RNS Number:1541B
TransCanada Pipelines Ld
30 July 2007
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< PERIOD > 06/30/2007
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< NAME > EDGAR Advantage Service Team
< PHONE > (800) 688 - 1933
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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 July 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
Indicate 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
Exhibits 13.1 to 13.3 and 99.1 to this report, furnished on Form 6-K, shall be
incorporated by reference into the following Registration Statement under the
Securities Act of 1933, as amended, of the registrant: Form F-9 (Reg. No.
333-141122).
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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.
Date: July 30, 2007
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
2
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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 June 30, 2007.
13.2 Consolidated comparative interim unaudited financial statements of the registrant for the period ended June
30, 2007 (included in the registrant's Second 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 Second 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 June 30, 2007.
3
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Exhibit 13.1
Management's Discussion and Analysis
The Management's Discussion and Analysis (MD&A) dated July 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
and six months ended June 30, 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 other 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.
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
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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 specific items that are significant and not typical of the
Company's operations. The identification of specific items is subjective and
management uses judgement in determining the items to be excluded in calculating
comparable earnings. Specific 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 Operations 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. A
reconciliation of operating income to net earnings is presented in the Energy
section in this MD&A.
Acquisitions
ANR and Great Lakes
On February 22, 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. 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 issuance of common shares, cash on
hand and funds drawn on loan facilities.
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$945 million, including
US$209 million of assumed long-term debt, subject to certain post-closing
adjustments. The acquisition was financed with debt facilities and a private
placement offering of PipeLines LP units, which included a US$312 million
investment by TCPL.
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Consolidated Results of Operations
Reconciliation of Comparable Earnings to Net Income
(unaudited) Three months ended Six months ended
June 30 June 30
(millions of dollars) 2007 2006 2007 2006
Pipelines
Comparable earnings 166 134 321 273
Specific items:
Bankruptcy settlement with Mirant - - - 18
Gain on sale of Northern Border Partners, L.P. interest - 13 - 13
Net earnings 166 147 321 304
Energy
Comparable earnings 90 74 196 174
Specific item:
Income tax adjustments 4 23 4 23
Net earnings 94 97 200 197
Corporate
Comparable (expenses)/earnings (18 ) (10 ) (31 ) (23 )
Specific item:
Income tax adjustments 12 10 27 10
Net (expenses)/earnings (6 ) - (4 ) (13 )
Net Income Applicable to Common Shares
Continuing operations(1) 254 244 517 488
Discontinued operations - - - 28
Net Income Applicable to Common Shares 254 244 517 516
(1) Comparable Earnings 238 198 486 424
Specific items (net of tax, where applicable):
Income tax adjustments 16 33 31 33
Bankruptcy settlement with Mirant - - - 18
Gain on sale of Northern Border Partners, L.P. interest - 13 - 13
Net Income Applicable To Common Shares from Continuing 254 244 517 488
Operations
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TCPL's net income applicable to common shares and net income applicable to
common shares from continuing operations (net earnings) in second quarter 2007
were $254 million compared to $244 million in second quarter 2006. The
$10-million increase in net earnings in second quarter 2007 compared to 2006 was
primarily due to income from the acquisition of ANR in February 2007, higher
income recorded due to a five-year settlement on the Canadian Mainline approved
by the National Energy Board (NEB) in May 2007 and start-up of the Becancour
cogeneration plant in September 2006. Net income and net earnings for second
quarter 2007 also included positive income tax adjustments of $16 million
resulting from changes in Canadian federal income tax legislation. These
increases were partially offset by a $33-million favourable impact on future
income taxes arising from a reduction in Canadian federal and provincial
corporate income tax rates and a $13-million ($23 million pre-tax) gain on the
sale of TCPL's interest in Northern Border Partners, L.P. that were recorded in
second quarter 2006.
Comparable earnings for second quarter 2007 were $238 million compared to $198
million for the same period in 2006. Comparable earnings excluded the positive
income tax adjustments of $16 million in second quarter 2007. In second quarter
2006, comparable earnings excluded the $33-million favourable impact on future
income taxes arising from a reduction in Canadian federal and provincial
corporate income tax rates and the $13-million ($23 million pre-tax) gain on the
sale of TCPL's interest in Northern Border Partners, L.P.
Net income applicable to common shares was $517 million for the first six months
in 2007 compared to $516 million for the same period last year. Net earnings for
the six months ended June 30, 2007 were $517 million compared to $488 million
for the same period in 2006. The increase in net income applicable to common
shares and net earnings was due to factors discussed above as well as positive
income tax adjustments of $15 million in first quarter 2007, which included the
resolution of certain income tax matters and an internal restructuring. Net
income applicable to common shares and net earnings for the six months ended
June 30, 2006 included an $18-million ($29 million pre-tax) bankruptcy
settlement with Mirant Corporation and certain of its subsidiaries (Mirant).
TCPL's net income applicable to common shares for the six months ended June 30,
2006 also 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.
Comparable earnings for the first six months of 2007 were $486 million compared
to $424 million for the same period in 2006. Comparable earnings for the six
months ended June 30, 2007 excluded positive income tax adjustments of $31
million recorded in the first six months of 2007. In the first six months of
2006, comparable earnings excluded the $33-million favourable impact on future
income taxes, the $18-million ($29 million pre-tax) bankruptcy settlement with
Mirant and the $13-million gain on the sale of TCPL's interest in Northern
Border Partners, L.P.
Results from each business segment for the three and six months ended June 30,
2007 are discussed further in the Pipelines, Energy and Corporate sections of
this MD&A.
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Funds generated from operations of $591 million and $1.2 billion for the three
and six months ended June 30, 2007 increased $52 million and $115 million,
respectively, when compared to the same periods in 2006.
Pipelines
The Pipelines business generated net earnings of $166 million for the three
months ended June 30, 2007 compared to $147 million for the same period in 2006.
Excluding the $13-million gain on the sale of TCPL's interest in Northern Border
Partners, L.P. in second quarter 2006, comparable earnings increased $32 million
in second quarter 2007 compared to the same period in 2006.
Net earnings for the six months ended June 30, 2007 were $321 million compared
to $304 million for the same six months in 2006. Excluding the gain on the sale
of TCPL's interest in Northern Border Partners, L.P. and an $18-million Mirant
settlement in first quarter 2006, comparable earnings increased $48 million.
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Pipelines Results-at-a-Glance
(unaudited) Three months ended Six months ended
June 30 June 30
(millions of dollars) 2007 2006 2007 2006
Wholly Owned Pipelines
Canadian Mainline 75 61 132 120
Alberta System 34 34 65 67
ANR(1) 29 - 50 -
GTN 5 13 16 27
Foothills(2) 8 7 14 14
151 115 277 228
Other Pipelines
Great Lakes(3) 11 11 25 23
Iroquois 3 3 8 7
Portland 1 (2 ) 6 4
PipeLines LP(4) 4 3 6 4
Ventures LP 3 3 6 6
TQM 1 1 3 3
TransGas 5 2 8 5
Gas Pacifico/INNERGY - 3 2 4
Tamazunchale 2 - 5 -
Northern Development (1 ) (1 ) (2 ) (2 )
General, administrative, support costs and other (14 ) (4 ) (23 ) (9 )
15 19 44 45
Comparable earnings 166 134 321 273
Bankruptcy settlement with Mirant - - - 18
Gain on sale of Northern Border Partners, L.P. interest - 13 - 13
Net Earnings 166 147 321 304
--------------------
(1) ANR includes results of operations since February 22, 2007.
(2) Foothills reflects the combined operations of Foothills and the BC System since January 1, 2007. Effective April
1, 2007, Foothills and BC System were integrated.
(3) Great Lakes' results reflect TCPL's 53.55 per cent ownership in Great Lakessince February 22, 2007.
(4) PipeLines LP's results includeTCPL'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 net earnings increased $14 million and $12 million for the
three and six months ended June 30, 2007, respectively, compared to the
corresponding periods in 2006. These increases reflect the impact of a five-year
tolls settlement (the Settlement) with interested stakeholders effective January
1, 2007 to December 31, 2011 on the Canadian Mainline. The Settlement was
approved by the NEB in May 2007, and included an increase in the deemed common
equity ratio from 36 per cent to 40 per cent. As a result of the Settlement,
Canadian Mainline's net earnings for the three months ended June 30, 2007,
compared to the same period in the prior year, increased $12 million as a result
of the higher common equity ratio ($6 million related to first quarter 2007). In
addition, Canadian Mainline's net earnings were positively impacted by certain
performance-based incentive arrangements and operations, maintenance and
administrative (OM&A) cost savings, some of which
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related to first quarter 2007. Partially offsetting these increases were the
negative impacts of a lower rate of return on common equity (ROE) of 8.46 per
cent in 2007 (8.88 per cent in 2006) and a lower average investment base.
Canadian Mainline's net earnings for the six months ended June 30, 2007,
compared to the same period in the prior year, increased $12 million as a result
of the higher common equity ratio, certain performance-based incentive
arrangements and OM&A cost savings under the Settlement, partially offset by a
lower ROE in 2007 and a lower average investment base.
The Alberta System's net earnings were $34 million in second quarter and $65
million for the first six months in 2007, respectively, compared to $34 million
and $67 million for the same periods in 2006. Net earnings in 2007 reflect an
ROE of 8.51 per cent in 2007 compared to an ROE of 8.93 per cent in 2006, on
deemed common equity of 35 per cent.
For the three and six months ended June 30, 2007, ANR's net earnings were $29
million and $50 million, respectively, which are generally in line with the
Company's expectations. 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. Due to the seasonal nature of the business, ANR's volumes,
revenues and net earnings are generally higher in the winter months.
GTN's comparable earnings for the three and six months ended June 30, 2007
decreased $8 million and $11 million, respectively, from the same periods in
2006 primarily due to lower operating revenues as a result of lower volumes
contracted on a long-term firm basis, higher maintenance costs and a higher
provision taken for non-payment of contract transportation revenues from a
subsidiary of Calpine Corporation that filed for bankruptcy protection. Pending
resolution of GTN's current rate case filing, GTN is recording its 2007 revenues
at 2006 rates. As a result, GTN has been recording a provision for rate refund
equal to the difference in transportation revenue based on GTN's interim 2007
rates and the rates that were in effect in 2006.
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Operating Statistics
Gas
Transmission
Canadian Alberta Northwest Foothills
Six months ended Mainline(1) System(2) ANR(3) System(3) System(5)
June 30 (4)
(unaudited) 2007 2006 2007 2006 2007 2007 2006 2007 2006
Average investment
base
($ millions) 7,359 7,454 4,254 4,305 n/a n/a n/a 816 861
Delivery volumes
(Bcf)
Total 1,614 1,534 2,004 2,026 498 371 349 676 656
Average per day 8.9 8.5 11.1 11.2 3.9 2.0 1.9 3.7 3.6
--------------------
(1) Canadian Mainline deliveries originating at the Alberta border and in Saskatchewan for the six months ended
June30, 2007 were 1,110 Bcf (2006 - 1,170 Bcf); average per day was 6.1 Bcf (2006 - 6.5 Bcf).
(2) Field receipt volumes for the Alberta System for the six months ended June30, 2007 were 2,039 Bcf (2006 - 2,070
Bcf); average per day was 11.3 Bcf (2006 - 11.4 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 pipeline operations since February 22, 2007.
(5) Foothills reflects the combined operations of Foothills and the BC System since January 1, 2007. Effective April
1, 2007, Foothills and BC System were integrated.
Other Pipelines
TCPL's proportionate share of comparable earnings from Other Pipelines was $15
million for the three months ended June 30, 2007 compared to $19 million for the
same period in 2006. The decrease was primarily due to higher project
development and support costs as a result of growing the Pipelines business and
decreased earnings from Gas Pacifico/INNERGY in second quarter 2007. These
decreases were partially offset by earnings from Tamazunchale, which commenced
operations in December 2006, and increased earnings from Portland and TransGas.
TCPL's proportionate share of comparable earnings from Other Pipelines for the
six months ended June 30, 2007 were $44 million compared to $45 million in the
corresponding period in 2006. The $1 million decrease in earnings was primarily
due to higher project development and support costs as a result of growing the
Pipelines business, offset by earnings in 2007 from Tamazunchale and higher
earnings from TransGas, Great Lakes, Portland and PipeLines LP in the first six
months of 2007.
As at June 30, 2007, TCPL had advanced $131 million to the Aboriginal Pipeline
Group with respect to the Mackenzie Gas Pipeline Project (MGP) and had
capitalized $65 million related to the Keystone oil pipeline. These amounts were
included in Other Assets.
TCPL and its co-venturers on the MGP continue to pursue the development of the
project, focusing on the regulatory process and discussions with the Canadian
federal government on fiscal framework. Project timing is uncertain and is
conditional upon regulatory and fiscal matters. TCPL's ability to recover its
investment remains dependent on the successful outcome of the project.
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Energy
Energy's net earnings of $94 million in second quarter 2007 decreased $3 million
compared to $97 million in second quarter 2006. Excluding $4 million of income
tax adjustments in second quarter 2007 and $23 million of income tax adjustments
in second quarter 2006, comparable earnings of $90 million increased $16 million
in second quarter 2007.
Energy's net earnings for the six months ended June 30, 2007 of $200 million
increased $3 million compared to $197 million for the same period in 2006.
Excluding the 2007 and 2006 income tax adjustments, comparable earnings for the
six months ended June 30, 2007 increased $22 million.
Energy Results-at-a-Glance
(unaudited) Three months ended Six months ended
June 30 June 30
(millions of dollars) 2007 2006 2007 2006
Bruce Power 31 41 60 104
Western Power Operations 57 46 130 104
Eastern Power Operations 70 43 137 92
Natural Gas Storage 20 17 50 39
General, administrative, support costs and other (39 ) (35 ) (75 ) (65 )
Operating income 139 112 302 274
Financial charges (6 ) (5 ) (10 ) (12 )
Interest income and other 3 1 6 3
Income taxes (46 ) (34 ) (102 ) (91 )
Comparable Earnings 90 74 196 174
Income tax adjustments 4 23 4 23
Net earnings 94 97 200 197
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Bruce Power
Bruce Power Results-at-a-Glance(1)
Three months ended June 30 Six months ended June 30
(unaudited) 2007 2006 2007 2006
Bruce Power (100 per cent basis)
(millions of dollars)
Revenues
Power 450 439 910 918
Other(2) 30 11 50 28
480 450 960 946
Operating expenses
Operations and maintenance (259 ) (226 ) (554 ) (446 )
Fuel (28 ) (22 ) (53 ) (42 )
Supplemental rent (42 ) (42 ) (85 ) (85 )
Depreciation and amortization (36 ) (34 ) (72 ) (65 )
(365 ) (324 ) (764 ) (638 )
Operating Income 115 126 196 308
TCPL's proportionate share 37 39 68 101
Adjustments (6 ) 2 (8 ) 3
TCPL's operating income from
Bruce Power 31 41 60 104
Bruce Power - Other Information
Plant availability
Bruce A 74 % 63 % 82 % 71 %
Bruce B 91 % 94 % 84 % 95 %
Combined Bruce Power 85 % 84 % 83 % 87 %
Sales volumes (GWh)(3)
Bruce A - 100 per cent 2,410 2,070 5,320 4,590
Bruce B - 100 per cent 6,370 6,630 11,800 13,250
Combined Bruce Power - 100 per cent 8,780 8,700 17,120 17,840
TCPL's proportionate share 3,191 3,094 6,320 6,400
Results per MWh(4)
Bruce A power revenues $ 60 $ 59 $ 59 $ 58
Bruce B power revenues $ 48 $ 48 $ 51 $ 49
Combined Bruce Power revenues $ 51 $ 51 $ 53 $ 51
Combined Bruce Power fuel $ 3 $ 2 $ 3 $ 2
Combined Bruce Power operating expenses(5) $ 41 $ 37 $ 44 $ 35
Percentage of output sold to spot market 47 % 39 % 41 % 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 and $17 million for the three and six months ended June
30, 2007, respectively ($5 million and $11 million for the three and six months ended June30, 2006, respectively).
Other income also includes fair value changes of the cash flow hedges that have not been designated for hedge
accounting.
(3) Gigawatt hours.
(4) Megawatt hours.
(5) Net of fuel cost recoveries.
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TCPL's operating income of $31 million from its investment in Bruce Power
decreased $10 million in second quarter 2007 compared to second quarter 2006,
primarily due to higher post-employment benefit and other employee-related
costs, as well as higher costs associated with changes in duration and scope of
planned outages. These impacts were partially offset by higher revenues
resulting from increased generation volumes.
TCPL's share of Bruce Power's generation for second quarter 2007 increased 97
GWh to 3,191 GWh, compared to second quarter 2006 generation of 3,094 GWh, as a
result of fewer planned maintenance outage days in second quarter 2007. Bruce
Power prices achieved during second quarter 2007 and 2006 (excluding other
revenues) were $51 per MWh. Bruce Power's combined operating expenses (net of
fuel cost recoveries) in second quarter 2007 increased to $41 per MWh from $37
per MWh in second quarter 2006 primarily due to higher employee-related and
planned outage costs, discussed above.
Approximately 44 reactor days of planned maintenance outages as well as
approximately 24 reactor days of unplanned outages occurred on the six operating
units in second quarter 2007. In second quarter 2006, Bruce Power experienced
approximately 50 reactor days of planned maintenance outages and 24 reactor days
of unplanned outages. The Bruce Power units ran at a combined average
availability of 85 per cent in second quarter 2007, compared to an 84 per cent
combined average availability in second quarter 2006.
TCPL's operating income from its investment in Bruce Power for the six months
ended June 30, 2007 was $60 million compared to $104 million for the same period
in 2006. The decrease of $44 million was primarily due to higher costs and
lower sales volumes as a result of higher planned outages, as well as higher
post-employment benefit and other employee-related costs. Partially offsetting
these decreases was the impact of higher realized prices.
The overall plant availability percentage in 2007 is expected to be in the low
90s for the four Bruce B units and in the high 70s for the two operating Bruce A
units. Two planned outages were scheduled for Bruce A Unit 3 in 2007, with the
first planned one month outage completed in second quarter 2007 and a second
outage now expected to last approximately one and a half 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. An additional outage on Bruce A Unit 4 is expected to
occur in early fourth quarter 2007 lasting approximately one month.
Income from Bruce B is directly impacted by the fluctuations in wholesale spot
market prices for electricity. Net earnings from both Bruce A and Bruce B units
are 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 second quarter
2007 was sold at a fixed price of $59.69 per MWh (before recovery of fuel costs
from the OPA) compared to $58.63 per MWh for second quarter 2006. In addition,
sales from the Bruce B Units 5 to 8 were subject to a floor price of $46.82 per
MWh in second quarter 2007 and $45.99 per MWh in second quarter 2006. Both of
the Bruce A and Bruce B reference prices are adjusted annually for inflation on
April 1. In first quarter 2007, the Bruce A fixed price was $58.63 per MWh (2006
--------------------------------------------------------------------------------
- $57.37 per MWh) and the Bruce B floor price was $45.99 per MWh (2006 - $45.00
per MWh). Payments received pursuant to the Bruce B floor price mechanism are
subject to a recapture payment dependent on annual spot prices over the term of
the contract. Bruce B net earnings do not include any amounts received under
this floor price 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 4,200 GWh of output for the remainder of 2007 and 6,500
GWh for 2008.
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 June 30, 2007, Bruce A had incurred capital
costs of $1.63 billion with respect to the restart and refurbishment project.
Western Power Operations
Western Power Operations Results-at-a-Glance
(unaudited) Three months ended Six months ended
June 30 June 30
(millions of dollars) 2007 2006 2007 2006
Revenues
Power 221 221 507 496
Other(1) 21 38 49 102
242 259 556 598
Commodity purchases resold
Power (135 ) (150 ) (314 ) (340 )
Other(1) (12 ) (28 ) (35 ) (76 )
(147 ) (178 ) (349 ) (416 )
Plant operating costs and other (34 ) (30 ) (68 ) (68 )
Depreciation (4 ) (5 ) (9 ) (10 )
Operating income 57 46 130 104
--------------------
(1) Other includes Cancarb Thermax and natural gas.
Western Power Operations Sales Volumes
(unaudited) Three months ended Six months ended
June 30 June 30
(GWh) 2007 2006 2007 2006
Supply
Generation 531 438 1,123 1,023
Purchased
Sundance A & B and Sheerness PPAs 2,877 2,846 6,130 6,237
Other purchases 416 519 865 1,005
3,824 3,803 8,118 8,265
Sales
Contracted 3,017 2,811 6,509 5,975
Spot 807 992 1,609 2,290
3,824 3,803 8,118 8,265
Western Power Operations' operating income of $57 million in second quarter 2007
increased $11 million compared to the $46 million earned in second quarter 2006.
This increase was primarily due to increased
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margins from the Alberta power purchase arrangements (PPA) resulting from a
combination of slightly higher realized power prices, increased volumes and
lower PPA costs. Average spot market prices in Alberta decreased seven per cent
to $50 per MWh in second quarter 2007 compared to the same quarter last year.
During second quarter 2007, Western Power Operations reduced its exposure to
lower spot market prices by contracting additional volumes and, as a result,
sold fewer volumes into the spot market. Recontracting at higher prices also
improved overall realized prices in second quarter 2007 compared to the same
period in 2006.
Generation volumes of 531 GWh in second quarter 2007 increased 93 GWh compared
to second quarter 2006 primarily due to the return to service of the Bear Creek
facility in third quarter 2006 and a planned maintenance outage at the MacKay
River facility in second 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 the amount of supply volumes eventually sold into the
spot market 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 21 per cent of power sales volumes were sold into the
spot market in second quarter 2007 compared to 26 per cent in second quarter
2006. To reduce its exposure to spot market prices on uncontracted volumes, as
at June 30, 2007, Western Power Operations had fixed-price power sales contracts
to sell approximately 5,300 GWh for the remainder of 2007 and 7,400 GWh for
2008.
Western Power Operations' operating income for the six months ended June 30,
2007 increased $26 million to $130 million compared to the same period in 2006.
This increase was primarily due to higher overall realized power prices and
lower PPA costs.
--------------------------------------------------------------------------------
Eastern Power Operations
Eastern Power Operations Results-at-a-Glance(1)
(unaudited) Three months ended Six months ended
June 30 June 30
(millions of dollars) 2007 2006 2007 2006
Revenue
Power 389 174 743 335
Other(2) 64 58 147 175
453 232 890 510
Commodity purchases resold
Power (183 ) (89 ) (360 ) (190 )
Other(2) (67 ) (53 ) (125 ) (149 )
(250 ) (142 ) (485 ) (339 )
Plant operating costs and other (120 ) (40 ) (244 ) (65 )
Depreciation (13 ) (7 ) (24 ) (14 )
Operating income 70 43 137 92
--------------------
(1) Eastern Power Operations includes Becancour and Baie-des-Sables effective
September 17, 2006 and November 21, 2006, respectively.
(2) Other includes natural gas.
Eastern Power Operations Sales Volumes(1)
(unaudited) Three months ended Six months ended
June 30 June 30
(GWh) 2007 2006 2007 2006
Supply
Generation 2,028 949 4,051 1,654
Purchased 1,562 667 3,088 1,397
3,590 1,616 7,139 3,051
Sales
Contracted 3,437 1,503 6,794 2,886
Spot 153 113 345 165
3,590 1,616 7,139 3,051
--------------------
(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 $70 million and $137 million for
the three and six months ended June 30, 2007, respectively, increased $27
million and $45 million, compared to the same periods in 2006. The increase was
primarily due to incremental income earned in 2007 from the startup of the 550
MW Becancour cogeneration plant in September 2006, payments received under the
newly designed forward capacity market in New England and margins earned on
incremental volumes sold to new customers.
Generation volumes in second quarter 2007 of 2,028 GWh increased 1,079 GWh
compared to 949 GWh generated in second quarter 2006 primarily due to the
placing into service of the Becancour and Baie-des-Sables facilities.
Eastern Power Operations' power revenues of $389 million increased $215 million
in second quarter 2007, compared to second 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 $183 million and purchased power volumes of 1,562 GWh were
significantly higher in second quarter 2007, compared to second quarter 2006,
primarily due to the impact of increased purchases to supply increased sales
volumes. Plant operating costs and other of $120 million, which includes fuel
gas consumed in generation, increased in second quarter 2007 from the prior year
primarily as a result of the startup of the Becancour facility.
In second quarter 2007, approximately four per cent of power sales volumes were
sold into the spot market compared to approximately seven per cent in second
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
June 30, 2007, Eastern Power Operations had entered into fixed price power sales
contracts to sell approximately 7,200 GWh for the remainder of 2007 and 11,000
GWh for 2008, although certain contracted volumes are dependent on customer
usage levels.
Power Plant Availability
Weighted Average Power Plant Availability(1)
Three months ended Six months ended
June 30 June 30
(unaudited) 2007 2006 2007 2006
Bruce Power 85 % 84 % 83 % 87 %
Western Power Operations(2) 89 % 74 % 94 % 82 %
Eastern Power Operations(3) 93 % 98 % 96 % 97 %
All plants, excluding Bruce Power 91 % 93 % 95 % 93 %
All plants 89 % 85 % 90 % 88 %
--------------------
(1) Plant availability represents the percentage of time in the period that the
plant is available to generate power, whether actually running or not and is
reduced by planned and unplanned outages.
(2) Western Power Operation's plant availability of 74 per cent for the three
months ended June 30, 2006 reflects planned maintenance outages at the MacKay
River, Bear Creek and Carseland cogeneration facilities.
(3) 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 $20 million in second quarter 2007
increased $3 million compared to $17 million in second quarter 2006. Natural Gas
Storage operating income of $50 million for the six months ended June 30, 2007
increased $11 million compared to $39 million for the same period in 2006. These
increases were primarily due to incremental income earned in 2007 from the
startup of the Edson facility in December 2006.
TCPL manages its natural gas storage assets' exposure to seasonal natural gas
price spreads by hedging storage capacity with a portfolio of third party
storage capacity leases and proprietary natural gas purchases and sales.
Earnings from third party storage capacity leases are recognized evenly over the
term of the lease. Earnings for proprietary natural gas
--------------------------------------------------------------------------------
sales, exclusive of unrealized gains or losses from changes in fair value, are
recognized when the natural gas is sold which typically occurs during the winter
withdrawal season.
Effective April 1, 2007, TCPL adopted an accounting policy to record proprietary
natural gas storage inventory at its fair value using the one-month forward
price for natural gas. Changes in fair value of inventory are included in
Revenues.
Back-to-back proprietary transactions are comprised of a forward purchase of
natural gas at lower prices to be injected into storage and a simultaneous
forward sale of natural gas at higher prices for withdrawal at a later period.
By matching purchases and sales volumes, TCPL locks in a margin effectively
eliminating its exposure to the price movements of natural gas. These forward
natural gas contracts, which meet the definition of a derivative, provide highly
effective economic hedges. However, they do not meet the criteria for hedge
accounting due to the Company's active management of these purchases and sales.
As a result, these forward purchase and sale contracts are recorded at their
fair values based on the forward market prices for the contracted month of
delivery. The change in fair value of the purchase and sale contracts is
included in Revenues.
Based on normal market price movements, the recording of natural gas storage
inventory at its fair value is expected to create partially, but not completely,
offsetting impacts to the changes in fair value of the forward contracts. Due to
the locked-in margins on these back-to-back proprietary transactions, the net
changes in fair value reflected in income at period ends may not be indicative
of the operating results of the underlying business. The net change in the fair
values of the proprietary natural gas storage inventory and forward contracts
included in income in second quarter 2007 was not significant.
General, Administrative and Support Costs
General, administrative and support costs of $39 million and $75 million for the
three and six months ended June 30, 2007 increased $4 million and $10 million,
respectively, compared to the same periods in 2006. The increases were primarily
due to higher business development costs associated with growing the Energy
business.
As at June 30, 2007, TCPL had capitalized $35 million related to the Broadwater
liquefied natural gas project.
Corporate
Corporate net expenses for the three months ended June 30, 2007 were $6 million
compared to nil for the same period in 2006. The increase in net expenses was
primarily due to higher financial charges as a result of financing the ANR and
Great Lakes acquisitions. Partially offsetting the increase in net expenses in
second quarter 2007 were gains on derivatives used to manage the Company's
exposure to foreign exchange rate fluctuations and favourable income tax
adjustments of $12 million from changes in Canadian federal income tax
legislation. In second quarter 2006, there was a $10-million favourable impact
on earnings arising from a reduction in Canadian federal and provincial income
tax rates.
--------------------------------------------------------------------------------
Excluding the $12 million and $10 million of income tax adjustments from net
expenses in second quarter 2007 and 2006, respectively, Corporate's comparable
expenses were $18 million and $10 million, respectively.
Net expenses from Corporate for the six months ended June 30, 2007 were $4
million compared to $13 million for the same period in 2006. The $9-million
increase in earnings for the six months ended June 30, 2007 was primarily due to
$27 million of favourable income tax adjustments recorded in the first six
months of 2007 as well as gains on derivatives used to manage the Company's
exposure to foreign exchange rate fluctuations. Partially offsetting these
increases were higher financial charges as a result of the ANR and Great Lakes
acquisitions. Excluding the $27-million income tax adjustments from Corporate's
net earnings for the six months ended June 30, 2007, and the $10-million income
tax adjustments from Corporate's net expenses for the six months ended June 30,
2006 resulted in comparable expenses of $31 million and $23 million for the six
months ended June 30, 2007 and 2006, respectively.
Liquidity and Capital Resources
Funds Generated from Operations
(unaudited) Three months ended Six months ended
June 30 June 30
(millions of dollars) 2007 2006 2007 2006
Cash Flows
Funds generated from operations(1) 591 539 1,170 1,055
Decrease/(increase) in operating working capital 85 (92 ) 126 (93 )
Net cash provided by operations 676 447 1,296 962
--------------------
(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 $229 million and $334 million in the
second quarter and first six months of 2007, respectively, compared to the same
periods in 2006. The increase in net cash provided by operations was primarily
due to an increase in funds generated from operations and a decrease in
operating working capital. Funds generated from operations were $591 million and
$1.2 billion for the three and six months ended June 30, 2007, respectively,
compared to $539 million and $1.1 billion for the same periods 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 six months ended June 30, 2007 were
$4.2 billion (2006 - $358 million) 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$945 million, including
--------------------------------------------------------------------------------
US$209 million of assumed long-term debt. These acquisitions are discussed
further in the Acquisitions section of this MD&A.
Acquisitions for each of the three and six months ended June 30, 2006 were $358
million, which related to the purchase of an additional 20 per cent general
partnership interest in Northern Border Pipeline Company by PipeLines LP.
For the three and six months ended June 30, 2007, capital expenditures totalled
$386 million (2006 - $327 million) and $692 million (2006 - $630 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.
In the three and six months ended June 30, 2006, disposition of assets, net of
current income tax, generated $23 million. The disposition in 2006 related to
the sale of TCPL's 17.5 per cent general partner interest in Northern Border
Partners, L.P.
Financing Activities
TCPL retired $470 million and $795 million of long-term debt in the three and
six months ended June 30, 2007, respectively ($208 million and $348 million for
the three and six months ended June 30, 2006, respectively) and issued $1.2
billion and $2.5 billion of long-term debt and junior subordinated notes for the
three and six months ended June 30, 2007, respectively ($372 million and $1.3
billion for the three and six months ended June 30, 2006, respectively). TCPL's
notes payable decreased $759 million and $257 million in the three and six
months ended June 30, 2007, respectively, compared to an increase of $180
million and a decrease of $453 million for the same periods in 2006,
respectively.
On July 5, 2007, TCPL redeemed, at par, all of the outstanding US$460 million
8.25 per cent Preferred Securities due 2047.
In second quarter 2007, TCPL issued 1.3 million common shares to TransCanada
Corporation (TransCanada) resulting in proceeds of approximately $52 million.
In April 2007, TCPL issued US$1.0 billion of Junior Subordinated Notes ("Notes")
maturing in 2067 and bearing interest of 6.35 per cent until May 15, 2017 at
which time the interest on the Notes will convert to a floating rate reset
quarterly to the three-month London Interbank Offered Rate (LIBOR) plus 221
basis points. The Notes' effective interest rate at June 30, 2007 was 6.51 per
cent. TCPL has the option to defer payment of interest for one or more periods
of up to ten years without giving rise to an event of default and without
permitting acceleration of payment under the terms of the Notes. If this were to
occur, the Company would be prohibited from paying dividends during the deferral
period. The Notes are subordinated in right of payment to existing and future
senior indebtedness and are effectively subordinated to all indebtedness and
obligations of TCPL. The Notes are callable at TCPL's option at any time on or
after May 15, 2017 at 100 per cent of the principal amount of the Notes plus
accrued and unpaid interest to the date of redemption. Upon the occurrence of
certain events, the Notes are callable earlier at TCPL's option, in whole or in
part, at an amount equal to the greater of 100
--------------------------------------------------------------------------------
per cent of the principal amount of the Notes plus accrued and unpaid interest
to the date of redemption or at an amount determined by formula in accordance
with the terms of the Notes.
In April 2007, Northern Border established a US$250-million five-year bank
facility. A portion of the bank facility was drawn to refinance US$150 million
of senior notes that matured on May 1, 2007, with the balance available to fund
Northern Border's ongoing operations.
In March 2007, the Company filed debt shelf prospectuses in Canada and the U.S.
qualifying for issuance of $1.5 billion of medium-term notes and US$1.5 billion
of debt securities, respectively. At June 30, 2007, the Company had issued no
medium-term notes and US$1.0 billion of debt securities under these
prospectuses.
In February 2007, the Company established a US$1.0-billion committed, unsecured
credit facility. A floating interest rate based on the three-month LIBOR plus
22.5 basis points is charged on the balance outstanding and a facility fee of
7.5 basis points is charged on the entire facility. 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. At June 30, 2007, the Company had an outstanding
balance of US$700 million on the credit facility and had repaid the demand line.
In February 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
amount available being terminated upon closing of the Great Lakes acquisition.
At June 30, 2007, US$506 million of the senior term loan and US$10 million of
the senior revolving credit facility remained outstanding. A floating interest
rate based on the three-month LIBOR plus 55 basis points is charged on the
senior term loan and a floating interest rate based on the one-month LIBOR plus
35 basis points is charged on the senior revolving credit facility. A facility
fee of 10 basis points is charged on the US$250 million senior revolving credit
facility. The weighted average interest rate at June 30, 2007 was 5.94 per cent.
Other than the above-mentioned items and those discussed in TCPL's 2006 Annual
Report and First Quarter 2007 Quarterly Report, there have been no material
changes to TCPL's financing activities from December 31, 2006 to June 30, 2007.
Dividends
On July 26, 2007, TCPL's Board of Directors declared a quarterly dividend for
the quarter ending September 30, 2007 in an aggregate amount equal to the
quarterly dividend to be paid on October 31, 2007 by TransCanada on its issued
and outstanding common shares at the close of business on September 28, 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 October
31, 2007. TransCanada reserves the right to alter the discount or return to
purchasing shares on the open market at any time. TCPL's preferred shareholders
may reinvest their dividends to obtain TransCanada common shares.
Changes in Accounting Policies
The Company's Changes in Accounting Policies have not changed materially from
those described in TCPL's 2006 Annual Report and First Quarter 2007 Quarterly
Report MD&A except for the following.
Proprietary Natural Gas Storage Inventories and Revenue Recognition
The new Canadian Institute of Chartered Accountants (CICA) Handbook accounting
requirements for Section 3031 "Inventories" will become effective January 1,
2008. However, the Company has chosen to adopt this standard as of April 1,
2007. Adjustments to second quarter 2007 consolidated financial statements have
been made in accordance with the transitional provisions for this new standard.
Beginning April 1, 2007, TCPL's proprietary natural gas storage inventory will
be valued at its fair value, as measured by the one-month forward price for
natural gas. In order to record inventory at fair value, TCPL has designated its
natural gas storage business as a "broker/trader business" that purchases and
sells natural gas on a back-to-back basis. The Company did not have any
proprietary natural gas inventory prior to April 1, 2007. The Company records
its proprietary natural gas storage results in Revenues net of Commodity
Purchases Resold.
At June 30, 2007, $81 million of proprietary natural gas storage inventory was
included in Inventories on the Consolidated Balance Sheet. All changes in the
fair value of the proprietary natural gas storage inventory will be recorded in
Inventories and Revenues. During the three months ended June 30, 2007,
unrealized pre-tax losses related to the change in fair value of the proprietary
natural gas storage inventory were $23 million, which was essentially offset by
the change in fair value of the forward proprietary natural gas storage purchase
and sale contracts.
Contractual Obligations
As a result of TCPL's acquisition of ANR, Pipelines' future purchase
obligations, primarily consisting of operating lease and purchase obligations,
increased $110 million at June 30, 2007, compared to December 31, 2006.
In July 2007, the Company entered into contracts to purchase pipe and supplies
totaling approximately $300 million for the Keystone oil pipeline and other
Pipeline projects.
Other than the above-mentioned 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 June 30, 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 Instruments and Risk Management
Energy Price, Interest Rate and Foreign Exchange Rate Risk Management
The Company enters into various contracts to mitigate its exposure to
fluctuations in interest rates, foreign exchange rates and commodity prices. The
contracts generally consist of the following.
* Forwards and futures contracts - contractual agreements to
buy or sell a specific financial instrument or commodity 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, cross-currency and commodity swaps to mitigate
changes in interest rates, foreign exchange rates and commodity prices,
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 or commodity 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 rates and commodity prices.
* Heat rate contracts - contracts for the sale or purchase of
power that are priced based on a natural gas index.
Energy Price Risk
The Company is exposed to energy price movements as part of its normal business
operations, particularly in relation to the prices of electricity and natural
gas. The primary risk is that market prices for commodities will move adversely
between the time that purchase and/or sales prices are fixed, potentially
reducing expected margins.
To manage exposure to price risk, subject to the Company's overall risk
management policies and procedures, the Company commits a significant portion of
its supply to medium- to long-term sales contracts while reserving an amount of
unsold supply to maintain flexibility in the overall management of its asset
portfolio. The types of instruments used include forwards and futures contracts,
swaps, options, and heat rate contracts.
TCPL manages its exposure to seasonal gas price spreads in its natural gas
storage business, by hedging storage capacity with a portfolio of third party
storage capacity leases and back-to-back proprietary natural gas purchases and
sales. By matching purchases and sales volumes, TCPL locks in a margin and
effectively eliminates its exposure to the price movements of natural gas.
--------------------------------------------------------------------------------
The Company continually assesses its power contracts and derivative instruments
used to manage energy price risk. Contracts, with the exception of leases, have
been assessed to determine whether they meet the definition of a derivative.
Certain commodity purchase and sale contracts are derivatives but are not within
the scope of the Canadian Institute of Chartered Accountants Handbook Section
3855, as they were entered into and continue to be held for the purpose of
receipt or delivery in accordance with the Company's expected purchase, sale or
usage requirements ("normal purchases and sales exception"), are considered to
be executory contracts or meet other exemption criteria listed in Section 3855.
Interest Rate Risk
The Company has fixed interest rate long-term debt, which subjects the Company
to interest rate price risk, and has floating interest rate long-term debt,
which subjects the Company to interest rate cash flow risk. To manage its
exposure to these risks, the Company uses a combination of interest-rate swaps,
forwards and options.
Investments in Foreign Operations
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 June 30, 2007, the Company had designated U.S.
dollar-denominated debt with a carrying value of $3,585 million (US$3,371
million) and a fair value of $3,659 million (US$3,441 million) as a portion of
this hedge and swaps, forwards and options with a fair value of $75 million
(US$70 million) as net investment hedges.
Net Investment in Foreign Operations
Asset/(Liability)
(millions of dollars) June 30, 2007 December 31, 2006
Notional Notional
or or
Fair Principal Fair Principal
Value(1) Amount Value Amount
(1)
Derivative financial Instruments in hedging relationships
U.S. dollar cross-currency swaps
(maturing 2007 to 2013) 75 U.S. 350 58 U.S. 400
U.S. dollar forward foreign exchange contracts
(maturing 2007) - U.S. 75 (7 ) U.S. 390
U.S. dollar options
(maturing 2007) - U.S. 50 (6 ) U.S. 500
75 U.S. 475 45 U.S. 1,290
--------------------
(1) Fair values are equal to carrying values.
--------------------------------------------------------------------------------
Fair Values
Fair values of financial instruments are determined by reference to quoted bid
or asking price, as appropriate, in active markets. In the absence of an active
market, the Company determines fair value by using valuation techniques that
refer to observable market data or estimated market prices. These include
comparisons with similar instruments where market observable prices exist,
option pricing models and other valuation techniques commonly used by market
participants. Fair values determined using valuation models require the use of
assumptions concerning the amount and timing of estimated future cash flows and
discount rates. In determining those assumptions, the Company looks primarily to
external readily observable market input factors such as interest rate yield
curves, currency rates, and price and rate volatilities as applicable.
Unrealized Gains and Losses
At June 30, 2007, there were unrealized gains from unsettled derivative
financial instruments of $147 million (December 31, 2006 - $41 million) included
in Other Current Assets and $120 million (December 31, 2006 - $39 million)
included in Other Assets. At June 30, 2007, there were unrealized losses from
unsettled derivative financial instruments of $220 million (December 31, 2006 -
$144 million) included in Accounts Payable and $253 million (December 31, 2006 -
$158 million) included in Deferred Amounts. At June 30, 2007, there were
unrealized losses from the fair value adjustments of proprietary natural gas
storage inventory of $23 million (December 31, 2006 - nil) included in
Inventories.
Risk and Risk Management Related to Environmental Regulations
On July 1, 2007, the Government of Alberta's regulations to reduce greenhouse
gas emissions (GHG) by 12 per cent of average 2003 to 2005 levels came into
effect for large industrial emitters in Alberta. Under the new regulations,
entities covered under this legislation will have until March 31, 2008 to
provide compliance reports stating how their facilities have met their reduction
targets. TCPL anticipates that costs associated with GHG reduction targets
impacting the Alberta System are to be recovered through future tolls paid by
customers on the Alberta System. Recovery of GHG compliance costs related to the
Company's power facilities in Alberta is ultimately dependent upon market prices
for electricity. These GHG changes may have an impact on these market prices.
On April 26, 2007, the Canadian government released its Regulatory Framework for
Air Emissions that includes "mandatory and enforceable reductions in emissions
of greenhouse gases and air pollutants". Under this framework, industrial
emitters will be required to reduce GHG intensities in 2010 by 18 percent from
2006 levels and this reduction target will increase by two per cent annually
until 2020. However, many significant implementation and compliance elements of
this framework are still evolving.
TCPL continues to be engaged in policy discussions at all levels with provincial
and federal governments. There are several processes taking place, including
assessment of significant infrastructure requirements, further development of
broad policy elements (for example, domestic offset systems and management of
the federal technology fund) and submission of third party audited compliance
reports. TCPL is following
--------------------------------------------------------------------------------
developments in each of these processes. As these Alberta and Canadian federal
government initiatives have the potential to significantly impact the energy
industry, the Company continues to assess and monitor the implications to TCPL's
businesses.
Other Risks
Additional risks faced by the Company are discussed in the MD&A in TCPL's 2006
Annual Report. TCPL's market, financial and counterparty risks remain
substantially unchanged since December 31, 2006.
Controls and Procedures
As of June 30, 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
Securities Exchange Commission (SEC). Based on that evaluation, the President
and Chief Executive Officer, and Chief Financial Officer concluded that the
design and operation of TCPL's disclosure controls and procedures were effective
as at June 30, 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 acquisitions in 2007, 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 rate-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. For further
information on the Company's accounting policies and estimates refer to the MD&A
in TCPL's 2006 Annual Report and First Quarter 2007 Quarterly Report.
Outlook
Excluding the $31 million of income tax adjustments recorded in 2007 and the
positive impact of the Settlement on the Canadian Mainline, the Company's
outlook is relatively unchanged since the disclosure in TCPL's 2006 Annual
Report. For further information on outlook, refer to the MD&A in TCPL's 2006
Annual Report.
TCPL's issuer rating assigned by Moody's Investors Service (Moody's) is A3 with
a stable outlook. TCPL's senior unsecured debt is rated A, with
--------------------------------------------------------------------------------
a stable outlook, by DBRS; A2, with a stable outlook, by Moody's; and A-, with a
stable outlook, by Standard & Poor's.
Other Recent Developments
Pipelines
Canadian Mainline
In February 2007, TCPL reached a five-year tolls settlement (the Settlement)
with interested stakeholders for the years 2007 to 2011 on the Canadian
Mainline. In March 2007, TCPL applied to the NEB for approval of the
Settlement. In May 2007, the NEB approved the application as filed, including
TCPL's request that interim tolls be made final for 2007. The terms of the
Settlement are effective January 1, 2007 to December 31, 2011.
As part of the Settlement, 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 on July 5, 2007 of the US$460 million 8.25 per cent Preferred
Securities that underpinned the Canadian Mainline's investment base. The
redemption crystallized a foreign exchange gain that will flow through to the
Canadian Mainline's customers.
The Settlement also established the Canadian Mainline's fixed 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
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 Settlement also allows for performance-based incentive arrangements that
will provide mutual benefits to both TCPL and its customers.
Alberta System Expansion
In June 2007, TransCanada made an application to the Alberta Energy and
Utilities Board for approval to construct approximately $300 million of new
facilities on the Alberta System to initially serve the growing demand for
natural gas in the Fort McMurray region of Alberta.
ANR Natural Gas Storage Expansion
In second quarter 2007, ANR received regulatory approval to proceed with a 14
Bcf natural gas storage expansion project in Michigan. This capacity is fully
contracted with an expected in service date of April 1, 2008 for injections and
November 1, 2008 for withdrawals. This project is in addition to a natural gas
storage enhancement and expansion program that will increase Michigan capacity
available for sale by 13 Bcf. This program was also fully subscribed with
injections commencing in April 2007. The expected capital cost of these projects
is US$125 million.
--------------------------------------------------------------------------------
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
liquefied natural gas (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.
An Environmental Impact Report (EIR) and an Environmental Impact Statement (EIS)
have been prepared jointly by the California State Land Commission and the FERC,
respectively, to assess the expansion's effect on the environment. The final
EIR and EIS were completed in June 2007 and the California State Lands
Commission certified the EIR for California's use on July 13, 2007. TCPL expects
that the FERC will issue its final order authorizing the project during third
quarter 2007.
Cacouna Energy Facilities
In July 2007, the NEB approved TCPL's application for a new LNG receipt point at
Gros Cacouna, Quebec, on the integrated Canadian Mainline and that tolls for
service from that point be calculated on a rolled-in basis. The effective date
for these approvals is when the facilities required to connect the Gros Cacouna
receipt point are approved and placed in service. TCPL and TQM are preparing
applications to the NEB for approval to construct those facilities required to
connect the LNG terminal at Gros Cacouna to the existing TQM and Canadian
Mainline infrastructure.
Mackenzie Gas Pipeline Project
In second quarter 2007, the MGP filed additional project update and tolls and
tariff information for the project with the NEB and a Joint Review Panel (JRP)
resulting from increased capital cost estimates for the project. JRP hearings
are scheduled for the third and fourth quarters of 2007 and NEB hearings, if
required, are scheduled for mid-October 2007. TCPL and its co-venturers on the
MGP continue to pursue the development of the project, focusing on the
regulatory process and discussions with the Canadian federal government on
fiscal framework.
Alaska Highway Pipeline Project
TCPL is continuing its discussions with the Alaska North Slope producers. The
Government of Alaska Legislature approved the Alaska Gasline Inducement Act
(AGIA) in May 2007. The Government of Alaska issued a Request for Applications
on July 2, 2007, requesting applications from pipeline developers, under the
AGIA, by October 1, 2007.
Keystone Oil Pipeline
Additional contracts for 155,000 barrels per day have been secured for the
proposed Keystone oil pipeline through an Open Season to transport oil from
Hardisty, Alberta to Cushing, Oklahoma. The contracts will have a duration
averaging 16 years. The Open Season supports an expansion to 590,000 barrels per
day and an extension of the pipeline to Cushing. TCPL has now secured long term
contracts for a total of 495,000 barrels per day with an average duration of 18
years.
--------------------------------------------------------------------------------
An NEB public hearing concluded on June 21, 2007 to determine if the NEB will
approve TCPL's application to construct and operate Keystone's facilities in
Canada. A decision on this application is expected in fourth quarter 2007. TCPL
has also submitted applications for U.S. regulatory approvals at federal and
state levels. Provided that regulatory approvals are received, construction of
the Keystone oil pipeline is expected to begin in 2008 and to be in service in
fourth quarter 2009.
Energy
Cacouna Energy
On June 22, 2007, the Cacouna Energy LNG project received federal approvals
pursuant to the Canadian Environmental Assessment Act. This approval is required
for the issuance of permits under the Fisheries Act (Canada) and Navigable
Waters Protection Act (Canada), which will outline detailed conditions required
for construction. Concurrently, the Government of Quebec granted a decree
approving the Cacouna regassification terminal in Quebec. The conditions are
binding on the Quebec Minister of Environment and subsequent Certificates of
Authorization required for construction.
Share Information
As at June 30, 2007, TCPL had 522,070,549 issued and outstanding common shares
to TransCanada.
Selected Quarterly Consolidated Financial Data(1)
(unaudited) 2007 2006 2005
(millions of dollars except per share Second First Fourth Third Second First Fourth Third
amounts)
Revenues 2,212 2,249 2,091 1,850 1,685 1,894 1,771 1,494
Net Income Applicable to Common Shares
Continuing operations 254 263 268 293 244 244 349 428
Discontinued operations - - - - - 28 - -
254 263 268 293 244 272 349 428
Share Statistics
Net income per share - Basic and
Diluted
Continuing operations $ 0.49 $ 0.50 $ 0.56 $ 0.60 $ 0.51 $ 0.50 $ 0.72 $ 0.89
Discontinued operations - - - - - 0.06 - -
$ 0.49 $ 0.50 $ 0.56 $ 0.60 $ 0.51 $ 0.56 $ 0.72 $ 0.89
--------------------
(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.
* 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' net 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 $50 million on the resolution of certain income tax matters with
taxation authorities and changes in estimates. Energy's net earnings included
earnings from Becancour, which came in service September 17, 2006.
* In fourth quarter 2006, net earnings included $12 million
related to income tax refunds and related interest.
* In first quarter 2007, net earnings included $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.
--------------------------------------------------------------------------------
* In second quarter 2007, net earnings included $16 million
($12 million in Corporate and $4 million in Energy) related to positive income
tax adjustments resulting from changes in Canadian federal income tax
legislation. Pipeline's net earnings increased as a result of a settlement
reached on the Canadian Mainline, which was approved by the NEB in May 2007.
--------------------------------------------------------------------------------
Exhibit 13.2
Consolidated Income
(unaudited) Three months ended Six months ended
June 30 June 30
(millions of dollars) 2007 2006 2007 2006
Revenues 2,212 1,685 4,461 3,579
Operating Expenses
Plant operating costs and other 761 566 1,493 1,103
Commodity purchases resold 527 337 1,103 842
Depreciation 300 266 590 523
1,588 1,169 3,186 2,468
624 516 1,275 1,111
Other Expenses/(Income)
Financial charges 250 207 489 410
Financial charges of joint ventures 19 24 40 45
Income from equity investments (5 ) (6 ) (11 ) (24 )
Interest income and other (24 ) (15 ) (48 ) (64 )
Gain on sale of Northern Border Partners, L.P. interest - (23 ) - (23 )
240 187 470 344
Income from Continuing Operations before Income
Taxes and Non-Controlling Interests 384 329 805 767
Income Taxes
Current 96 37 263 247
Future 14 37 (23 ) (4 )
110 74 240 243
Non-Controlling Interests
Non-controlling interest in PipeLines LP 14 8 31 21
Other 1 (2 ) 6 4
15 6 37 25
Net Income from Continuing Operations 259 249 528 499
Net Income from Discontinued Operations - - - 28
Net Income 259 249 528 527
Preferred Share Dividends 5 5 11 11
Net Income Applicable to Common Shares 254 244 517 516
Net Income Applicable to Common Shares
Continuing operations 254 244 517 488
Discontinued operations - - - 28
254 244 517 516
See accompanying notes to the consolidated financial statements.
--------------------------------------------------------------------------------
Consolidated Cash Flows
(unaudited) Three months ended June 30 Six months ended June 30
(millions of dollars) 2007 2006 2007 2006
Cash Generated From Operations
Net income 259 249 528 527
Depreciation 300 266 590 523
Gain on sale of Northern Border Partners, L.P. - (11 ) - (11 )
interest, net of current income tax
Income from equity investments lower than/(in excess 1 (3 ) (5 ) (7 )
of) distributions received
Future income taxes 14 37 (23 ) (4 )
Non-controlling interests 15 6 37 25
Funding of employee future benefits lower than/(in 3 (13 ) 15 (15 )
excess of) expense
Other (1 ) 8 28 17
591 539 1,170 1,055
Decrease/(increase) in operating working capital 85 (92 ) 126 (93 )
Net cash provided by operations 676 447 1,296 962
Investing Activities
Capital expenditures (386 ) (327 ) (692 ) (630 )
Acquisitions, net of cash acquired (4 ) (358 ) (4,224 ) (358 )
Disposition of assets, net of current income taxes - 23 - 23
Deferred amounts and other (5 ) (6 ) (93 ) (15 )
Net cash used in investing activities (395 ) (668 ) (5,009 ) (980 )
Financing Activities
Dividends on common and preferred shares (187 ) (161 ) (349 ) (316 )
Advances from parent (38 ) 11 718 11
Distributions paid to non-controlling interests (24 ) (10 ) (34 ) (20 )
Notes payable (repaid)/issued, net (759 ) 180 (257 ) (453 )
Long-term debt issued 52 372 1,414 1,250
Reduction of long-term debt (470 ) (208 ) (795 ) (348 )
Long-term debt of joint ventures issued 98 22 110 24
Reduction of long-term debt of joint ventures (107 ) (15 ) (119 ) (21 )
Junior subordinated notes issued 1,107 - 1,107 -
Partnership units of subsidiary issued - - 348 -
Common shares issued 52 - 1,524 -
Net cash (used in)/provided by financing activities (276 ) 191 3,667 127
Effect of Foreign Exchange Rate Changes on Cash and (27 ) (11 ) (30 ) (9 )
Short-Term Investments
(Decrease)/Increase in Cash and Short-Term Investments (22 ) (41 ) (76 ) 100
Cash and Short-Term Investments
Beginning of period 347 353 401 212
Cash and Short-Term Investments
End of period 325 312 325 312
Supplementary Cash Flow Information
Income taxes paid 124 151 211 368
Interest paid 255 218 528 421
See accompanying notes to the consolidated financial statements.
--------------------------------------------------------------------------------
Consolidated Balance Sheet
(unaudited) June December
30, 31,
(millions of dollars) 2007 2006
ASSETS
Current Assets
Cash and short-term investments 325 401
Accounts receivable 983 1,001
Inventories 466 392
Other 187 297
1,961 2,091
Long-Term Investments 69 71
Plant, Property and Equipment 23,700 21,487
Goodwill 2,682 281
Other Assets 1,895 1,978
30,307 25,908
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Notes payable 209 467
Accounts payable 2,419 1,582
Accrued interest 263 264
Current portion of long-term debt 759 616
Current portion of long-term debt of joint ventures 32 142
3,682 3,071
Deferred Amounts 1,143 1,029
Future Income Taxes 1,202 876
Long-Term Debt 11,766 10,887
Long-Term Debt of Joint Ventures 913 1,136
Junior Subordinated Notes 1,050 -
Preferred Securities 489 536
20,245 17,535
Non-Controlling Interests
Non-controlling interest in PipeLines LP 574 287
Other 72 79
646 366
Shareholders' Equity
Preferred shares 389 389
Common shares 6,235 4,712
Contributed surplus 279 277
Retained earnings 2,882 2,719
Accumulated other comprehensive loss (369 ) (90 )
9,416 8,007
30,307 25,908
See accompanying notes to the consolidated financial statements.
--------------------------------------------------------------------------------
Consolidated Comprehensive Income
(unaudited) Three months ended Six months ended
June 30 June 30
(millions of dollars) 2007 2006 2007 2006
Net income 259 249 528 527
Other comprehensive loss, net of tax
Change in foreign currency translation gains and losses on (184 ) (29 ) (221 ) (30 )
investments in foreign operations(1)
Change in gains and losses on hedges of investments in 46 27 55 24
foreign operations(2)
Change in gains and losses on derivative instruments (36 ) - (37 ) -
designated as cash flow hedges(3)
Reclassification to net income of gains and losses on 23 - 20 -
derivative instruments designated as cash flow hedges
pertaining to prior periods(4)
Other comprehensive loss for the period (151 ) (2 ) (183 ) (6 )
Comprehensive income for the period 108 247 345 521
--------------------
(1) Net of tax expense of $51 million and $56 million for the three and six
months ended June 30, 2007 (2006 - $23 million and $22 million expense,
respectively).
(2) Net of tax expense of $23 million and $28 million for the three and six
months ended June 30, 2007 (2006 - $14 million and $12 million expense,
respectively).
(3) Net of tax recovery of $15 million and $10 million for the three and six
months ended June 30, 2007.
(4) Net of tax expense of $7 million and $5 million for the three and six months
ended June 30, 2007.
See accompanying notes to the consolidated financial statements.
--------------------------------------------------------------------------------
Consolidated Shareholders' Equity
Six months ended June 30
(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 1,523 -
Balance at end of period 6,235 4,712
Contributed Surplus
Balance at beginning of period 277 275
Issuance of stock options 2 -
Balance at end of period 279 275
Retained Earnings
Balance at beginning of period 2,719 2,267
Transition adjustment resulting from adopting new financial instruments accounting standards 4
Net income 528 527
Preferred share dividends (11 ) (11 )
Common share dividends (358 ) (312 )
Balance at end of period 2,882 2,471
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 ) -
Other comprehensive loss (183 ) (6 )
Balance at end of period (369 ) (96 )
Total Shareholders' Equity 9,416 7,751
See accompanying notes to the consolidated financial statements.
--------------------------------------------------------------------------------
Accumulated Other Comprehensive Loss
Currency
(unaudited) Translation Cash Flow
(millions of dollars) Adjustment Hedges Total
Balance at December 31, 2006 (90 ) - (90 )
Transition adjustment resulting from adopting new financial instruments - (96 ) (96 )
standards
Change in foreign currency translation gains and losses on investments in (221 ) - (221 )
foreign operations(1)
Change in gains and losses on hedge of investments in foreign operations(2) 55 - 55
Change in gains and losses on derivative instruments designated as cash flow - (37 ) (37 )
hedges(3)
Reclassification to net income of gains and losses on derivative instruments - 20 20
designated as cash flow hedges pertaining to prior periods(4) (5)
Balance at June 30, 2007 (256 ) (113 ) (369 )
Balance at December 31, 2005 (90 ) - (90 )
Change in foreign currency translation gains and losses on investments in (30 ) - (30 )
foreign operations(1)
Change in gains and losses on hedge of investments in foreign operations(2) 24 - 24
Balance at June 30, 2006 (96 ) - (96 )
--------------------
(1) Net of tax expense of $56 million for the six months ended June 30, 2007
(2006 - $22 million expense).
(2) Net of tax expense of $28 million for the six months ended June 30, 2007
(2006 - $12 million expense).
(3) Net of tax recovery of $10 million for the six months ended June 30, 2007.
(4) Net of tax expense of $5 million for the six months ended June 30, 2007.
(5) During the next 12 months, the Company expects to reclassify to net income
an estimated $128 million ($88 million after tax) of net losses reported in
accumulated other comprehensive income for cash flow hedges.
See accompanying notes to the consolidated financial statements.
--------------------------------------------------------------------------------
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 Second Quarter 2007
Proprietary Natural Gas Storage Inventories and Revenue Recognition
The new Canadian Institute of Chartered Accountants (CICA) Handbook accounting
requirements for Section 3031 "Inventories" will become effective January 1,
2008. However, the Company has chosen to adopt this
--------------------------------------------------------------------------------
standard as of April 2007. Adjustments to second quarter 2007 consolidated
financial statements have been made in accordance with the transitional
provisions for this new standard.
Beginning April 1, 2007, TCPL's proprietary natural gas storage inventory will
be valued at its fair value, as measured by the one-month forward price for
natural gas. In order to record inventory at fair value, TCPL has designated its
natural gas storage business as a "broker/trader business" that purchases and
sells natural gas on a back-to-back basis. The Company did not have any
proprietary natural gas inventory prior to April 1, 2007. The Company records
its proprietary natural gas storage results in Revenues net of Commodity
Purchases Resold.
At June 30, 2007, $81 million of proprietary natural gas storage inventory was
included in Inventories on the Consolidated Balance Sheet. All changes in the
fair value of the proprietary natural gas storage inventory will be recorded in
Inventories and Revenues. During the three months ended June 30, 2007,
unrealized pre-tax losses related to the change in fair value of the proprietary
natural gas storage inventory were $23 million, which was essentially offset by
the change in fair value of the forward proprietary natural gas storage purchase
and sale contracts.
Changes for First Quarter 2007
Effective January 1, 2007, the Company adopted the new 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 the consolidated
financial statements for the first six months in 2007 have been made in
accordance with the transitional provisions for these new standards.
Comprehensive Income and Equity
The Company's financial statements include statements of Consolidated
Comprehensive Loss and Accumulated Other Comprehensive Loss. In addition, as
required by Section 3251, the Company now presents separately in its
Consolidated Shareholders' Equity the changes for each of its components of
Shareholders' Equity, including Accumulated Other Comprehensive Loss.
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 consist of swaps, options,
forwards and futures and are entered into with the intention of generating a
profit. These financial instruments are initially accounted for at their fair
value and changes to fair value included in Revenues. 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 June 30, 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 Revenues. All derivatives, other than those that meet
the normal purchases and sales exceptions or are not within the scope of Section
3855, 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
method. Previously, these costs were amortized on a straight-line basis 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 second quarter and the first
six months of 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
Section 3865 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 and the corresponding underlying transactions are recorded in
Financial Charges and Interest Income and Other, for hedges of interest rates
and foreign exchange rates, respectively. Any gains or losses arising from
ineffectiveness are recognized immediately in income in the same financial
category as the underlying transaction.
The Company uses cash flow hedges for its anticipated transactions to reduce
exposure to fluctuations in interest rates, foreign exchange rates 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. 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.
--------------------------------------------------------------------------------
3. Segmented Information
Three months ended June 30 Pipelines Energy Corporate Total
(unaudited - millions of dollars) 2007 2006 2007 2006 2007 2006 2007 2006
Revenues 1,228 969 984 716 - - 2,212 1,685
Plant operating costs and other (417 ) (326 ) (343 ) (236 ) (1 ) (4 ) (761 ) (566 )
Commodity purchases resold (65 ) - (462 ) (337 ) - - (527 ) (337 )
Depreciation (260 ) (235 ) (40 ) (31 ) - - (300 ) (266 )
486 408 139 112 (1 ) (4 ) 624 516
Financial charges and non-controlling (206 ) (184 ) - - (65 ) (34 ) (271 ) (218 )
interests
Financial charges of joint ventures (13 ) (19 ) (6 ) (5 ) - - (19 ) (24 )
Income from equity investments 5 6 - - - - 5 6
Interest income and other 11 2 3 1 11 12 25 15
Gain on sale of Northern Border
Partners, L.P. interest - 23 - - - - - 23
Income taxes (117 ) (89 ) (42 ) (11 ) 49 26 (110 ) (74 )
Income from Continuing Operations 166 147 94 97 (6 ) - 254 244
Income from Discontinued Operations - -
Net Income Applicable to Common Shares 254 244
Six months ended June 30 Pipelines Energy Corporate Total
(unaudited - millions of dollars) 2007 2006 2007 2006 2007 2006 2007 2006
Revenues 2,352 1,946 2,109 1,633 - - 4,461 3,579
Plant operating costs and other (800 ) (643 ) (690 ) (455 ) (3 ) (5 ) (1,493 ) (1,103 )
Commodity purchases resold (65 ) - (1,038 ) (842 ) - - (1,103 ) (842 )
Depreciation (511 ) (461 ) (79 ) (62 ) - - (590 ) (523 )
976 842 302 274 (3 ) (5 ) 1,275 1,111
Financial charges and non-controlling (423 ) (376 ) 1 - (116 ) (70 ) (538 ) (446 )
interests
Financial charges of joint ventures (29 ) (33 ) (11 ) (12 ) - - (40 ) (45 )
Income from equity investments 11 24 - - - - 11 24
Interest income and other 18 34 6 3 25 27 49 64
Gain on sale of Northern Border
Partners, L.P. interest - 23 - - - - - 23
Income taxes (232 ) (210 ) (98 ) (68 ) 90 35 (240 ) (243 )
Income from Continuing Operations 321 304 200 197 (4 ) (13 ) 517 488
Income from Discontinued Operations - 28
Net Income Applicable to Common Shares 517 516
Total Assets
(unaudited - millions of dollars) June 30, December 31,
2007 2006
Pipelines 22,753 18,320
Energy 6,509 6,500
Corporate 1,045 1,088
30,307 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 Lakes Total
Current assets 258 4 262
Plant, property and equipment 1,874 35 1,909
Other non-current assets 82 - 82
Goodwill 1,767 37 1,804
Current liabilities (177 ) (3 ) (180 )
Long-term debt (475 ) (16 ) (491 )
Other non-current liabilities (447 ) (22 ) (469 )
2,882 35 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, 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 U.S. 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$945 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 460
Current liabilities (23 )
Long-term debt (209 )
736
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 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 U.S. 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.
5. Notes Payable and Long-Term Debt
In April 2007, TCPL issued US$1.0 billion of Junior Subordinated Notes ("Notes")
maturing in 2067 and bearing interest of 6.35 per cent until May 15, 2017 at
which time the interest on the Notes will convert to a floating rate, reset
quarterly to the three-month London Interbank Offered Rate (LIBOR) plus 221
basis points. The Notes' effective interest rate at June 30, 2007 was 6.51 per
cent. TCPL has the option to defer payment of interest for one or more periods
of up to ten years without giving rise to an event of default and without
permitting acceleration of payment under the terms of the Notes. If this were to
occur, the Company would be prohibited from paying dividends during the deferral
period. The Notes are subordinated in right of payment to existing and future
senior indebtedness and are effectively subordinated to all indebtedness and
obligations of TCPL. The Notes are callable at TCPL's option at any time on or
after May 15, 2017 at 100 per cent of the principal amount of the Notes plus
accrued and unpaid interest to the date of redemption. Upon the occurrence of
certain events, the Notes are callable earlier at TCPL's option, in whole or in
part, at an amount equal to the greater of 100 per cent of the principal amount
of the Notes plus accrued and unpaid interest to the date of redemption or at an
amount determined by formula in accordance with the terms of the Notes.
In April 2007, Northern Border established a US$250 million five-year bank
facility. A portion of the bank facility was drawn to refinance US$150 - million
of senior notes that matured on May 1, 2007, with the balance available to fund
Northern Border's ongoing operations.
In March 2007, the Company filed debt shelf prospectuses in Canada and the U.S.
qualifying for issuance of $1.5 billion of medium-term notes and US$1.5 billion
of debt securities, respectively. At June 30, 2007, the Company had issued no
medium-term notes and US$1.0 billion of debt securities under these
prospectuses.
In March 2007, ANR Pipeline Company voluntarily withdrew from the New York Stock
Exchange the listing of its 9.625 per cent Debentures due 2021, 7.375 per cent
Debentures due 2024, and 7.0 per cent Debentures due 2025.
--------------------------------------------------------------------------------
With 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 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. A floating interest
rate based on the three-month LIBOR plus 22.5 basis points is charged on the
balance outstanding and a facility fee of 7.5 basis points is charged on the
entire facility. 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. At June
30, 2007, the Company had an outstanding balance of US$700 million on the credit
facility and had repaid the demand line.
In February 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
amount available being terminated upon closing of the Great Lakes acquisition.
At June 30, 2007, US$506 million of the senior term loan and US$10 million of
the senior revolving credit facility remained outstanding. A floating interest
rate based on the three-month LIBOR plus 55 basis points is charged on the
senior term loan and a floating interest rate based on the one-month LIBOR plus
35 basis points is charged on the senior revolving credit facility. A facility
fee of 10 basis points is charged on the US$250 million senior revolving credit
facility. The weighted average interest rate at June 30, 2007 was 5.94 per cent.
6. Preferred Securities
On July 5, 2007, TCPL redeemed, at par, all of the outstanding US$460 million
8.25 per cent Preferred Securities due 2047. The redemption occurred as a result
of a five-year tolls settlement reached on the Canadian Mainline. The redemption
crystallized a foreign exchange gain that will flow through to the Canadian
Mainline's customers.
7. Share Capital
In second quarter 2007, TCPL issued 1.3 million common shares to TransCanada
Corporation (TransCanada) resulting in proceeds of approximately $52 million.
In February and March 2007, TCPL issued 34,210,526 and 4,515,914 common shares,
respectively, to TransCanada 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.
8. Financial Instruments and Risk Management
The fair values of non-derivative financial instruments at June 30, 2007 are as
follows.
Non-Derivative Financial Instruments Summary(1)
(unaudited)
(millions of dollars) June 30,
2007
Fair
Value
Financial Assets(2) (3)
Cash and cash equivalents(4) 340
Loans and receivables(4) 1,142
Available-for-sale assets 13
1,495
Financial Liabilities(3) (5) (6)
Notes payable 728
Trade and other payables 1,187
Long-term debt 14,520
Preferred securities 489
Other long-term liabilities 65
16,989
--------------------
(1) Consolidated Net Income for the three months and six months ended June 30, 2007 included a $2 million unrealized
loss for the fair value adjustments to these financial instruments.
(2) At June 30, 2007, Current Assets on the Consolidated Balance Sheet included financial assets of $932 million in
Accounts Receivable and $340 million in Cash and Cash Equivalents. The remainder of these financial assets were
included in Other Assets.
(3) Carrying value is not materially different from fair value, except for available-for-sale financial assets, which
have a carrying value equal to fair value.
(4) Recorded at cost.
(5) Recorded at amortized cost.
(6) At June 30, 2007, Current Liabilities on the Consolidated Balance Sheet included financial liabilities of $1,178
million in Accounts Payable and $728 million in Notes Payable. Financial liabilities of $74 million were included
in Deferred Amounts, $14,520 million were included in Long-Term Debt and $489 million were included in Preferred
Securities.
The fair values of the Company's derivative financial instruments are as
follows.
Derivative Financial Instruments Summary(1)
(unaudited)
(millions of dollars) June 30,
2007
Fair
Value
Derivative financial instruments held for trading
Power derivatives-assets(2) 38
Power derivatives-liabilities(2) (31 )
Natural gas derivatives-assets(3) 67
Natural gas derivatives-liabilities(3) (34 )
Interest rate derivatives-assets(4) 18
Interest rate derivatives-liabilities(4) (4 )
Foreign exchange derivatives-assets(4) 3
Foreign exchange derivatives-liabilities(4) (67 )
(10 )
Derivative financial instruments in hedging
relationships(5)
Power derivatives-assets(6) 102
Power derivatives-liabilities(6) (269 )
Natural gas derivatives-assets(6) 30
Natural gas derivatives-liabilities(6) (9 )
Interest rate derivatives-assets(7) 9
Interest rate derivatives-liabilities(7) (5 )
Foreign exchange derivatives-assets(7) -
Foreign exchange derivatives-liabilities(7) (54 )
(196 )
Total Derivative Financial Instruments (206 )
(1) Fair value is equal to the carrying value of these derivatives except for
derivatives used in the Company's regulatory operations which are carried at
their regulatory values.
(2) Consolidated Net Income for the three and six months ended June 30, 2007
included a $15 million unrealized loss and a $4 million unrealized gain,
respectively, for the change in the fair value of held-for-trading power
derivatives.
(3) Consolidated Net Income for the three and six months ended June 30, 2007
included $4 million and $10 million, respectively, of unrealized gains for the
change in the fair value of held-for-trading natural gas derivatives.
(4) Consolidated Net Income for the three and six months ended June 30, 2007
included a $6 million unrealized loss and a $1 million unrealized gain,
respectively, for the change in the fair value of held-for-trading interest-rate
and foreign exchange derivatives.
(5) All hedging relationships are designated cash flow hedges except for $4
million of interest-rate derivative financial instruments designated as fair
value hedges.
(6) Consolidated Net Income for the three and six months ended June 30, 2007
included nil and a $6 million gain, respectively, for the changes in fair value
of power and natural gas cash flow hedges that were ineffective in offsetting
the change in fair value of their related underlyings.
(7) Consolidated Net Income for the three and six months ended June 30, 2007
included a $4 million loss for the change in fair value of interest-rate and
foreign exchange cash flow hedges and fair value hedges that were ineffective in
offsetting the change in fair value of their related underlyings.
Unrealized Gains and Losses
At June 30, 2007, there were unrealized gains from unsettled derivative
financial instruments of $147 million (December 31, 2006 - $41 million) included
in Other Current Assets and $120 million (December 31, 2006 - $39 million)
included in Other Assets. At June 30, 2007, there were unrealized losses from
unsettled derivative financial instruments of $220 million (December 31, 2006 -
$144 million) included in Accounts Payable and $253 million (December 31, 2006 -
$158 million) included in Deferred Amounts. At June 30, 2007 there were
unrealized losses from the fair value adjustments of proprietary natural gas
storage inventory of $23 million (December 31, 2006 - nil) included in
Inventories.
Energy Price, Interest Rate and Foreign Exchange Rate Risk Management
The Company enters into various contracts to mitigate its exposure to
fluctuations in interest rates, foreign exchange rates and commodity prices. The
contracts generally consist of the following.
* Forwards and futures contracts - contractual agreements to
buy or sell a specific financial instrument or commodity 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, cross-currency and commodity swaps to mitigate
changes in interest rates, foreign exchange rates and commodity prices,
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 or commodity 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 rates and commodity prices.
* Heat rate contracts - contracts for the sale or purchase of
power that are priced based on a natural gas index.
Energy Price Risk
The Company is exposed to energy price movements as part of its normal business
operations, particularly in relation to the prices of electricity and natural
gas. The primary risk is that market prices for commodities will move adversely
between the time that purchase and/or sales prices are fixed, potentially
reducing expected margins.
To manage exposure to price risk, subject to the Company's overall risk
management policies and procedures, the Company commits a significant portion of
its supply to medium- to long-term sales contracts while reserving an amount of
unsold supply to maintain flexibility in the overall management of its asset
portfolio. The types of instruments used include forwards and futures contracts,
swaps, options, and heat rate contracts.
TCPL manages its exposure to seasonal gas price spreads in its natural gas
storage business, by hedging storage capacity with a portfolio of third party
storage capacity leases and back-to-back proprietary natural gas purchases and
sales. By matching purchases and sales volumes, TCPL locks in a margin and
effectively eliminates its exposure to the price movements of natural gas.
The Company continually assesses its power contracts and derivative instruments
used to manage energy price risk. Contracts, with the exception of leases, have
been assessed to determine whether they meet the definition of a derivative.
Certain commodity purchase and sale contracts are derivatives but are not within
the scope of CICA Handbook Section 3855, as they were entered into and continue
to be held for the purpose of receipt or delivery in accordance with the
Company's expected purchase, sale or usage requirements ("normal purchases and
sales exception"), are considered to be executory contracts or meet other
exemption criteria listed in Section 3855.
Interest Rate Risk
The Company has fixed interest rate long-term debt, which subjects the Company
to interest rate price risk, and has floating interest rate long-term debt,
which subjects the Company to interest rate cash flow risk. To manage its
exposure to these risks, the Company uses a combination of interest-rate swaps,
forwards and options.
Investments in Foreign Operations
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 June 30, 2007, the Company had designated U.S.
dollar-denominated debt with a carrying value of $3,585 million (US$3,371
million) and a fair value of $3,659 million (US$3,441 million) as a portion of
this hedge and swaps, forwards and options with a fair value of $75 million
(US$70 million) as net investment hedges.
Net Investment in Foreign Operations
Asset/(Liability)
(millions of dollars) June 30, 2007 December 31, 2006
Notional Notional
or or
Fair Principal Fair Principal
Value(1) Amount Value(1) Amount
Derivative financial Instruments in hedging relationships
U.S. dollar cross-currency swaps 75 U.S. 350 58 U.S. 400
(maturing 2007 to 2013)
U.S. dollar forward foreign exchange contracts - U.S. 75 (7 ) U.S. 390
(maturing 2007)
U.S. dollar options - U.S. 50 (6 ) U.S. 500
(maturing 2007)
75 U.S. 475 45 U.S. 1,290
--------------------
(1) Fair values are equal to carrying values.
Fair Values
Fair values of financial instruments are determined by reference to quoted bid
or asking price, as appropriate, in active markets. In the absence of an active
market, the Company determines fair value by using valuation techniques that
refer to observable market data or estimated market prices. These include
comparisons with similar instruments where market observable prices exist,
option pricing models and other valuation techniques commonly used by market
participants. Fair values determined using valuation models require the use of
assumptions concerning the amount and timing of estimated future cash flows and
discount rates. In determining those assumptions, the Company looks primarily to
external readily observable market input factors such as interest rate yield
curves, currency rates, and price and rate volatilities as applicable.
9. Income Taxes
In second quarter 2007, TCPL recorded income tax benefits of approximately $16
million as a result of changes in Canadian federal income tax legislation.
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.
10. Employee Future Benefits
The net benefit plan expense for the Company's defined benefit pension plans and
other post-employment benefit plans for the three and six months ended June 30,
2007 is as follows.
Three months ended June 30 Pension Benefit Plans Other Benefit Plans
(unaudited - millions of dollars) 2007 2006 2007 2006
Current service cost 11 9 1 1
Interest cost 18 16 2 2
Expected return on plan assets (20 ) (17 ) (1 ) (1 )
Amortization of net actuarial loss 6 7 - -
Amortization of past service costs 1 1 (1 ) 1
Net benefit cost recognized 16 16 1 3
Six months ended June 30 Pension Benefit Plans Other Benefit Plans
(unaudited - millions of dollars) 2007 2006 2007 2006
Current service cost 22 18 1 1
Interest cost 35 33 3 4
Expected return on plan assets (39 ) (35 ) (1 ) (1 )
Amortization of transitional obligation related to regulated - - 1 1
business
Amortization of net actuarial loss 12 14 1 1
Amortization of past service costs 2 2 (1 ) 1
Net benefit cost recognized 32 32 4 7
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) 920-7859.
Visit TCPL's Internet site at: http://www.transcanada.com
Exhibit 13.3
TRANSCANADA PIPELINES LIMITED
RECONCILIATION TO UNITED STATES GAAP
June 30, 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 and six months ended June 30, 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 and
six months ended June 30, 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 and six
months ended June 30, 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 Six months ended
June 30 June 30
(millions of dollars) 2007 2006 2007 2006
Revenues 1,975 1,322 3,869 2,815
Plant operating costs and other 632 442 1,219 872
Commodity purchases resold 536 267 1,058 632
Depreciation 263 222 512 445
1,431 931 2,789 1,949
544 391 1,080 866
Other (income)/expenses
Income from equity investments (67 ) (99 ) (170 ) (218 )
Other expenses(2) 243 177 487 351
Income taxes 120 70 249 239
296 148 566 372
Income from continuing operations - U.S. GAAP 248 243 514 494
Net income from discontinued operations - U.S. GAAP - - - 28
Net Income in Accordance with U.S. GAAP 248 243 514 522
Adjustments affecting comprehensive income under U.S. GAAP
Foreign currency translation adjustment, net of tax (138 ) (2 ) (166 ) (6 )
Change in funded status of postretirement plan liability, net 1 - 3 -
of tax(3)
Change in equity investment funded status of postretirement 2 - 11 -
plan liability, net of tax(3)
Unrealized (loss)/gain on derivatives, net of tax (13 ) 16 (22 ) 34
Comprehensive Income in Accordance with U.S. GAAP(4) 100 257 340 550
2
Reconciliation of Income from Continuing Operations
(unaudited) Three months ended Six months ended
June 30 June 30
(millions of dollars) 2007 2006 2007 2006
Net Income from Continuing Operations in Accordance with 259 249 528 499
Canadian GAAP
U.S. GAAP adjustments
Unrealized loss on energy contracts(5) - (12 ) - (11 )
Tax impact of unrealized loss on energy contracts - 4 - 4
Equity investment gain(6)(7) - 1 - 1
Unrealized gain/(loss) on foreign exchange and interest rate - 1 (4 ) 1
derivatives(8)
Tax impact of loss on foreign exchange and interest rate - - 1 -
derivatives
Tax recovery due to a change in tax legislation substantively (11 ) - (11 ) -
enacted in Canada(9)
Income from Continuing Operations in Accordance with U.S. 248 243 514 494
GAAP
Condensed Statement of Consolidated Cash Flows in Accordance with U.S. GAAP(1)
(unaudited) Three months ended Six months ended
June 30 June 30
(millions of dollars) 2007 2006 2007 2006
Cash Generated from Operations(10)
Net cash provided by operating activities 541 469 1,232 963
Investing Activities
Net cash used in investing activities (301 ) (675 ) (4,961 ) (945 )
Financing Activities
Net cash provided by/(used in) financing activities (265 ) 178 3,669 115
Effect of Foreign Exchange Rate Changes on Cash and (22 ) (8 ) (25 ) (7 )
Short-Term Investments
(Decrease)/Increase in Cash and Short-Term Investments (47 ) (36 ) (85 ) 126
Cash and Short-Term Investments
Beginning of period 251 245 289 83
Cash and Short-Term Investments
End of period 204 209 204 209
3
Condensed Balance Sheet in Accordance with U.S. GAAP(1)
June
(millions of dollars) 30, 2007 December
(unaudited) 31, 2006
Current assets 1,570 1,550
Long-term investments(6)(7) 2,964 2,922
Plant, property and equipment 19,935 17,430
Regulatory asset(11) 2,103 2,199
Other assets(6)(12) 4,236 1,720
30,808 25,821
Current liabilities(9)(13) 3,427 2,623
Deferred amounts(7) 1,149 986
Long-term debt and junior subordinated notes(12) 12,894 10,913
Deferred income taxes(6)(8)(11) 3,037 2,734
Preferred securities 489 536
Non-controlling interests 646 366
Shareholders' equity 9,166 7,663
30,808 25,821
Statement of Accumulated Other Comprehensive Income in Accordance with U.S. GAAP
(1)(14)
(unaudited) Under-funded Cumulative Minimum Cash Flow Total
(millions of dollars) Postretirement Translation Pension Hedges
Account Liability (SFAS No.
Plan Liability (SFAS No. 87) 133)
(SFAS No. 158)
Balance at December 31, 2006 (246 ) (90 ) - (82 ) (418 )
Foreign currency translation - (166 ) - - (166 )
adjustment, net of tax of $(84)
Change in funded status of 3 - - - 3
postretirement plan liability,
net of tax of $2
Change in equity investment 11 - - - 11
funded status of postretirement
plan liability, net of tax of
$6
Unrealized loss on derivatives, - - - (22 ) (22 )
net of tax of $(14)
Balance at June 30, 2007 (232 ) (256 ) - (104 ) (592 )
Balance at December 31, 2005 - (89 ) (77 ) (58 ) (224 )
Foreign currency translation - (6 ) - - (6 )
adjustment, net of tax of $(34)
Unrealized gain on derivatives, - - - 34 34
net of tax of $(15)
Balance at June 30, 2006 - (95 ) (77 ) (24 ) (196 )
--------------------
(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 $7 million for the six months ended June 30, 2007 (June 30, 2006
- $3 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
4
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 six months ended June 30, 2007, Comprehensive Income
in Accordance with U.S. GAAP is $5 million lower 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 prepared in Accordance with Canadian
and U.S. GAAP for the six months ended June 30, 2007 relates to the accounting
treatments for defined benefit pension and other postretirement plans.
(5) Substantially all of the amounts recorded in the six months
ended June 30, 2006 as differences between U.S. and Canadian GAAP in respect of
energy contracts relate to gains and losses on derivative energy contracts for
periods before they were documented as hedges for purposes of U.S. GAAP and to
differences in accounting with respect to physical energy contracts.
(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 costs incurred by Bruce Power, 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 Power, 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 June
30, 2007 was $16 million (June 30, 2006 - $17 million) and primarily relates to
the Company's equity interest in Bruce Power. The net income impact with
respect to the guarantees for the six months ended June 30, 2007 was nil (June
30, 2006 - $1 million).
(8) Represents the amortization of certain hedges that became
ineffective at different times under Canadian and U.S. GAAP.
(9) In accordance with Canadian GAAP, the Company recorded income
tax benefits resulting from substantively enacted Canadian federal income tax
legislation. Under US GAAP, the legislation must be fully enacted for income
tax adjustments to be recorded.
(10) In accordance with U.S. GAAP, all current taxes are included in
cash generated from operations.
(11) In accordance with U.S. GAAP, the Company is required to record
a deferred income tax liability for its cost-of-service regulated businesses
that is not required under Canadian GAAP. As these deferred income taxes are
recoverable through future revenues, a corresponding regulatory asset is
recorded for U.S. GAAP purposes.
(12) In accordance with U.S. GAAP, debt issue costs are recorded as a
deferred asset rather than being included in long-term debt as required by
Canadian GAAP.
(13) Current liabilities at June 30, 2007 include dividends payable
of $187 million (December 31, 2006 - $162 million) and current taxes payable of
$173 million (December 31, 2006 - $71 million).
(14) At June 30, 2007, Accumulated Other Comprehensive Income in
Accordance with U.S. GAAP is $223 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 favourably
5
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
favourable resolution of certain income tax matters. During the second quarter
of 2007, there were no significant adjustments related to income tax matters.
At June 30, 2007, the total unrecognized tax benefit is approximately $71
million.
TCPL expects the enactment of certain Canadian Federal tax legislation in the
next twelve months. This legislation will result in a favourable income tax
adjustment of approximately $11 million. Otherwise, subject to the results of
audit examinations by taxing authorities and other legislative amendments, TCPL
does not anticipate further 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 $11 million
accrued for interest and nil accrued for penalties at June 30, 2007, and $13
million and nil, respectively, at December 31, 2006.
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 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 currently assessing
the impact of adopting this standard on January 1, 2008.
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.
6
Summarized Financial Information of Long-Term Investments
The following summarized financial information of long-term investments includes
those investments that are accounted for by the equity method under U.S. GAAP
(including those that are accounted for by the proportionate consolidation
method under Canadian GAAP).
Three months ended Six months ended
June 30 June 30
(millions of dollars) 2007 2006 2007 2006
Income
Revenues 340 348 736 704
Plant operating costs and other (217 ) (176 ) (446 ) (350 )
Depreciation (39 ) (47 ) (82 ) (87 )
Financial charges and other (17 ) (26 ) (38 ) (49 )
Proportionate share of income before income taxes of 67 99 170 218
long-term investments
(millions of dollars) June 30, December 31,
2007 2006
(unaudited)
Balance Sheet
Current assets 417 446
Plant, property and equipment 3,872 4,177
Other assets 70 198
Current liabilities (271 ) (445 )
Deferred amounts (227 ) (235 )
Long-term debt of joint ventures (959 ) (1,266 )
Deferred income taxes 62 47
Proportionate share of net assets of long-term investments 2,964 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.
/s/ Harold N. Kvisle
Dated July 30, 2007 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.
/ s / Gregory A. Lohnes
Dated July 30, 2007 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 June 30, 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
July 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 June 30, 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
July 30, 2007
Exhibit 99.1
TransCanada PipeLines Limited
EARNINGS COVERAGE
JUNE 30, 2007
The following financial ratios have been calculated on a consolidated basis for
the respective 12 month period ended June 30, 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:
June 30,
2007
Earnings coverage on long-term debt 2.6 times
Earnings coverage on long-term debt and First Preferred Shares 2.5 times
This information is provided by RNS
The company news service from the London Stock Exchange
END
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