance with Canadian GAAP 269 250
U.S. GAAP adjustments
Unrealized gain on energy contracts - 1
Unrealized loss on foreign exchange and interest rate derivatives(5) (4 ) -
Tax impact of loss on foreign exchange and interest rate derivatives 1 -
Income from Continuing Operations in Accordance with U.S. GAAP 266 251
2
--------------------------------------------------------------------------------
Condensed Statement of Consolidated Cash Flows in Accordance with U.S. GAAP(1)
(unaudited) Three months
ended March 31
(millions of dollars) 2007 2006
Cash Generated from Operations(8)
Net cash provided by operating activities 691 494
Investing Activities
Net cash used in investing activities (4,660 ) (264 )
Financing Activities
Net cash provided by/(used in) financing activities 3,934 (69 )
Effect of Foreign Exchange Rate Changes on Cash and Short-Term Investments (3 ) 1
(Decrease)/Increase in Cash and Short-Term Investments (38 ) 162
Cash and Short-Term Investments
Beginning of period 289 83
Cash and Short-Term Investments
End of period 251 245
Condensed Balance Sheet in Accordance with U.S. GAAP(1)
March 31,
2007 December
31,
(millions of dollars) (unaudited) 2006
Current assets 1,714 1,550
Long-term investments(6)(7) 2,784 2,922
Plant, property and equipment 20,514 17,430
Regulatory asset(9) 2,154 2,199
Other assets(6) 4,355 1,720
31,521 25,821
Current liabilities(10) 3,919 2,623
Deferred amounts(7) 1,116 986
Long-term debt 12,948 10,913
Deferred income taxes(9) 3,096 2,734
Preferred securities 530 536
Non-controlling interests 718 366
Shareholders' equity 9,194 7,663
31,521 25,821
3
--------------------------------------------------------------------------------
Statement of Accumulated Other Comprehensive Income in Accordance with U.S. GAAP
(11)
(unaudited) Under-funded Cumulative Minimum Cash Flow Total
(millions of dollars) Postretirement Translation Pension Hedges
Plan Liability Account Liability (SFAS No.
(SFAS No. 158) (SFAS No. 133)
87)
Balance at December 31, 2005 (246 ) (90 ) - (82 ) (418 )
Change in funded status of postretirement 2 - - - 2
plan liability, net of tax of $(1)
Change in equity investment funded status of 9 - - - 9
postretirement plan liability, net of tax of
$(4)
Unrealized loss on derivatives, net of tax of - - - (9 ) (9 )
$6
Foreign currency translation adjustment, net - (28 ) - - (28 )
of tax of $(10)
Balance at March 31, 2007 (235 ) (118 ) - (91 ) (444 )
Balance at December 31, 2005 - (89 ) (77 ) (58 ) (224 )
Unrealized gain on derivatives, net of tax of - - - 18 18
$(10)
Foreign currency translation adjustment, net - (4 ) - - (4 )
of tax of $3
Balance at March 31, 2006 - (93 ) (77 ) (40 ) (210 )
(1) In accordance with U.S. GAAP, the Condensed Statement of
Consolidated Income, Statement of Consolidated Cash Flows, Consolidated Balance
Sheet and Statement of Accumulated Other Comprehensive Income of TCPL are
prepared using the equity method of accounting for joint ventures.
(2) Other expenses include an allowance for funds used during
construction of $3 million for the three months ended March 31, 2007 (March 31,
2006 - $1 million).
(3) Represents the amortization of net loss and prior service cost
amounts previously recorded in accumulated other comprehensive income under
Statement of Financial Accounting Standards No.158 "Employers' Accounting for
Defined Benefit Pension and Other Postretirement Plans" for the Company's
defined benefit pension and other postretirement plans.
(4) For the three months ended March 31, 2007, Comprehensive Income
in Accordance with U.S. GAAP is $3 million higher than under Canadian GAAP. In
addition to the differences between Canadian and U.S. GAAP net income described
in the Reconciliation of Income from Continuing Operations, substantially all of
the difference between Comprehensive Income in Accordance with Canadian and U.S.
GAAP at March 31, 2007 relates to the accounting treatment for defined benefit
pension and other postretirement plans.
4
--------------------------------------------------------------------------------
(5) Represents the amortization of certain hedges that became
ineffective at different times under Canadian and U.S. GAAP.
(6) Under Canadian GAAP, pre-operating costs incurred during the
commissioning phase of a new project are deferred until commercial production
levels are achieved. After such time, those costs are amortized over the
estimated life of the project. Under U.S. GAAP, such costs are expensed as
incurred. Certain start-up costs incurred by Bruce Power L.P. (Bruce B), an
equity investment, were 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 certain pre-operating
costs.
(7) 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
March 31, 2007 was $16 million (March 31, 2006 - $18 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 three months ended March 31, 2007
was nil (March 31, 2006 - nil).
(8) In accordance with U.S. GAAP, all current taxes are included in
cash generated from operations.
(9) Under U.S. GAAP, the Company is required to record a deferred
income tax liability for its cost-of-service regulated businesses. As these
deferred income taxes are recoverable through future revenues, a corresponding
regulatory asset is recorded for U.S. GAAP purposes.
(10) Current liabilities at March 31, 2007 include dividends payable of
$187 million (December 31, 2006 - $162 million) and current taxes payable of
$156 million (December 31, 2006 - $71 million).
(11) At March 31, 2007, Accumulated Other Comprehensive Income in
Accordance with U.S. GAAP is $226 million higher than under Canadian GAAP.
Substantially all of the difference relates to the accounting treatment for
defined benefit pension and other postretirement plans.
Income Taxes
TCPL adopted FASB Interpretation 48, Accounting for Uncertainty in Income Taxes
("FIN 48"), at the beginning of fiscal year 2007. The implementation of the
provisions under FIN 48 as of January 1, 2007 did not have a material impact on
the U.S. GAAP financial statements of the Company and no adjustment to the
beginning balance of retained earnings was required for the adoption of FIN 48.
At the beginning of 2007, TCPL had approximately $80 million of unrecognized tax
benefits that, if recognized, would favorably affect the effective income tax
rate in any future periods. During the first quarter of 2007, TCPL recognized
in income approximately $10 million on the favorable resolution of certain
income tax matters. At March 31, 2007 the total unrecognized tax benefit is
approximately $71 million. Subject to the results of audit examinations by
taxing authorities and legislative amendments, TCPL does not anticipate
adjustments to the unrecognized tax benefits during the next twelve months that
would have a material impact on its financial statements.
TCPL and its subsidiaries are subject to either Canadian federal and provincial
income tax, U.S. federal, state and local income tax or the relevant income tax
in other international jurisdictions. The Company has substantially concluded
all Canadian federal and provincial income tax matters for the years through
2001. Canadian federal income tax returns for years 2002 and 2003 are currently
under examination by the Canada Revenue Agency, which has not proposed any
significant adjustments. Substantially all material U.S. federal income tax
matters have been concluded for years through 2002 and U.S. state and local
income tax matters through 2001.
TCPL's continuing practice is to recognize interest and penalties related to
income tax uncertainties in income tax expense. The Company had $10 million
accrued for interest and nil accrued for penalties at March 31, 2007, and $13
million and nil respectively at December 31, 2006.
5
--------------------------------------------------------------------------------
Other
In February 2006, the U.S. Financial Accounting Standards Board (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. SFAS No. 155 permits fair value remeasurement of any hybrid
instrument that contains an embedded derivative that otherwise would require
bifurcation. TCPL's U.S. GAAP financial statements were not impacted by SFAS
155.
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. 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 did not 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.
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. TCPL is in the process of
assessing the impact of the application of SFAS No. 157 on its U.S. GAAP
financial statements.
In February 2007, FASB issued SFAS No.159 "The Fair Value Option for Financial
Assets and Financial Liabilities - Including an Amendment of FASB Statement No.
115", which allows an entity to choose to measure many financial instruments and
certain other items at fair value for fiscal years beginning on or after
November 15, 2007. TCPL is currently assessing the impact of adopting this
standard on January 1, 2008.
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).
6
--------------------------------------------------------------------------------
(unaudited) Three months
(millions of dollars) ended March 31
2007 2006
Income
Revenues 396 356
Plant operating costs and other (229 ) (174 )
Depreciation (43 ) (40 )
Financial charges and other (21 ) (23 )
Proportionate share of income before income taxes of long-term investments 103 119
(millions of dollars) March 31, December
2007 31,
(unaudited) 2006
Balance Sheet
Current assets 397 446
Plant, property and equipment 3,782 4,177
Other assets 84 198
Current liabilities (383 ) (445 )
Deferred amounts (231 ) (235 )
Long-term debt of joint ventures (928 ) (1,266 )
Deferred income taxes 63 47
Proportionate share of net assets of long-term investments 2,784 2,922
7
--------------------------------------------------------------------------------
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)) and internal controls over financial reporting (as defined in Exchange Act
Rules 13a-15(f) and 15d-15(f)) 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) designed such internal control over financial reporting, or caused
such internal control over financial reporting to be designed under our
supervision, to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting principles;
(c) 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
(d) 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 April 30, 2007
/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)) and internal controls over financial reporting (as defined in Exchange Act
Rules 13a-15(f) and 15d-15(f)) 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) designed such internal control over financial reporting, or caused
such internal control over financial reporting to be designed under our
supervision, to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting principles;
(c) 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
(d) 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 April 30, 2007
/ 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 March 31, 2007 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
April 30, 2007
--------------------------------------------------------------------------------
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 March 31, 2007 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
April 30, 2007
--------------------------------------------------------------------------------
Exhibit 99.1
TransCanada PipeLines Limited
EARNINGS COVERAGE
MARCH 31, 2007
The following financial ratios have been calculated on a consolidated basis for
the respective 12 month period ended March 31, 2007 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:
March 31, 2007
Earnings coverage on long-term debt 2.4 times
Earnings coverage on long-term debt and First Preferred Shares 2.3 times
--------------------------------------------------------------------------------
This information is provided by RNS
The company news service from the London Stock Exchange
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