SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
6-K
Report of
Foreign Private Issuer
Pursuant
to Rule 13a-16 or 15d-16 of
the
Securities Exchange Act of 1934
For the
month of November 2009
Commission
File No. 1-31690
TransCanada
Corporation
(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 ¨ Form
40-F þ
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): ¨
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): ¨
Exhibits
13.1 to 13.3 to this report, furnished on Form 6-K, shall be incorporated by
reference into each of the Registration Statements under the Securities Act of
1933, as amended, of the registrant: Form S-8 (File Nos. 333-5916, 333-8470,
333-9130 and 333-151736), Form F-3 (File Nos. 33-13564 and 333-6132) and Form
F-10 (File No. 333-161929).
Exhibit
99.1 to this report, furnished on Form 6-K, is furnished, not filed, and will
not be incorporated by reference into any registration statement filed by the
registrant under the Securities Act of 1933, as amended.
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.
Dated:
November 4, 2009
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TRANSCANADA
CORPORATION
|
||
|
By:
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/s/ Gregory A. Lohnes | |
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Gregory
A. Lohnes
|
||
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Executive
Vice-President and
|
||
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Chief
Financial Officer
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||
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By:
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/s/ G. Glenn Menuz | |
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G.
Glenn Menuz
|
||
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Vice-President
and Controller
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||
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EXHIBIT
INDEX
|
|
13.1
|
Management’s
Discussion and Analysis of Financial Condition and Results of Operations
of the registrant as at and for the period ended September 30,
2009.
|
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13.2
|
Consolidated
comparative interim unaudited financial statements of the registrant for
the period ended September 30, 2009 (included in the registrant's Third
Quarter 2009 Quarterly Report to Shareholders).
|
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13.3
|
U.S.
GAAP reconciliation of the consolidated comparative interim unaudited
financial statements of the registrant contained in the registrant's Third
Quarter 2009 Quarterly Report to Shareholders.
|
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31.1
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Certification
of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002.
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31.2
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Certification
of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002.
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32.1
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Certification
of Chief Executive Officer regarding Periodic Report containing Financial
Statements.
|
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32.2
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Certification
of Chief Financial Officer regarding Periodic Report containing Financial
Statements.
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99.1
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A
copy of the registrant’s news release of November 4, 2009.
|
EXHIBIT
13.1
TRANSCANADA
CORPORATION – THIRD QUARTER 2009
Quarterly Report to
Shareholders
Management's
Discussion and Analysis
Management's
Discussion and Analysis (MD&A) dated November 3, 2009 should be read in
conjunction with the accompanying unaudited Consolidated Financial Statements of
TransCanada Corporation (TransCanada or the Company) for the three and nine
months ended September 30, 2009. It should also be read in
conjunction with the audited Consolidated Financial Statements and notes
thereto, and the MD&A contained in TransCanada's 2008 Annual Report for the
year ended December 31, 2008. Additional information relating to TransCanada,
including the Company's Annual Information Form and other continuous disclosure
documents, is available on SEDAR at www.sedar.com under TransCanada Corporation.
Unless otherwise indicated, "TransCanada" or "the Company" includes TransCanada
Corporation and its subsidiaries. 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 TransCanada’s 2008 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",
"believe", "may", "should", "estimate", "project", "outlook", "forecast" or
other similar words are used to identify such forward looking
information. Forward-looking statements in this document are intended
to provide TransCanada securityholders and potential investors with information
regarding TransCanada and its subsidiaries, including management’s assessment of
TransCanada’s and its subsidiaries’ future financial and operational plans and
outlook. Forward-looking statements in this document may include,
among others, statements regarding the anticipated business prospects and
financial performance of TransCanada and its subsidiaries, expectations or
projections about the future, strategies and goals for growth and expansion,
expected and future cash flows, costs, schedules, operating and financial
results and expected impact of future commitments and contingent
liabilities. All forward-looking statements reflect TransCanada's
beliefs and assumptions based on information available at the time the
statements were made. Actual results or events may differ from those predicted
in these forward-looking statements. Factors that could cause actual results or
events to differ materially from current expectations include, among other
things, the ability of TransCanada to successfully implement its strategic
initiatives and whether such strategic initiatives will yield the expected
benefits, the operating performance of the Company's pipeline and energy assets,
the availability and price of energy commodities, capacity payments, regulatory
processes and decisions, changes in environmental and other laws and
regulations, competitive factors in the pipeline and energy industry sectors,
construction and completion of capital projects, labour, equipment and material
costs, access to capital markets, interest and currency exchange rates,
technological developments and the current economic conditions in North America.
By its nature, forward-looking information is subject to various risks and
uncertainties, which could cause TransCanada's actual results and experience to
differ materially from the anticipated results or expectations expressed.
Additional information on these and other factors is available in the reports
filed by TransCanada with Canadian securities regulators and with the U.S.
Securities and Exchange Commission ("SEC"). Readers are cautioned to not place
undue reliance on this forward-looking information, which is given as of the
date it is expressed in this quarterly report or otherwise, and to not use
future-oriented information or financial outlooks for anything other
than their intended purpose. TransCanada 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.
THIRD
QUARTER REPORT 2009 - TRANSCANADA [2
Non-GAAP
Measures
TransCanada
uses the measures "comparable earnings", "comparable earnings per common share",
"earnings before interest, taxes, depreciation and amortization" (EBITDA),
"comparable EBITDA", "earnings before interest and taxes" (EBIT), "comparable
EBIT" and "funds generated from operations" in this MD&A. These measures do
not have any standardized meaning prescribed by Canadian generally accepted
accounting principles (GAAP). They are, therefore, considered to be non-GAAP
measures and may not be comparable to similar measures presented by other
entities. Management of TransCanada uses these non-GAAP measures to improve its
ability to compare financial results among reporting periods and to enhance its
understanding of operating performance, liquidity and ability to generate funds
to finance operations. These non-GAAP measures are also provided to readers as
additional information on TransCanada’s operating performance, liquidity and
ability to generate funds to finance operations.
EBITDA is
an approximate measure of the Company’s pre-tax operating cash flow. EBITDA
comprises earnings before deducting interest and other financial charges, income
taxes, depreciation and amortization, and non-controlling interests. EBIT is a
measure of the Company’s earnings from ongoing operations. EBIT comprises
earnings before deducting interest and other financial charges, income taxes and
non-controlling interests.
Management
uses the measures of comparable earnings, EBITDA and EBIT to better evaluate
trends in the Company’s underlying operations. Comparable earnings, comparable
EBITDA and comparable EBIT comprise net income, EBITDA and EBIT, respectively,
adjusted for specific items that are significant, but are not reflective of the
Company’s underlying operations in the period. Specific items are subjective,
however, management uses its judgement and informed decision-making when
identifying items to be excluded in calculating comparable earnings, comparable
EBITDA and comparable EBIT, some of which may recur. Specific items may include
but are not limited to certain income tax refunds and adjustments, gains or
losses on sales of assets, legal and bankruptcy settlements, and certain fair
value adjustments. The table in the "Consolidated Results of Operations" section
of this MD&A presents a reconciliation of comparable earnings, comparable
EBITDA, comparable EBIT and EBIT to Net Income. Comparable earnings per common
share is calculated by dividing comparable earnings by the weighted average
number of common shares outstanding for the period.
Funds
generated from operations comprises 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 of this MD&A.
Financial Information
Presentation
Effective
January 1, 2009, TransCanada revised the information presented in the tables of
this MD&A to better reflect the operating and financing structure of the
Company. The Pipelines and Energy results summaries are presented geographically
by separating the Canadian and U.S. portions of each segment. The Company
believes this new format more clearly describes the financial performance of its
business units. The new format presents EBITDA and EBIT as the Company believes
these measures provide increased transparency and more useful information with
respect to the performance of the Company’s individual assets. Segmented
information has been retroactively reclassified to reflect these changes. These
changes had no impact on reported consolidated Net Income.
THIRD
QUARTER REPORT 2009 - TRANSCANADA [3
Consolidated
Results of Operations
Reconciliation
of Comparable Earnings, Comparable EBITDA, Comparable EBIT and EBIT to Net
Income
|
For
the three months ended September 30
|
||||||||||||||||||||||||||||||||
|
(unaudited)(millions
of dollars except per
|
Pipelines
|
Energy
|
Corporate
|
Total
|
||||||||||||||||||||||||||||
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share
amounts)
|
2009
|
2008
|
2009
|
2008
|
2009
|
2008
|
2009
|
2008
|
||||||||||||||||||||||||
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Comparable EBITDA(1)
|
730 | 723 | 292 | 366 | (28 | ) | (23 | ) | 994 | 1,066 | ||||||||||||||||||||||
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Depreciation
and amortization
|
(255 | ) | (254 | ) | (88 | ) | (64 | ) | - | - | (343 | ) | (318 | ) | ||||||||||||||||||
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Comparable EBIT(1)
|
475 | 469 | 204 | 302 | (28 | ) | (23 | ) | 651 | 748 | ||||||||||||||||||||||
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Specific
item:
|
||||||||||||||||||||||||||||||||
|
Fair value adjustments of
natural gas
inventory and forward
contracts
|
- | - | 14 | (2 | ) | - | - | 14 | (2 | ) | ||||||||||||||||||||||
|
EBIT(1)
|
475 | 469 | 218 | 300 | (28 | ) | (23 | ) | 665 | 746 | ||||||||||||||||||||||
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Interest
expense
|
(216 | ) | (213 | ) | ||||||||||||||||||||||||||||
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Financial
charges of joint ventures
|
(17 | ) | (18 | ) | ||||||||||||||||||||||||||||
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Interest
income and other
|
43 | 22 | ||||||||||||||||||||||||||||||
|
Income
taxes
|
(107 | ) | (129 | ) | ||||||||||||||||||||||||||||
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Non-controlling
interests
|
(23 | ) | (18 | ) | ||||||||||||||||||||||||||||
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Net
Income
|
345 | 390 | ||||||||||||||||||||||||||||||
|
Specific
items (net of tax, where applicable):
|
||||||||||||||||||||||||||||||||
|
Fair value adjustments of
natural gas inventory and forward contracts
|
(10
|
) |
2
|
|||||||||||||||||||||||||||||
| Income tax reassessments and adjustments | - | (26 | ) | |||||||||||||||||||||||||||||
|
Comparable Earnings(1)
|
335 | 366 | ||||||||||||||||||||||||||||||
|
Net Income Per Common Share -
Basic and Diluted(2)
|
$ | 0.50 | $ | 0.67 | ||||||||||||||||||||||||||||
|
(1)
|
Refer
to the Non-GAAP Measures section in this MD&A for further discussion
of comparable EBITDA, comparable EBIT, EBIT, comparable earnings and
comparable earnings per common
share.
|
| (2) |
For
the three months ended September 30
|
||||||||
|
(unaudited)
|
2009 | 2008 | |||||||
|
Net
Income Per Common Share
|
$ | 0.50 | $ | 0.67 | |||||
|
Specific items (net of tax,
where applicable):
|
|||||||||
|
Fair value adjustments of
natural gas inventory and forward contracts
|
(0.01 | ) | - | ||||||
| Income tax reassessment and adjustments | - | (0.04 | ) | ||||||
|
Comparable Earnings Per Common
Share(1)
|
$ | 0.49 | $ | 0.63 | |||||
THIRD
QUARTER REPORT 2009 - TRANSCANADA [4
|
For
the nine months ended September 30
|
|||||||||||||||||||||||||||||||
|
(unaudited)(millions
of dollars except
|
Pipelines
|
Energy
|
Corporate
|
Total
|
|||||||||||||||||||||||||||
|
per
share amounts)
|
2009
|
2008
|
2009
|
2008
|
2009
|
2008
|
2009
|
2008 | |||||||||||||||||||||||
|
Comparable EBITDA(1)
|
2,348 | 2,239 | 883 | 913 | (89 | ) | (71 | ) | 3,142 | 3,081 | |||||||||||||||||||||
|
Depreciation
and amortization
|
(773 | ) | (765 | ) | (261 | ) | (178 | ) | - | - | (1,034 | ) | (943 | ) | |||||||||||||||||
|
Comparable EBIT(1)
|
1,575 | 1,474 | 622 | 735 | (89 | ) | (71 | ) | 2,108 | 2,138 | |||||||||||||||||||||
|
Specific
items:
|
|||||||||||||||||||||||||||||||
|
Fair value adjustments of
natural
gas inventory and forward contracts
|
- | - | (6 | ) | (7 | ) | - | - | (6 | ) | (7 | ) | |||||||||||||||||||
|
Calpine bankruptcy
settlements
|
- | 279 | - | - | - | - | - | 279 | |||||||||||||||||||||||
|
GTN lawsuit
settlement
|
- | 17 | - | - | - | - | - | 17 | |||||||||||||||||||||||
|
Writedown of Broadwater
LNG
project costs
|
- | - | - | (41 | ) | - | - | - | (41 | ) | |||||||||||||||||||||
|
EBIT(1)
|
1,575 | 1,770 | 616 | 687 | (89 | ) | (71 | ) | 2,102 | 2,386 | |||||||||||||||||||||
|
Interest
expense
|
(770 | ) | (617 | ) | |||||||||||||||||||||||||||
|
Financial
charges of joint ventures
|
(47 | ) | (51 | ) | |||||||||||||||||||||||||||
|
Interest
income and other
|
99 | 58 | |||||||||||||||||||||||||||||
|
Income
taxes
|
(320 | ) | (507 | ) | |||||||||||||||||||||||||||
|
Non-controlling
interests
|
(71 | ) | (106 | ) | |||||||||||||||||||||||||||
|
Net
Income
|
993 | 1,163 | |||||||||||||||||||||||||||||
|
Specific
items (net of tax, where applicable):
|
|||||||||||||||||||||||||||||||
|
Fair value adjustments of
natural gas inventory and forward contracts
|
4 | 6 | |||||||||||||||||||||||||||||
|
Calpine bankruptcy settlements
|
- | (152 | ) | ||||||||||||||||||||||||||||
|
GTN lawsuit settlement
|
- | (10 | ) | ||||||||||||||||||||||||||||
|
Writedown of Broadwater LNG project costs
|
- | 27 | |||||||||||||||||||||||||||||
|
Income
tax reassessments and adjustments
|
- | (26 | ) | ||||||||||||||||||||||||||||
|
Comparable Earnings(1)
|
997 | 1,008 | |||||||||||||||||||||||||||||
|
Net Income Per Common Share -
Basic and Diluted(2)
|
$ | 1.55 | $ | 2.07 | |||||||||||||||||||||||||||
|
(1)
|
Refer
to the Non-GAAP Measures section in this MD&A for further discussion
of comparable EBITDA, comparable EBIT, EBIT, comparable earnings and
comparable earnings per common
share.
|
| (2) |
For
the nine months ended September 30
|
||||||||
|
(unaudited)
|
2009 | 2008 | |||||||
|
Net
Income Per Common Share
|
$ | 1.55 | $ | 2.07 | |||||
|
Specific items (net of tax,
where applicable):
|
|||||||||
|
Fair value adjustments of
natural gas inventory and forward contracts
|
0.01 | 0.01 | |||||||
|
Calpine bankruptcy
settlements
|
- | (0.27 | ) | ||||||
|
GTN lawsuit
settlement
|
- | (0.02 | ) | ||||||
|
Writedown of Broadwater LNG
project costs
|
- | 0.05 | |||||||
|
Income
tax reassessments and adjustments
|
- | (0.04 | ) | ||||||
|
Comparable Earnings Per Common
Share(1)
|
$ | 1.56 | $ | 1.80 | |||||
TransCanada’s
net income in third quarter 2009 was $345 million or $0.50 per common share
compared to $390 million or $0.67 per common share in third quarter 2008. The
$45 million decrease in net income reflected:
|
·
|
increased
EBIT from Pipelines primarily due to increased earnings for the Alberta
System as a result of a settlement approved in December 2008, the positive
impact of a stronger U.S. dollar on Pipelines’ U.S. operations and higher
operations, maintenance and administrative (OM&A) cost savings for the
Canadian Mainline;
|
|
·
|
decreased
EBIT from Energy primarily due to lower power prices in Western Power, and
reduced volumes in Western Power, New England and Bruce Power. These
decreases were partially offset by a $16 million year-over-year positive
change in the pre-tax fair value adjustment of natural gas inventory and
forward contracts, as well as increased earnings as a result of the
acquisition of Ravenswood and the start up of Portlands Energy and the
Carleton wind farm. Energy’s EBIT also reflects higher contribution from
the Natural Gas Storage business due to increased third party storage
revenues;
|
THIRD
QUARTER REPORT 2009 - TRANSCANADA [5
|
·
|
increased
interest income and other due to higher gains from changes in the fair
value of derivatives used to manage the Company’s exposure to foreign
exchange rate fluctuations and the positive impact of a stronger U.S.
dollar; and
|
|
·
|
decreased
income tax expense primarily due to reduced earnings, higher income tax
rate differentials and other positive income tax
adjustments.
|
Earnings
per common share in third quarter 2009 was further reduced by an 18 per cent
increase in the average number of common shares outstanding following the
Company’s issuance of 58.4 million and 35.1 million common shares in second
quarter 2009 and fourth quarter 2008, respectively.
Comparable
earnings in third quarter 2009 were $335 million or $0.49 per common share
compared to $366 million or $0.63 per common share for the same period in 2008.
Comparable earnings in third quarter 2009 and 2008 excluded $10 million of after
tax ($14 million pre-tax) net unrealized gains and $2 million of after tax ($2
million pre-tax) net unrealized losses, respectively, resulting from changes in
the fair value of proprietary natural gas inventory in storage and natural gas
forward purchase and sale contracts. Comparable earnings in 2008 also excluded
$26 million of favourable income tax adjustments.
On a
consolidated basis, the impact of changes in the U.S. dollar on U.S. Pipelines
and Energy EBIT is largely offset by the impact on U.S. dollar interest expense
and other income statement items. The resultant net exposure is managed using
derivatives thereby effectively reducing the Company’s exposure to changes in
foreign exchange. The average U.S. dollar exchange rate for the three and
nine months ended September 30, 2009 was 1.10 and 1.17, respectively (2008 -
1.04 and 1.02, respectively).
TransCanada’s
net income in the first nine months of 2009 was $993 million or $1.55 per common
share compared to $1.2 billion or $2.07 per common share for the same period in
2008. The $170 million decrease in net income reflected:
|
·
|
decreased
EBIT from Pipelines primarily due to $152 million of after tax gains ($279
million pre-tax) on the sale of shares received by GTN and Portland for
Calpine bankruptcy settlements and proceeds from a GTN lawsuit settlement
of $10 million after tax ($17 million pre-tax) received in first quarter
2008. The impact of these items on the Pipelines segment was partially
offset by the positive impact in 2009 of a stronger U.S. dollar on
Pipelines’ U.S. operations;
|
|
·
|
decreased
EBIT from Energy primarily due to lower power prices in Western Power and
reduced volumes in Western Power and New England. These decreases were
partially offset by higher realized prices at Bruce Power, increased
earnings from the start up of Portlands Energy and the Carleton wind farm,
and the positive impact of a stronger U.S. dollar on Energy’s U.S.
operations. EBIT also reflects the impact of a $27 million after tax ($41
million pre-tax) writedown of costs capitalized for the Broadwater
liquefied natural gas (LNG) project in first quarter
2008;
|
|
·
|
increased
EBIT losses from Corporate due to higher support services costs as a
result of a growing asset base;
|
|
·
|
increased
interest expense due to debt issuances throughout 2008 and first quarter
2009, and the negative impact of a stronger U.S. dollar, partially offset
by an increase in interest capitalized relating to Keystone and other
capital projects;
|
|
·
|
increased
interest income and other due to higher gains from changes in the fair
value of derivatives used to manage the Company’s exposure to foreign
exchange rate fluctuations and the positive impact of a stronger U.S.
dollar;
|
|
·
|
decreased
income tax expense due to lower earnings and higher income tax rate
differentials in 2009; and
|
THIRD
QUARTER REPORT 2009 - TRANSCANADA [6
|
·
|
a
reduction in non-controlling interests due to Portland’s portion of the
Calpine bankruptcy settlements recorded in
2008.
|
Earnings
per common share in the first nine months of 2009 was further reduced due to an
increased average number of common shares outstanding following the Company’s
common share issuances in second quarter 2009 and fourth quarter
2008.
Comparable
earnings in the first nine months of 2009 were $997 million or $1.56 per common
share compared to $1.0 billion or $1.80 per common share for the same period in
2008. Comparable earnings for the first nine months of 2009 and 2008 excluded $4
million after tax ($6 million pre-tax) and $6 million after tax ($7 million
pre-tax), respectively, of net unrealized losses from changes in the fair value
of proprietary natural gas inventory in storage and natural gas forward purchase
and sale contracts. In addition, comparable earnings in the first nine months of
2008 excluded the $152 million after tax gain on Calpine bankruptcy settlements,
the $10 million after tax gain on the GTN lawsuit settlement, the $27 million
after tax writedown of Broadwater LNG project costs and $26 million of
favourable income tax adjustments.
Results
from each of the segments for the three and nine month periods ended September
30, 2009 are discussed further in the Pipelines, Energy and Corporate sections
of this MD&A.
Pipelines
The
Pipelines business generated comparable EBIT of $475 million and $1.6 billion in
the three and nine month periods ended September 30, 2009, respectively,
compared to $469 million and $1.5 billion for the same periods in
2008.
Comparable
EBIT for the first nine months of 2008 excluded the $279 million of gains
realized by GTN and Portland for the Calpine bankruptcy settlements and the $17
million gain on the GTN lawsuit settlement with a software
supplier.
THIRD
QUARTER REPORT 2009 - TRANSCANADA [7
Pipelines
Results
|
(unaudited)
|
Three
months ended
September
30
|
Nine
months ended
September
30
|
||||||||||||||
|
(millions
of dollars)
|
2009
|
2008
|
2009
|
2008
|
||||||||||||
|
Canadian
Pipelines
|
||||||||||||||||
|
Canadian
Mainline
|
279
|
268
|
851
|
841
|
||||||||||||
|
Alberta
System
|
190
|
182
|
535
|
540
|
||||||||||||
|
Foothills
|
32
|
33
|
100
|
102
|
||||||||||||
|
Other
(TQM, Ventures LP)
|
13
|
13
|
44
|
39
|
||||||||||||
|
Canadian Pipelines Comparable
EBITDA(1)
|
514
|
496
|
1,530
|
1,522
|
||||||||||||
|
U.S.
Pipelines
|
||||||||||||||||
|
ANR
|
57
|
74
|
263
|
248
|
||||||||||||
|
GTN(2)
|
42
|
48
|
152
|
146
|
||||||||||||
|
Great
Lakes
|
31
|
28
|
108
|
93
|
||||||||||||
|
Iroquois
|
18
|
15
|
62
|
42
|
||||||||||||
|
PipeLines
LP(3)
|
24
|
13
|
64
|
47
|
||||||||||||
|
Portland(4)
|
2
|
4
|
18
|
18
|
||||||||||||
|
International
(Tamazunchale, TransGas, INNERGY/Gas
Pacifico)
|
18
|
10
|
46
|
32
|
||||||||||||
|
General,
administrative and support costs(5)
|
(11
|
)
|
(4
|
)
|
(17
|
)
|
(14
|
)
|
||||||||
|
Non-controlling
interests(6)
|
45
|
40
|
148
|
133
|
||||||||||||
|
U.S. Pipelines Comparable
EBITDA(1)
|
226
|
228
|
844
|
745
|
||||||||||||
|
Business Development Comparable
EBITDA(1)
|
(10
|
)
|
(1
|
)
|
(26
|
)
|
(28
|
)
|
||||||||
|
Pipelines Comparable
EBITDA(1)
|
730
|
723
|
2,348
|
2,239
|
||||||||||||
|
Depreciation
and amortization
|
(255
|
)
|
(254
|
)
|
(773
|
)
|
(765
|
)
|
||||||||
|
Pipelines Comparable
EBIT(1)
|
475
|
469
|
1,575
|
1,474
|
||||||||||||
|
Specific
items:
|
||||||||||||||||
|
Calpine bankruptcy
settlements(7)
|
-
|
-
|
-
|
279
|
||||||||||||
|
GTN lawsuit
settlement
|
-
|
-
|
-
|
17
|
||||||||||||
|
Pipelines EBIT(1)
|
475
|
469
|
1,575
|
1,770
|
||||||||||||
|
(1)
|
Refer
to the Non-GAAP Measures section in this MD&A for further discussion
of comparable EBITDA, comparable EBIT and
EBIT.
|
|
(2)
|
GTN’s
results include North Baja to June 30,
2009.
|
|
(3)
|
Effective
July 1, 2009, TransCanada’s ownership interest in PipeLines LP increased
to 42.6 per cent. As a result, PipeLines LP’s results include
TransCanada’s ownership of an additional 10.5 per cent of PipeLines LP and
TransCanada’s effective ownership of 42.6 per cent of North Baja since
July 1, 2009.
|
|
(4)
|
Portland’s
results reflect TransCanada’s 61.7 per cent ownership
interest.
|
|
(5)
|
Represents
certain costs associated with supporting the Company’s Canadian and U.S.
Pipelines.
|
|
(6)
|
The
non-controlling interests reflect PipeLines LP and Portland amounts not
owned by TransCanada.
|
|
(7)
|
GTN
and Portland received shares of Calpine with an initial value of $154
million and $103 million, respectively, from the bankruptcy settlements
with Calpine. These shares were subsequently sold for an additional gain
of $22 million.
|
THIRD
QUARTER REPORT 2009 - TRANSCANADA [8
Net
Income for Wholly Owned Canadian Pipelines
|
(unaudited)
|
Three
months ended
September
30
|
Nine
months ended
September
30
|
|||||||||||
|
(millions
of dollars)
|
2009
|
2008
|
2009
|
2008
|
|||||||||
|
Canadian
Mainline
|
68
|
66
|
201
|
204
|
|||||||||
|
Alberta
System
|
44
|
32
|
123
|
97
|
|||||||||
|
Foothills
|
6
|
6
|
18
|
19
|
|||||||||
Canadian
Pipelines
Canadian
Mainline’s net income for the three and nine months ended September 30, 2009
increased $2 million and decreased $3 million, respectively, to $68 million and
$201 million, respectively, compared to the same periods in 2008. Net income for
third quarter 2009 reflected higher OM&A cost savings, partially offset by a
lower average investment base and a lower rate of return on common equity (ROE)
as determined by the National Energy Board (NEB) of 8.57 per cent in 2009
compared to 8.71 per cent in 2008. Net income for the nine months ended
September 30, 2009 decreased as higher OM&A cost savings were more than
offset by the lower average investment base and ROE.
Canadian
Mainline’s EBITDA for the three and nine months ended September 30, 2009 of $279
million and $851 million, respectively, increased $11 million and $10 million,
respectively, compared to the same periods in 2008, primarily due to higher
revenues as a result of the recovery of higher depreciation and income taxes
approved in the 2009 tolls, and higher OM&A cost savings. The increases in
revenues were partially offset by a lower overall return on a reduced average
investment base.
The
Alberta System’s net income was $44 million in third quarter 2009 and $123
million for the first nine months of 2009 compared to $32 million and $97
million for the same periods in 2008. Earnings in 2009 reflected the impact of a
2008-2009 settlement approved by the Alberta Utilities Commission (AUC) in
December 2008 and the impact of a higher average investment base compared to
2008 due to customer-driven expansions of the Alberta System.
The
Alberta System's EBITDA was $190 million in third quarter 2009 and $535 million
for the first nine months of 2009 compared to $182 million and $540 million for
the same periods in 2008. Third quarter EBITDA reflects increases due to higher
settlement earnings and revenues as a result of the recovery of higher financial
charges. For the nine months ended September 30, 2009, these increases were more
than offset by reduced revenues as a result of the recovery of lower
depreciation and income taxes approved in the settlement.
EBITDA
from Other Canadian Pipelines was $13 million and $44 million for the three and
nine months ended September 30, 2009, respectively, compared to $13 million and
$39 million for the same periods in 2008. The increase in the nine month period
was primarily due to the NEB decision on TQM’s cost of capital for the years
2007 and 2008 reached in February 2009.
U.S.
Pipelines
ANR’s
EBITDA for the three and nine months ended September 30, 2009 was $57 million
and $263 million, respectively, compared to $74 million and $248 million,
respectively, for the same periods in 2008. The decrease in EBITDA in third
quarter 2009 was primarily due to reduced revenues as a result of lower
utilization, lower incidental natural gas and condensate sales, and higher
OM&A costs, partially offset by the positive impact of a stronger U.S.
dollar. For the nine months ended September 30, 2009, the increase in EBITDA was
primarily due to the positive impact of a stronger U.S. dollar and higher
revenues, partially offset by lower natural gas and condensate sales, and higher
OM&A costs.
THIRD
QUARTER REPORT 2009 - TRANSCANADA [9
GTN’s
EBITDA for the three months ended September 30, 2009 decreased $6 million from
the same period in 2008 primarily due to the sale of North Baja to PipeLines LP
on July 1, 2009. GTN’s EBITDA for the nine months ended September 30, 2009
increased $6 million from the same period in 2008 primarily due to the positive
impact of a stronger U.S. dollar, partially offset by the sale of North Baja in
2009.
EBITDA
for the remainder of the U.S. Pipelines was $127 million and $429 million for
the three and nine months ended September 30, 2009, respectively, compared to
$106 million and $351 million for the same periods in 2008. The increases were
primarily due to the positive impact of a stronger U.S. dollar in 2009,
increased revenues for Gas Pacifico resulting from a new transportation
agreement, TransCanada’s increased ownership in PipeLines LP and PipeLines LP’s
acquisition of North Baja, partially offset by charges incurred in restructuring
the U.S. pipeline operations. The increase for the nine month period also
included higher short-term revenues for Iroquois.
Operating
Statistics
|
Nine
months
ended
September 30
|
Canadian
Mainline(1)
|
Alberta
System(2)
|
Foothills
|
ANR(3)
|
GTN
System(3)
|
|||||||||||||||||||||||||||||||||||
|
(unaudited)
|
2009
|
2008
|
2009
|
2008
|
2009
|
2008
|
2009
|
2008
|
2009
|
2008
|
||||||||||||||||||||||||||||||
|
Average
investment base
|
6,549 | 7,065 | 4,724 | 4,322 | 711 | 755 | n/a | n/a | n/a | n/a | ||||||||||||||||||||||||||||||
| ($ millions) | ||||||||||||||||||||||||||||||||||||||||
|
Delivery
volumes (Bcf)
|
||||||||||||||||||||||||||||||||||||||||
|
Total
|
1,561 | 1,635 | 2,652 | 2,833 | 901 | 955 | 1,199 | 1,219 | 578 | 595 | ||||||||||||||||||||||||||||||
|
Average per day
|
5.7 | 6.0 | 9.7 | 10.3 | 3.3 | 3.5 | 4.4 | 4.5 | 2.1 | 2.2 | ||||||||||||||||||||||||||||||
|
(1)
|
Canadian
Mainline 2009 and 2008 delivery volumes reflect physical deliveries to
domestic and export markets. Delivery volumes reported prior to third
quarter 2009 reflected contract deliveries, however, customer contracting
patterns have changed in recent years making physical deliveries a better
measure of system utilization. Canadian Mainline’s physical receipts
originating at the Alberta border and in Saskatchewan for the nine months
ended September 30, 2009 were 1,234 billion cubic feet (Bcf) (2008 – 1,460
Bcf); average per day was 4.5 Bcf (2008 – 5.3
Bcf).
|
|
(2)
|
Field
receipt volumes for the Alberta System for the nine months ended September
30, 2009 were 2,734 Bcf (2008 – 2,908 Bcf); average per day was 10.0 Bcf
(2008 – 10.6 Bcf).
|
|
(3)
|
ANR’s
and the GTN System’s results are not impacted by average investment base
as these systems operate under fixed rate models approved by the U.S.
Federal Energy Regulatory
Commission.
|
Capitalized
Project Costs
At
September 30, 2009, Other Assets included $212 million of capitalized costs
related to the Keystone pipeline system expansion to the Gulf
Coast.
As at
September 30, 2009, TransCanada had advanced $142 million to the Aboriginal
Pipeline Group (APG) with respect to the Mackenzie Gas Pipeline Project (MGP).
TransCanada and the other co-venture companies involved in the MGP continue to
pursue approval of the proposed project, focusing on obtaining regulatory
approval and the Canadian government’s support of an acceptable fiscal
framework. Project timing continues to be uncertain and discussions between the
co-venture group and the Canadian government are ongoing. In the event the
co-venture group is unable to reach an agreement with the government on an
acceptable fiscal framework, the parties will need to determine the appropriate
next steps for the project. For TransCanada, this may result in a reassessment
of the carrying amount of the APG advances.
Energy
Energy’s
comparable EBIT was $204 million in third quarter 2009 compared to $302 million
in third quarter 2008. Comparable EBIT excluded net unrealized gains of $14
million and net unrealized losses of $2 million in third quarter 2009 and 2008,
respectively, resulting from changes in the fair value of proprietary natural
gas inventory and natural gas forward purchase and sale contracts.
THIRD
QUARTER REPORT 2009 - TRANSCANADA [10
Energy’s
comparable EBIT was $622 million for the first nine months of 2009 compared to
$735 million in the same nine months of 2008. Comparable EBIT excluded net
unrealized losses of $6 million and $7 million in the first nine months of 2009
and 2008, respectively, resulting from changes in the fair value of proprietary
natural gas inventory and natural gas forward purchase and sale contracts.
Comparable EBIT in 2008 also excluded the $41 million writedown of costs
previously capitalized for the Broadwater LNG project.
Energy
Results
|
(unaudited)
|
Three
months ended
September
30
|
Nine
months ended
September
30
|
||||||||||||||
|
(millions
of dollars)
|
2009
|
2008
|
2009
|
2008
|
||||||||||||
|
Canadian
Power
|
||||||||||||||||
|
Western
Power
|
66 | 145 | 218 | 382 | ||||||||||||
|
Eastern
Power
|
52 | 35 | 164 | 104 | ||||||||||||
|
Bruce
Power
|
81 | 102 | 282 | 205 | ||||||||||||
|
General,
administrative and support costs
|
(9 | ) | (12 | ) | (28 | ) | (28 | ) | ||||||||
|
Canadian Power Comparable
EBITDA(1)
|
190 | 270 | 636 | 663 | ||||||||||||
|
U.S. Power(2)
|
||||||||||||||||
|
Northeast
Power
|
80 | 85 | 198 | 209 | ||||||||||||
|
General,
administrative and support costs
|
(12 | ) | (9 | ) | (35 | ) | (28 | ) | ||||||||
|
U.S. Power Comparable
EBITDA(1)
|
68 | 76 | 163 | 181 | ||||||||||||
|
Natural
Gas Storage
|
||||||||||||||||
|
Alberta
Storage
|
47 | 35 | 122 | 114 | ||||||||||||
|
General,
administrative and support costs
|
(2 | ) | (4 | ) | (7 | ) | (10 | ) | ||||||||
|
Natural Gas Storage Comparable
EBITDA(1)
|
45 | 31 | 115 | 104 | ||||||||||||
|
Business Development Comparable
EBITDA(1)
|
(11 | ) | (11 | ) | (31 | ) | (35 | ) | ||||||||
|
Energy Comparable
EBITDA(1)
|
292 | 366 | 883 | 913 | ||||||||||||
|
Depreciation
and amortization
|
(88 | ) | (64 | ) | (261 | ) | (178 | ) | ||||||||
|
Energy Comparable
EBIT(1)
|
204 | 302 | 622 | 735 | ||||||||||||
|
Specific
items:
|
||||||||||||||||
|
Fair value adjustments of
natural gas inventoryand
forward contracts
|
14 | (2 | ) | (6 | ) | (7 | ) | |||||||||
|
Writedown of Broadwater LNG
project costs
|
- | - | - | (41 | ) | |||||||||||
|
Energy EBIT(1)
|
218 | 300 | 616 | 687 | ||||||||||||
|
(1)
|
Refer
to the Non-GAAP Measures section in this MD&A for further discussion
of comparable EBITDA, comparable EBIT and
EBIT.
|
|
(2)
|
Includes
Ravenswood effective August 2008.
|
THIRD
QUARTER REPORT 2009 - TRANSCANADA [11
Western and Eastern Canadian Power
Comparable EBITDA(1)(2)
|
(unaudited)
|
Three
months ended September 30
|
Nine months ended September 30 | ||||||||||||||
|
(millions
of dollars)
|
2009
|
2008
|
2009
|
2008 |
|
|||||||||||
|
Revenues
|
||||||||||||||||
|
Western power
|
196 | 264 | 585 | 842 | ||||||||||||
|
Eastern power
|
69 | 48 | 209 | 148 | ||||||||||||
|
Other(3)
|
32 | 56 | 122 | 108 | ||||||||||||
| 297 | 368 | 916 | 1,098 | |||||||||||||
|
Commodity
Purchases Resold
|
||||||||||||||||
|
Western power
|
(120 | ) | (114 | ) | (327 | ) | (380 | ) | ||||||||
|
Eastern power
|
- | - | - | (2 | ) | |||||||||||
|
Other(4)
|
(17 | ) | (13 | ) | (80 | ) | (47 | ) | ||||||||
| (137 | ) | (127 | ) | (407 | ) | (429 | ) | |||||||||
|
Plant
operating costs and other
|
(42 | ) | (60 | ) | (129 | ) | (183 | ) | ||||||||
|
General,
administrative and support costs
|
(9 | ) | (12 | ) | (28 | ) | (28 | ) | ||||||||
|
Other
(expense)/income
|
- | (1 | ) | 2 | - | |||||||||||
|
Comparable EBITDA(2)
|
109 | 168 | 354 | 458 | ||||||||||||
|
(1)
|
Includes
Portlands Energy and the Carleton wind farm effective April 2009 and
November 2008, respectively.
|
|
(2)
|
Refer
to the Non-GAAP Measures section in this MD&A for further discussion
of comparable EBITDA.
|
|
(3)
|
Other
revenue includes sales of natural gas, sulphur and thermal carbon
black.
|
|
(4)
|
Other
commodity purchases resold includes the cost of natural gas
sold.
|
Western and Eastern Canadian Power
Operating Statistics(1)
|
Three
months ended September 30
|
Nine
months ended September 30
|
|||||||||||||||
|
(unaudited)
|
2009
|
2008
|
2009
|
2008
|
||||||||||||
|
Sales
Volumes (GWh)
|
||||||||||||||||
|
Supply
|
||||||||||||||||
|
Generation
|
||||||||||||||||
|
Western Power
|
541
|
598
|
1,718
|
1,733
|
||||||||||||
|
Eastern Power
|
305
|
225
|
1,081
|
737
|
||||||||||||
|
Purchased
|
||||||||||||||||
|
Sundance A & B and
Sheerness PPAs
|
2,560
|
2,949
|
7,725
|
9,143
|
||||||||||||
|
Other
purchases
|
113
|
252
|
420
|
789
|
||||||||||||
|
3,519
|
4,024
|
10,944
|
12,402
|
|||||||||||||
|
Sales
|
||||||||||||||||
|
Contracted
|
||||||||||||||||
|
Western Power
|
2,514
|
2,686
|
7,164
|
8,579
|
||||||||||||
|
Eastern Power
|
307
|
297
|
1,117
|
899
|
||||||||||||
|
Spot
|
||||||||||||||||
|
Western Power
|
698
|
1,041
|
2,663
|
2,924
|
||||||||||||
|
3,519
|
4,024
|
10,944
|
12,402
|
|||||||||||||
|
Plant
Availability
|
||||||||||||||||
|
Western
Power(2)
|
90%
|
92%
|
92%
|
87%
|
||||||||||||
|
Eastern
Power
|
97%
|
98%
|
97%
|
97%
|
||||||||||||
|
(1)
|
Includes
Portlands Energy and the Carleton wind farm effective April 2009 and
November 2008, respectively.
|
|
(2)
|
Excludes
facilities that provide power to TransCanada under
PPAs.
|
Western
Power’s EBITDA of $66 million in third quarter 2009 decreased $79 million
compared to $145 million in third quarter 2008. This decrease was primarily due
to lower earnings from the Alberta power portfolio resulting from lower overall
realized power prices on lower volumes of power sold. In addition, Western
Power’s EBITDA in third quarter 2008 included $17 million relating to sulphur
sales.
THIRD
QUARTER REPORT 2009 - TRANSCANADA [12
Western
Power’s EBITDA of $218 million in the nine months ended September 30, 2009
decreased $164 million compared to $382 million for the same period in 2008
primarily due to lower overall realized power prices on lower volumes of power
sold, partially offset by lower power purchase arrangements (PPA) costs per
megawatt hour (MWh). Western Power’s EBITDA for the nine months ended September
30, 2008 also included $17 million relating to sulphur sales.
Lower
overall realized power prices as well as lower sales volumes resulted in
decreases of $68 million and $257 million in Western Power’s power revenues for
the three and nine months ended September 30, 2009, respectively, compared to
the same periods in 2008. Lower sales volumes were the result of reduced
dispatch of the Alberta PPAs during periods of reduced demand.
Eastern
Power’s EBITDA of $52 million and $164 million for the three and nine months
ended September 30, 2009, respectively, increased $17 million and $60 million,
respectively, compared to the same periods in 2008. These increases were
primarily due to incremental earnings from Portlands Energy and the Carleton
wind farm at Cartier Wind, which went into service in April 2009 and November
2008, respectively, as well as higher contracted revenue from the Bécancour
facility.
Eastern
Power’s power revenues increased $21 million and $61 million for the three and
nine months ended September 30, 2009, respectively, primarily due to incremental
revenues from Portlands Energy and the Carleton wind farm.
For the
nine months ended September 30, 2009, Other Revenues and Other Commodity
Purchases Resold of $122 million and $80 million, respectively, increased
compared to the same period in 2008 as a result of an increase in the quantity
of natural gas being resold in Eastern Power in first quarter 2009.
Plant
Operating Costs and Other, which includes fuel gas consumed in generation, of
$42 million and $129 million for the three and nine months ended September 30,
2009, respectively, decreased from the same periods in 2008 primarily due to
lower prices for natural gas in Western Power.
Western
Power 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 would otherwise have to purchase electricity in the open
market to fulfill its contractual sales obligations. Approximately 78 per cent
of Western Power sales volumes were sold under contract in third quarter 2009,
compared to 72 per cent in third quarter 2008. To reduce its exposure to spot
market prices on uncontracted volumes, as at September 30, 2009, Western Power
had entered into fixed-price power sales contracts to sell approximately 3,200
gigawatt hours (GWh) for the remainder of 2009 and 9,200 GWh for
2010.
Eastern
Power is focused on selling power under long-term contracts. As a result, in
third quarter 2009 and 2008, 100 per cent of Eastern Power sales volumes were
sold under contract and are expected to continue to be fully sold under contract
for the remainder of 2009 and 2010.
THIRD
QUARTER REPORT 2009 - TRANSCANADA [13
Bruce
Power Results
|
(TransCanada’s proportionate
share)
(unaudited)
|
Three
months ended
September
30
|
Nine
months ended
September
30
|
||||||||
|
(millions
of dollars unless otherwise indicated)
|
2009
|
2008
|
2009
|
2008
|
||||||
|
Revenues(1)(2)
|
224
|
227
|
685
|
603
|
||||||
|
Operating
Expenses(2)
|
(143
|
)
|
(125
|
)
|
(403
|
)
|
(398
|
)
|
||
|
Comparable EBITDA(3)
|
81
|
102
|
282
|
205
|
||||||
|
Bruce A Comparable
EBITDA(3)
|
(11
|
)
|
22
|
77
|
79
|
|||||
|
Bruce B Comparable
EBITDA(3)
|
92
|
80
|
205
|
126
|
||||||
|
Comparable EBITDA(3)
|
81
|
102
|
282
|
205
|
||||||
|
Bruce
Power – Other Information
|
||||||||||
|
Plant
availability
|
||||||||||
|
Bruce A
|
71%
|
85%
|
89%
|
88%
|
||||||
|
Bruce B
|
97%
|
94%
|
90%
|
82%
|
||||||
|
Combined Bruce
Power
|
89%
|
92%
|
90%
|
85%
|
||||||
|
Planned
outage days
|
||||||||||
|
Bruce A
|
46
|
12
|
46
|
45
|
||||||
|
Bruce B
|
-
|
-
|
45
|
100
|
||||||
|
Unplanned
outage days
|
||||||||||
|
Bruce A
|
3
|
8
|
8
|
10
|
||||||
|
Bruce B
|
3
|
12
|
44
|
60
|
||||||
|
Sales
volumes (GWh)
|
||||||||||
|
Bruce A
|
1,099
|
1,356
|
4,157
|
4,182
|
||||||
|
Bruce B
|
1,950
|
2,153
|
5,751
|
5,581
|
||||||
|
3,049
|
3,509
|
9,908
|
9,763
|
|||||||
|
Results
per MWh
|
||||||||||
|
Bruce A power
revenues
|
$64
|
$63
|
$64
|
$62
|
||||||
|
Bruce B power
revenues
|
$66
|
$59
|
$64
|
$57
|
||||||
|
Combined Bruce Power
revenues
|
$66
|
$60
|
$64
|
$59
|
||||||
|
Percentage
of Bruce B output sold to spot market
|
49%
|
33%
|
42%
|
37%
|
||||||
|
(1)
|
Revenues
include Bruce A’s fuel cost recoveries of $7 million and $28 million for
the three and nine months ended September 30, 2009, respectively (2008 -
$5 million and $32 million, respectively). Revenues also include gains of
$2 and $4 million as a result of changes in fair value of held-for-trading
derivatives for the three and nine months ended September 30, 2009,
respectively (2008 - gain of $5 million and loss of $1 million,
respectively).
|
|
(2)
|
Includes
adjustments to eliminate the effects of inter-partnership transactions
between Bruce A and Bruce B.
|
|
(3)
|
Refer
to the Non-GAAP Measures section in this MD&A for further discussion
of comparable EBITDA.
|
TransCanada’s
proportionate share of Bruce Power’s comparable EBITDA decreased $21 million to
$81 million in third quarter 2009 compared to third quarter 2008 primarily due
to higher operating costs as well as lower output as a result of increased
outage days.
TransCanada’s
proportionate share of Bruce A’s comparable EBITDA decreased $33 million to a
loss of $11 million in third quarter 2009 compared to earnings of $22 million in
third quarter 2008 as a result of decreased volumes and higher operating costs
due to an increase in outage days following the rescheduling of two planned
outages from March 2009 to September 2009. Bruce A’s availability in third
quarter 2009 was 71 per cent as a result of 49 outage days compared to an
availability of 85 per cent and 20 outage days in the same period in
2008.
TransCanada’s
proportionate share of Bruce B’s comparable EBITDA increased $12 million to $92
million in third quarter 2009 compared to third quarter 2008 primarily due to
higher realized prices resulting
from the recognition of payments received pursuant to the floor price mechanism
in Bruce B’s contract with the Ontario Power Authority (OPA).
THIRD
QUARTER REPORT 2009 - TRANSCANADA [14
In 2008,
Bruce B did not recognize into revenue any of the support payments received
under the floor price mechanism as the annual average spot price exceeded the
average floor price. Amounts received under the floor price mechanism in any
year are subject to repayment if spot prices in the remainder of that year
increase above the floor price. With respect to 2009, TransCanada currently
expects spot prices to be less than the floor price for the remainder of the
year, therefore, no amounts recorded in revenue in the first nine months of 2009
are expected to be repaid.
TransCanada’s
proportionate share of Bruce Power’s Comparable EBITDA increased $77 million to
$282 million in the nine months ended September 30, 2009 compared to the same
period in 2008 due to higher realized prices resulting from the
recognition of payments received pursuant to the floor price mechanism as well
as higher output, deemed generation payments in third quarter 2009 and lower
operating costs per MWh due to fewer outage days.
TransCanada’s
share of Bruce Power’s generation in third quarter 2009 decreased to 3,049 GWh
compared to 3,509 GWh in third quarter 2008, however, Bruce Power received
deemed generation payments at OPA contract prices during periods of surplus
baseload generation when the output of the units was reduced due to system
curtailments required by the Independent Electricity System Operator. Including
deemed generation, the Bruce Power units’ combined average availability was 89
per cent in third quarter 2009, compared to 92 per cent in third quarter 2008.
An approximate six week maintenance outage of Bruce A Unit 4 and an approximate
one month outage of Bruce A Unit 3 were rescheduled from March 2009 to September
2009. The overall plant availability percentage in 2009 is currently expected to
be in the low 90s for the four Bruce B units and the mid 80s for the two
operating Bruce A units.
Pursuant
to the terms of a contract with the OPA, all of the output from Bruce A in third
quarter 2009 was sold at a fixed price of $64.45 per MWh (before recovery of
fuel costs from the OPA) compared to $63.00 per MWh in third quarter 2008. All
output from the Bruce B Units 5 to 8 were subject to a floor price of $48.76 per
MWh in third quarter 2009 and $47.66 per MWh in third quarter 2008. Both the
Bruce A and Bruce B contract prices are adjusted annually for inflation on April
1.
At
September 30, 2009, Bruce B had sold forward approximately 1,000 GWh and 2,700
GWh, representing TransCanada’s proportionate share, for the remainder of 2009
and the year 2010, respectively. To reduce its exposure to spot prices, Bruce B
had entered into most of these fixed-price contracts in 2006 to 2008 when the
spot price exceeded the floor price. Under these ‘contracts for differences’,
Bruce B receives the difference between the contract price and spot price on
output sold forward under contract. As a result, Bruce B’s realized price of $66
per MWh and $64 per MWh in the three and nine months ended September 30, 2009,
respectively, reflects revenues recognized from both the floor price mechanism
and contract sales, compared to $59 per MWh and $57 per MWh in the same periods
in 2008 in which no revenues were recognized under the floor price
mechanism.
As at
September 30, 2009, Bruce A had incurred approximately $3.1 billion in
costs for the refurbishment and restart of Units 1 and 2, and approximately $0.2
billion for the refurbishment of Units 3 and 4.
THIRD
QUARTER REPORT 2009 - TRANSCANADA [15
U.S. Power Comparable
EBITDA(1)(2)
|
(unaudited)
|
Three
months ended September 30
|
Nine months ended September 30 | |||||||||||||||
|
(millions
of dollars)
|
2009
|
2008
|
2009
|
2008 |
|
||||||||||||
|
Revenues
|
|||||||||||||||||
|
Power
|
374 | 263 | 1,035 | 704 | |||||||||||||
|
Other(3)(4)
|
114 | 81 | 364 | 258 | |||||||||||||
| 488 | 344 | 1,399 | 962 | ||||||||||||||
|
Commodity
Purchases Resold
|
|||||||||||||||||
|
Power
|
(147 | ) | (121 | ) | (419 | ) | (360 | ) | |||||||||
|
Other(5)
|
(84 | ) | (77 | ) | (271 | ) | (239 | ) | |||||||||
| (231 | ) | (198 | ) | (690 | ) | (599 | ) | ||||||||||
|
Plant
operating costs and other(4)
|
(177 | ) | (61 | ) | (511 | ) | (154 | ) | |||||||||
|
General,
administrative and support costs
|
(12 | ) | (9 | ) | (35 | ) | (28 | ) | |||||||||
|
Comparable EBITDA(2)
|
68 | 76 | 163 | 181 | |||||||||||||
|
(1)
|
Includes
Ravenswood effective August 26,
2008.
|
|
(2)
|
Refer
to the Non-GAAP Measures section in this MD&A for further discussion
of comparable EBITDA.
|
|
(3)
|
Other
revenue includes sales of natural
gas.
|
|
(4)
|
Includes
activity at Ravenswood related to a third-party owned steam production
facility operated by TransCanada on behalf of the plant
owner.
|
|
(5)
|
Other
commodity purchases resold includes the cost of natural gas
sold.
|
U.S. Power Sales Operating
Statistics(1)
|
Three
months ended September 30
|
Nine
months ended September 30
|
|||||||||||||||
|
(unaudited)
|
2009
|
2008
|
2009
|
2008
|
||||||||||||
|
Sales
Volumes (GWh)
|
||||||||||||||||
|
Supply
|
||||||||||||||||
|
Generation
|
2,021
|
1,217
|
4,593
|
2,847
|
||||||||||||
|
Purchased
|
1,259
|
1,566
|
3,653
|
4,383
|
||||||||||||
|
3,280
|
2,783
|
8,246
|
7,230
|
|||||||||||||
|
Sales
|
||||||||||||||||
|
Contracted
|
2,800
|
2,751
|
7,265
|
7,032
|
||||||||||||
|
Spot
|
480
|
32
|
981
|
198
|
||||||||||||
|
3,280
|
2,783
|
8,246
|
7,230
|
|||||||||||||
|
Plant Availability(2)
|
97%
|
98%
|
78%
|
96%
|
||||||||||||
|
(1)
|
Includes
Ravenswood effective August 26,
2008.
|
|
(2)
|
Plant
availability decreased in the nine months ended September 30, 2009 due to
the impact of a forced outage affecting Unit 30 at Ravenswood, which
returned to service May 17, 2009.
|
U.S.
Power’s EBITDA for the three and nine months ended September 30, 2009 of $68
million and $163 million, respectively, decreased $8 million and $18 million,
respectively, compared to the same periods in 2008. These decreases were due to
reduced power prices and lower volumes of power sold to commercial and
industrial customers in New England as a result of unseasonably cool summer
weather, which resulted in a decrease in demand, partially offset by incremental
revenue realized on contract sales in New England. While average spot market
power prices in New England decreased in 2009 compared to 2008, the majority of
U.S. Power’s sales in New England are sold at contracted prices. These decreases
were also partially offset by incremental EBITDA from the Ravenswood facility
which was acquired in August 2008 and the impact of a stronger U.S. dollar in
the first nine months of 2009.
THIRD
QUARTER REPORT 2009 - TRANSCANADA [16
U.S.
Power’s power revenues for the three and nine months ended September 30, 2009 of
$374 million and $1,035 million, respectively, increased from $263 million and
$704 million for the same periods in 2008 due to incremental revenues from the
Ravenswood facility, an increase in financial contract sales and the impact of a
stronger U.S. dollar, partially offset by lower volumes of power sold in New
England.
Other
Revenues of $114 million and $364 million for the three and nine months ended
September 30, 2009, respectively, increased $33 million and $106 million,
respectively, compared to the same periods in 2008 due to incremental revenues
earned from a steam generating facility at Ravenswood, as well as an increase in
the volume of natural gas sold and the impact of a stronger U.S. dollar in
2009.
Power
Commodity Purchases Resold of $147 million and $419 million for the three and
nine months ended September 30, 2009, respectively, increased from $121 million
and $360 million in the same periods in 2008 primarily due to the incremental
impact of financial contract purchases in New England and the impact of a
stronger U.S. dollar in 2009. These increases were partially offset by lower
volumes of power purchased for resale to commercial and industrial customers in
New England.
Other
Commodity Purchases Resold for the three and nine months ended September 30,
2009 of $84 million and $271 million, respectively, increased from $77 million
and $239 million for the same periods in 2008 primarily due to higher volumes of
natural gas purchased and resold as well as the impact of a stronger U.S.
dollar, partially offset by a decrease in natural gas prices.
Plant
Operating Costs and Other, which includes fuel gas consumed in generation, of
$177 million and $511 million for the three and nine months ended September 30,
2009, respectively, increased $116 million and $357 million, respectively, from
the same periods in 2008 due to incremental costs from the Ravenswood
facility.
In the
three and nine months ended September 30, 2009, 15 per cent and 12 per cent,
respectively, of power sales volumes were sold into the spot market, compared to
one and three per cent for the same periods in 2008, as there were no power
sales contracts in place for Ravenswood extending beyond 2008 at the time the
facility was acquired. U.S. Power 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 on
uncontracted volumes, as at September 30, 2009, U.S. Power had entered into
fixed-price power sales contracts to sell approximately 2,500 GWh for the
remainder of 2009 and 7,600 GWh for 2010, although certain contracted volumes
are dependent on customer usage levels. Actual amounts contracted in future
periods will depend on market liquidity and other factors.
Natural
Gas Storage
Natural
Gas Storage’s comparable EBITDA for the three and nine months ended September
30, 2009 was $45 million and $115 million, respectively, compared to $31 million
and $104 million for the same periods in 2008. The $14 million and $11 million
increases in EBITDA in third quarter 2009 and nine months ended September 30,
2009 were primarily due to increased third party storage revenues.
Comparable
EBITDA excluded net unrealized gains of $14 million and net unrealized losses of
$6 million in the three and nine months ended September 30, 2009, respectively
(2008 – losses of $2 million and $7 million, respectively), resulting from
changes in the fair value of proprietary natural gas inventory in storage and
natural gas forward purchase and sale contracts. TransCanada manages its
proprietary natural gas storage earnings by simultaneously entering into a
forward purchase of natural gas for injection into storage and an offsetting
forward sale of natural gas for withdrawal at a later period, thereby locking in
future positive margins and effectively eliminating exposure to price movements
of natural gas. Fair value adjustments are recorded in each period on
proprietary natural gas held
in storage and these forward contracts are not representative of the amounts
that will be realized on settlement. The fair value of proprietary natural gas
inventory held in storage has been measured using a weighted average of forward
prices for the following four months less selling costs.
THIRD
QUARTER REPORT 2009 - TRANSCANADA [17
Depreciation
and Amortization
Depreciation
and Amortization for the three and nine months ended September 30, 2009 of $88
million and $261 million, respectively, increased $24 million and $83 million,
respectively, compared to the same periods in 2008, primarily due to the
acquisition of Ravenswood in August 2008.
Corporate
Corporate
EBIT losses for the three and nine months ended September 30, 2009 were $28
million and $89 million, respectively, compared to losses of $23 million and $71
million for the same periods in 2008. These increases in EBIT losses were
primarily due to higher support services costs in 2009, reflecting a growing
asset base.
Other Income Statement
Items
Interest
Expense
|
(unaudited)
|
Three
months ended September 30
|
Nine
months ended September 30
|
||||||||||||||||
|
(million
of dollars)
|
2009
|
2008
|
2009
|
2008
|
||||||||||||||
|
Interest
on long-term debt(1)
|
317 | 256 | 981 | 739 | ||||||||||||||
|
Other
interest and amortization
|
12 | (5 | ) | 19 | (25 | ) | ||||||||||||
|
Capitalized
interest
|
(113 | ) | (38 | ) | (230 | ) | (97 | ) | ||||||||||
| 216 | 213 | 770 | 617 | |||||||||||||||
|
(1)
|
Includes
interest for Junior Subordinated
Notes.
|
Interest
Expense for third quarter 2009 increased $3 million to $216 million from $213
million in third quarter 2008. Interest Expense for the nine months ended
September 30, 2009, increased $153 million to $770 million from $617 million for
the nine months ended September 30, 2008. These increases reflected new debt
issues of US$1.5 billion and $500 million in August 2008, US$2.0 billion in
January 2009 and $700 million in February 2009, as well as higher losses from
changes in the fair value of derivatives used to manage the Company’s exposure
to interest rate fluctuations. In addition, U.S. dollar-denominated interest
expense increased due to the impact of a stronger U.S. dollar. These increases
were partially offset by increased capitalization of interest to finance the
Company’s larger capital spending program in 2009 primarily due to the
construction of Keystone and the acquisition of the remaining 20 per cent
ownership interest in Keystone from ConocoPhillips.
Interest
Income and Other was $43 million and $99 million for the three and nine month
periods ended September 30, 2009, respectively, compared to $22 million and $58
million for the same periods in 2008. The increase of $21 million and $41
million for the three and nine months ended September 30, 2009, respectively,
was primarily due to higher gains from changes in the fair value of derivatives
used to manage the Company’s exposure to foreign exchange rate fluctuations and
the positive impact of a stronger U.S. dollar. An increase in interest income
due to higher cash balances held in 2009 was more than offset by lower interest
rates.
THIRD
QUARTER REPORT 2009 - TRANSCANADA [18
Income
Taxes were $107 million in third quarter 2009 compared to $129 million for the
same period in 2008. Income Taxes for the nine months ended September 30, 2009
were $320 million compared to $507 million for the same period in 2008. The
decreases were primarily due to reduced earnings and higher income tax rate
differentials and other positive income tax adjustments in 2009.
Non-Controlling
Interests were $23 million for third quarter 2009 compared to $18 million for
the same period in 2008. The increase of $5 million was primarily due to higher
earnings in PipeLines LP, partially offset by lower earnings in Portland.
Non-Controlling Interests of $71 million for the first nine months of 2009,
decreased $35 million compared to $106 million for the same period in 2008,
primarily due to the non-controlling interests’ portion of Portland’s Calpine
bankruptcy settlement in first quarter 2008, partially offset by higher
PipeLines LP earnings in 2009.
Liquidity and Capital
Resources
TransCanada’s
financial position remains sound and consistent with recent years as does its
ability to generate cash in the short and long term to provide liquidity,
maintain financial capacity and flexibility, and provide for planned growth.
TransCanada’s liquidity position remains solid, underpinned by highly
predictable cash flow from operations, significant cash balances on hand from
recent debt, common and preferred share issues, as well as committed revolving
bank lines of US$1.0 billion, $2.0 billion and US$300 million, maturing in
November 2010, December 2012 and February 2013, respectively. To date, no draws
have been made on these facilities as TransCanada has maintained continuous
access to the Canadian commercial paper market on competitive terms. An
additional approximate $150 million of capacity remains available on Canadian
and U.S. dollar committed bank facilities at TransCanada-operated affiliates
with maturity dates from 2010 through 2012. In addition, common shares are
expected to be issued under the Company’s Dividend Reinvestment and Share
Purchase Plan (DRP) in lieu of making cash dividend payments to eligible
participants.
At
September 30, 2009, the Company held cash and cash equivalents of $2.4 billion
compared to $1.3 billion at December 31, 2008. The increase in cash and cash
equivalents was primarily due to proceeds from the issuance in 2009 of preferred
shares in third quarter, common shares in second quarter and long-term debt in
first quarter.
Operating
Activities
Funds Generated from
Operations(1)
|
(unaudited)
|
Three
months ended September 30
|
Nine
months ended September 30
|
||||||||||||||
|
(millions
of dollars)
|
2009
|
2008
|
2009
|
2008
|
||||||||||||
|
Cash
Flows
|
||||||||||||||||
|
Funds generated from
operations(1)
|
772 | 711 | 2,230 | 2,309 | ||||||||||||
|
(Increase)/decrease in
operating working capital
|
(31 | ) | 114 | 362 | 16 | |||||||||||
|
Net cash provided by
operations
|
741 | 825 | 2,592 | 2,325 | ||||||||||||
|
(1)
|
Refer
to the Non-GAAP Measures section in this MD&A for further discussion
of funds generated from operations.
|
Net Cash
Provided by Operations decreased $84 million and increased $267 million for the
three and nine months ended September 30, 2009, respectively, compared to the
same periods in 2008, primarily due to changes in operating working capital.
Funds Generated from Operations (FGFO) for the three and nine months ended
September 30, 2009, were $772 million and $2.2 billion, respectively, compared
to $711 million and $2.3 billion for the same periods in 2008. FGFO for the
three months ended September 30, 2009 increased primarily due to increased cash
from earnings, partially offset by increased
pension contributions in 2009. FGFO for the nine months ended September 30, 2009
decreased primarily due to $152 million of after tax proceeds received in 2008
from the Calpine bankruptcy settlements and increased pension contributions in
2009, partially offset by increased cash from earnings.
THIRD
QUARTER REPORT 2009 - TRANSCANADA [19
Investing
Activities
Acquisitions,
net of cash acquired, were $653 million in third quarter 2009 (2008 - $3.1
billion) and $902 million (2008 - $3.1 billion) for the nine months ended
September 30, 2009. In August 2009, the Company acquired ConocoPhillips’
remaining 20 per cent interest in Keystone. Acquisitions for the nine months
ended September 30, 2009 also included the previous increases in ownership
interest in Keystone pursuant to an agreement with ConocoPhillips that became
effective December 2008.
TransCanada
remains committed to executing its previously announced $22 billion capital
expenditure program over the next four years. For the three and nine months
ended September 30, 2009, capital expenditures totalled $1.6 billion and $3.9
billion, respectively (2008 - $0.8 billion and $1.9 billion, respectively),
primarily related to construction of the Keystone pipeline system, expansion of
the Alberta System, refurbishment and restart of Bruce A Units 1 and 2, and
construction of Kibby Wind, Halton Hills, Coolidge and Bison.
Financing
Activities
On
September 30, 2009, TransCanada completed a public offering of 22 million
cumulative redeemable first preferred shares under the September 21, 2009
prospectus, discussed below, for gross proceeds of $550 million. The holders of
the preferred shares are entitled to receive fixed cumulative dividends at an
annual rate of $1.15 per share, payable quarterly, yielding 4.6 per cent per
annum, for the initial five-year period ending December 31, 2014, with the first
dividend payment date scheduled for December 31, 2009. The dividend rate will
reset on December 31, 2014 and every five years thereafter to a yield per annum
equal to the then sum of the five-year Government of Canada bond yield and 1.92
per cent. The preferred shares are redeemable by TransCanada on or after
December 31, 2014 at a price of $25 per share plus all accrued and unpaid
dividends. The net proceeds of this offering are expected to be used to
partially fund capital projects, for general corporate purposes and to repay
short term indebtedness of TransCanada and its affiliates.
The
preferred shareholders will have the right to convert their shares into Series 2
cumulative redeemable first preferred shares on December 31, 2014 and on
December 31 of every fifth year thereafter. The holders of Series 2 preferred
shares will be entitled to receive quarterly floating rate cumulative dividends
at a yield per annum equal to the sum of the then 90-day Government of Canada
treasury bill rate and 1.92 per cent.
On
September 21, 2009, TransCanada filed a short form base shelf prospectus
qualifying for issuance $3.0 billion of common shares, first or second preferred
shares and/or subscription receipts in Canada and the U.S. until October
2011.
This base shelf prospectus replaced the base shelf prospectus filed in July
2008, which was exhausted by the common share issue discussed
below.
In June
2009, TransCanada completed a public offering of 58.4 million common shares,
including full exercise of an underwriters’ over-allotment option. Net proceeds
from the common share offering and the over-allotment option totalled $1.8
billion and are expected to be used by TransCanada to partially fund capital
projects of the Company, including the acquisition of the remaining interest in
Keystone, for general corporate purposes and to repay short-term
indebtedness.
The
Company is well positioned to fund its existing capital program through its
growing internally-generated cash flow, its DRP and its continued access to
capital markets. As demonstrated by the recent sale of North Baja to PipeLines
LP, TransCanada will also continue to examine opportunities for portfolio
management, including a greater role for PipeLines LP, in the financing of its
capital program.
THIRD
QUARTER REPORT 2009 - TRANSCANADA [20
In the
three and nine months ended September 30, 2009, TransCanada issued $207 million
and $3.3 billion, respectively (2008 - $2.1 billion and $2.2 billion,
respectively), and retired $9 million and $509 million, respectively (2008 - $15
million and $788 million, respectively), of long-term debt. TransCanada’s notes
payable increased $77 million and decreased $607 million in the three and nine
months ended September 30, 2009, respectively, compared to a decrease of $258
million and an increase of $466 million for the same periods in
2008.
In April
2009, TCPL filed a $2.0 billion Canadian Medium-Term Notes shelf prospectus to
replace a March 2007 $1.5 billion Canadian Medium-Term Notes shelf prospectus,
which expired in April 2009. No amounts have been issued under this shelf
prospectus.
In
February 2009, TCPL issued Medium-Term Notes of $300 million and $400 million
maturing in February 2014 and February 2039, respectively, and bearing interest
at 5.05 per cent and 8.05 per cent, respectively. These notes were issued under
the $1.5 billion debt shelf prospectus filed in March 2007.
In
January 2009, TCPL issued Senior Unsecured Notes of US$750 million and US$1.25
billion maturing in January 2019 and January 2039, respectively, and bearing
interest at 7.125 per cent and 7.625 per cent, respectively. These notes were
issued under a US$3.0 billion debt shelf prospectus filed in January 2009, which
has remaining capacity of US$1.0 billion.
On
October 20, 2009, the Company retired $250 million of 10.625 per cent
debentures.
Dividends
On
November 3, 2009, TransCanada's Board of Directors declared a quarterly dividend
of $0.38 per share for the quarter ending December 31, 2009 on the Company’s
outstanding common shares. It is payable on January 29, 2010 to shareholders of
record at the close of business on December 31, 2009.
TransCanada’s
Board of Directors approved the issuance of common shares from treasury at a
three per cent discount under TransCanada’s DRP for the dividends payable on
January 29, 2010. The Company reserves the right to alter the discount or return
to purchasing shares on the open market at any time. In the three and nine
months ended September 30, 2009, TransCanada issued 2.5 million and 6.0 million
common shares, respectively, under its DRP, in lieu of making cash dividend
payments of $73 million and $182 million, respectively.
Significant Accounting
Policies and Critical Accounting Estimates
To
prepare financial statements that conform with Canadian GAAP, TransCanada is
required to make estimates and assumptions that affect both the amount and
timing of recording assets, liabilities, revenues and expenses since the
determination of these items may be dependent on future events. The Company uses
the most current information available and exercises careful judgement in making
these estimates and assumptions.
TransCanada's
significant accounting policies and critical accounting estimates have remained
unchanged since December 31, 2008. For further information on the Company’s
accounting policies and estimates refer to the MD&A in TransCanada's 2008
Annual Report.
THIRD
QUARTER REPORT 2009 - TRANSCANADA [21
Changes in Accounting
Policies
The
Company’s accounting policies have not changed materially from those described
in TransCanada’s 2008 Annual Report except as follows:
2009
Accounting Changes
Rate-Regulated
Operations
Effective
January 1, 2009, the temporary exemption was withdrawn from the Canadian
Institute of Chartered Accountants (CICA) Handbook Section 1100 “Generally
Accepted Accounting Principles”, which permitted the recognition and measurement
of assets and liabilities arising from rate regulation. In addition, Section
3465 “Income Taxes” was amended to require the recognition of future income tax
assets and liabilities for rate-regulated entities. The Company chose to adopt
accounting policies consistent with the U.S. Financial Accounting Standards
Board’s Financial Accounting Standard (FAS) 71 “Accounting for the Effects of
Certain Types of Regulation”. As a result, TransCanada retained its current
method of accounting for its rate-regulated operations, except that TransCanada
is required to recognize future income tax assets and liabilities, instead of
using the taxes payable method, and records an offsetting adjustment to
regulatory assets and liabilities. As a result of adopting this accounting
change, additional future income tax liabilities and a regulatory asset in the
amount of $1.4 billion were recorded January 1, 2009 in each of Future Income
Taxes and Regulatory Assets, respectively.
Adjustments
to the 2009 financial statements have been made in accordance with the
transitional provisions for Section 3465, which required a cumulative adjustment
in the current period to Future Income Taxes and Regulatory Assets. Restatement
of prior periods’ financial statements was not permitted under Section
3465.
Intangible
Assets
Effective
January 1, 2009, the Company adopted CICA Handbook Section 3064 “Goodwill and
Intangible Assets”, which replaced Section 3062 “Goodwill and Other Intangible
Assets”. Section 3064 gives guidance on the recognition of intangible assets as
well as the recognition and measurement of internally developed intangible
assets. In addition, Section 3450 “Research and Development Costs” was withdrawn
from the CICA Handbook. Adopting this accounting change did not have a material
effect on the Company’s financial statements.
Credit
Risk and the Fair Value of Financial Assets and Financial
Liabilities
Effective
January 1, 2009, the Company adopted the accounting provisions of Emerging
Issues Committee (EIC) Abstract EIC 173, “Credit Risk and the Fair Value of
Financial Assets and Financial Liabilities”. Under EIC 173 an entity’s own
credit risk and the credit risk of its counterparties is taken into account in
determining the fair value of financial assets and financial liabilities,
including derivative instruments. Adopting this accounting change did not have a
material effect on the Company’s financial statements.
Future
Accounting Changes
International
Financial Reporting Standards
The
CICA’s Accounting Standards Board announced that Canadian publicly accountable
enterprises are required to adopt International Financial Reporting Standards
(IFRS), as issued by the International Accounting Standards Board (IASB),
effective January 1, 2011. The Company will prepare its financial statements
under IFRS commencing January 1, 2011.
THIRD
QUARTER REPORT 2009 - TRANSCANADA [22
TransCanada
has developed a conversion plan that is overseen by its IFRS Steering Committee.
The plan includes identifying resources and training requirements, analyzing the
impact of key differences between Canadian GAAP and IFRS, and developing a
phased approach to conversion implementation. The Company’s conversion project
is discussed in further detail in its 2008 Annual Report. TransCanada continues
to progress its conversion project by scheduling training sessions and IFRS
updates for employees, reviewing new IFRS developments and assessing the impact
that significant differences between Canadian GAAP and IFRS may have on
TransCanada.
Under
existing Canadian GAAP, TransCanada follows specific accounting policies unique
to a rate-regulated business. TransCanada is actively monitoring developments
regarding potential future guidance on the applicability of certain aspects of
rate-regulated accounting under IFRS. Developments in this area could have a
significant effect on the scope of the Company’s IFRS project and on
TransCanada’s financial results under IFRS. On July 23, 2009, the IASB issued an
exposure draft “Rate-regulated Activities” and the Company is assessing the
impact of this exposure draft on TransCanada.
The
impact of the adoption of IFRS on the Company’s consolidated financial
statements and accounting systems is currently being evaluated. At the current
stage of its IFRS project, TransCanada cannot reasonably determine the full
impact that adopting IFRS will have on its financial position and future
results.
Financial
Instruments Disclosure
The CICA
implemented revisions to Handbook Section 3862 “Financial Instruments –
Disclosures” for fiscal years ending after September 30, 2009. These revisions
are intended to align the disclosure requirements for financial instruments to
the maximum extent possible with the disclosure required under IFRS. These
revisions require additional disclosure based on a three level hierarchy that
reflects the significance of inputs used in measuring fair value. Fair values of
assets and liabilities included in Level 1 are determined by reference to quoted
prices in active markets for identical assets and liabilities. Fair values of
assets and liabilities included in Level 2 include valuations using inputs other
than quoted prices for which all significant outputs are observable, either
directly or indirectly. Fair values of assets and liabilities included in Level
3 valuations are based on inputs that are unobservable and significant to the
overall fair value measurement. These changes will be applied by TransCanada
effective December 31, 2009.
Contractual
Obligations
On August
14, 2009, the Company acquired ConocoPhillips’ remaining interest in Keystone.
As a result, TransCanada assumed responsibility for ConocoPhillips’ share of the
capital investment required to complete the project, which is expected to result
in an incremental commitment of US$1.7 billion through the end of
2012.
Other
than the commitments discussed above and obligations for future debt and
interest payments relating to debt issuances and redemptions discussed in the
“Financing Activities” section of this MD&A, there have been no other
material changes to TransCanada’s contractual obligations from December 31, 2008
to September 30, 2009, including payments due for the next five years and
thereafter. For further information on these contractual obligations, refer to
the MD&A in TransCanada’s 2008 Annual Report.
Financial Instruments and
Risk Management
TransCanada
continues to manage and monitor its exposure to market, counterparty credit and
liquidity risk.
THIRD
QUARTER REPORT 2009 - TRANSCANADA [23
Counterparty
Credit and Liquidity Risk
TransCanada’s
maximum counterparty credit exposure with respect to financial instruments at
the balance sheet date, without taking into account security held, consisted
primarily of the carrying amount, which approximates fair value, of
non-derivative financial assets, such as accounts receivable, as well as the
fair value of derivative assets. Letters of credit and cash are the primary
types of security provided to support these amounts. The Company does not have
significant concentrations of counterparty credit risk with any individual
counterparties and the majority of counterparty credit exposure is with
counterparties who are investment grade. At September 30, 2009, there were no
significant amounts past due or impaired.
As a
level of uncertainty in the global financial markets remains, TransCanada
continues to closely monitor and reassess the creditworthiness of its
counterparties. This has resulted in TransCanada reducing or mitigating its
exposure to certain counterparties where it is deemed warranted and permitted
under contractual terms. As part of its ongoing operations, TransCanada must
balance its market and counterparty credit risks when making business
decisions.
The
Company continues to manage its liquidity risk by ensuring sufficient cash and
credit facilities are available to meet its operating and capital expenditure
obligations when due, under both normal and stressed economic conditions.
Further discussion of the Company’s ability to manage its cash and credit
facilities is provided in the “Liquidity and Capital Resources” section in this
MD&A.
Natural
Gas Inventory
At
September 30, 2009, the fair value of proprietary natural gas inventory held in
storage, as measured using a weighted average of forward prices for the
following four months less selling costs, was $73 million (December 31, 2008 -
$76 million).
The
change in fair value of proprietary natural gas inventory in storage in the
three and nine months ended September 30, 2009 resulted in a net pre-tax
unrealized gain of $16 million and a net pre-tax unrealized loss of $13 million,
respectively (2008 – unrealized losses of $108 million and $6 million,
respectively), which were recorded to Revenues and Inventories. The net
change in fair value of natural gas forward purchase and sales contracts in the
three and nine months ended September 30, 2009 resulted in a net pre-tax
unrealized loss of $2 million and a net pre-tax unrealized gain of $7 million,
respectively (2008 - unrealized gain of $106 million and unrealized loss of $1
million), which were included in Revenues.
Net
Investment in Self-Sustaining Foreign Operations
The
Company hedges its net investment in self-sustaining foreign operations with
U.S. dollar-denominated debt, cross-currency swaps and foreign exchange forward
contracts and options. At September 30, 2009, the Company had designated as a
net investment hedge U.S. dollar-denominated debt with a carrying value of $8.1
billion (US$7.6 billion) and a fair value of $9.2 billion (US$8.6 billion). At
September 30, 2009, Other Assets included $51 million for the fair value of
derivatives used to hedge the Company’s net U.S. dollar investment in foreign
operations.
THIRD
QUARTER REPORT 2009 - TRANSCANADA [24
Information
for the derivatives used to hedge the Company’s net investment in its
self-sustaining foreign operations is as follows:
Derivatives
Hedging Net Investment in Self-Sustaining Foreign Operations
|
September
30, 2009
|
December
31, 2008
|
||||||||||
|
Asset/(Liability)
(unaudited)
(millions
of dollars)
|
Fair
Value(1)
|
Notional
or
Principal
Amount
|
Fair
Value(1)
|
Notional
or
Principal
Amount
|
|||||||
|
U.S.
dollar cross-currency swaps
|
|||||||||||
|
(maturing 2009 to 2014)(2)
|
40 |
U.S.
1,650
|
(218 | ) |
U.S.
1,650
|
||||||
|
U.S.
dollar forward foreign exchange contracts
|
|||||||||||
|
(maturing 2009 to 2010)(2)
|
7 |
U.S.
635
|
(42 | ) |
U.S.
2,152
|
||||||
|
U.S.
dollar options
|
|||||||||||
|
(maturing 2009)(2)
|
4 |
U.S.
400
|
6 |
U.S.
300
|
|||||||
| 51 |
U.S.
2,685
|
(254 | ) |
U.S.
4,102
|
|||||||
|
(1)
|
Fair
values equal carrying values.
|
|
(2)
|
As
at September 30, 2009.
|
Non-Derivative
Financial Instruments Summary
The
carrying and fair values of non-derivative financial instruments were as
follows:
|
September
30, 2009
|
December
31, 2008
|
|||||||||||||||
|
(unaudited)
(millions
of dollars)
|
Carrying
Amount
|
Fair
Value
|
Carrying
Amount
|
Fair
Value
|
||||||||||||
|
Financial Assets(1)
|
||||||||||||||||
|
Cash
and cash equivalents
|
2,406 | 2,406 | 1,308 | 1,308 | ||||||||||||
|
Accounts
receivable and other assets(2)(3)
|
983 | 983 | 1,404 | 1,404 | ||||||||||||
|
Available-for-sale
assets(2)
|
23 | 23 | 27 | 27 | ||||||||||||
| 3,412 | 3,412 | 2,739 | 2,739 | |||||||||||||
|
Financial
Liabilities(1)(3)
|
||||||||||||||||
|
Notes
payable
|
1,324 | 1,324 | 1,702 | 1,702 | ||||||||||||
|
Accounts
payable and deferred amounts(4)
|
1,606 | 1,606 | 1,372 | 1,372 | ||||||||||||
|
Accrued
interest
|
342 | 342 | 359 | 359 | ||||||||||||
|
Long-term
debt and junior subordinated notes
|
18,469 | 21,388 | 17,367 | 16,152 | ||||||||||||
|
Long-term
debt of joint ventures
|
1,090 | 1,149 | 1,076 | 1,052 | ||||||||||||
| 22,831 | 25,809 | 21,876 | 20,637 | |||||||||||||
|
(1)
|
Consolidated
Net Income in 2009 and 2008 included unrealized gains or losses of nil for
the fair value adjustments to each of these financial
instruments.
|
|
(2)
|
At
September 30, 2009, the Consolidated Balance Sheet included financial
assets of $834 million (December 31, 2008 – $1,257 million) in Accounts
Receivable and $172 million (December 31, 2008 - $174 million) in Other
Assets.
|
|
(3)
|
Recorded
at amortized cost.
|
|
(4)
|
At
September 30, 2009, the Consolidated Balance Sheet included financial
liabilities of $1,604 million (December 31, 2008 – $1,350 million) in
Accounts Payable and $2 million (December 31, 2008 - $22 million) in
Deferred Amounts.
|
THIRD
QUARTER REPORT 2009 - TRANSCANADA [25
Derivative
Financial Instruments Summary
Information
for the Company’s derivative financial instruments, excluding hedges of the
Company’s net investment in self-sustaining foreign operations, is as
follows:
|
September
30, 2009
|
|||||||||||||||
|
(unaudited)
(all
amounts in millions unless otherwise indicated)
|
Power
|
Natural
Gas
|
Oil
Products
|
Foreign
Exchange
|
Interest
|
||||||||||
|
Derivative Financial
Instruments Held for Trading(1)
|
|||||||||||||||
|
Fair
Values(2)
|
|||||||||||||||
|
Assets
|
$126
|
$129
|
$4
|
$4
|
$35
|
||||||||||
|
Liabilities
|
$(71
|
)
|
$(134
|
)
|
$(3
|
)
|
$(64
|
)
|
$(81
|
)
|
|||||
|
Notional
Values
|
|||||||||||||||
|
Volumes(3)
|
|||||||||||||||
|
Purchases
|
9,876
|
204
|
180
|
-
|
-
|
||||||||||
|
Sales
|
9,718
|
171
|
228
|
-
|
-
|
||||||||||
|
Canadian dollars
|
-
|
-
|
-
|
-
|
699
|
||||||||||
|
U.S. dollars
|
-
|
-
|
-
|
U.S.
426
|
U.S.
1,425
|
||||||||||
|
Cross-currency
|
-
|
-
|
-
|
227/U.S.
157
|
-
|
||||||||||
|
Net
unrealized (losses)/gains in the period(4)
|
|||||||||||||||
|
Three months ended September 30,
2009
|
$(8
|
)
|
$21
|
$(1
|
)
|
$2
|
$(7
|
)
|
|||||||
|
Nine months ended September 30,
2009
|
$11
|
$(4
|
)
|
$1
|
$4
|
$20
|
|||||||||
|
Net
realized gains/(losses) in the period(4)
|
|||||||||||||||
|
Three months ended September 30,
2009
|
$23
|
$(43
|
)
|
$1
|
$11
|
$(5
|
)
|
||||||||
|
Nine months ended September 30,
2009
|
$53
|
$(56
|
)
|
-
|
$28
|
$(14
|
)
|
||||||||
|
Maturity
dates
|
2009-2014
|
2009-2014
|
2009-2010
|
2009-2012
|
2009-2018
|
||||||||||
|
Derivative Financial
Instruments in Hedging Relationships(5)(6)
|
|||||||||||||||
|
Fair
Values(2)
|
|||||||||||||||
|
Assets
|
$229
|
$2
|
-
|
-
|
$6
|
||||||||||
|
Liabilities
|
$(154
|
)
|
$(15
|
)
|
-
|
$(36
|
)
|
$(67
|
)
|
||||||
|
Notional
Values
|
|||||||||||||||
|
Volumes(3)
|
|||||||||||||||
|
Purchases
|
13,597
|
24
|
-
|
-
|
-
|
||||||||||
|
Sales
|
14,806
|
-
|
-
|
-
|
-
|
||||||||||
|
U.S. dollars
|
-
|
-
|
-
|
-
|
1,825
|
||||||||||
|
Cross-currency
|
-
|
-
|
-
|
136/U.S.
100
|
-
|
||||||||||
|
Net
realized gains/(losses) in the period(4)
|
|||||||||||||||
|
Three months ended September 30,
2009
|
$30
|
$(8
|
)
|
-
|
-
|
$(10
|
)
|
||||||||
|
Nine months ended September 30,
2009
|
$108
|
$(28
|
)
|
-
|
-
|
$(27
|
)
|
||||||||
|
Maturity
dates
|
2009-2015
|
2009-2012
|
n/a
|
2009-
2013
|
2010-2020
|
||||||||||
|
(1)
|
All
derivative financial instruments in the held-for-trading classification
have been entered into for risk management purposes and are subject to the
Company’s risk management strategies, policies and limits. These include
derivatives that have not been designated as hedges or do not qualify for
hedge accounting treatment but have been entered into as economic hedges
to manage the Company’s exposures to market
risk.
|
|
(2)
|
Fair
values equal carrying values.
|
|
(3)
|
Volumes
for power, natural gas and oil products derivatives are in GWh, Bcf and
thousands of barrels, respectively.
|
|
(4)
|
Realized
and unrealized gains and losses on power, natural gas and oil products
derivative financial instruments held for trading are included in
Revenues. Realized and unrealized gains and losses on interest rate and
foreign exchange derivative financial instruments held for trading are
included in Interest Expense and Interest Income and Other, respectively.
The effective portion of unrealized gains and losses on derivative
financial instruments in hedging relationships are initially recognized in
Other Comprehensive Income, and are reclassified to Revenues, Interest
Expense and Interest Income and Other, as appropriate, as the original
hedged item settles.
|
|
(5)
|
All
hedging relationships are designated as cash flow hedges except for
interest rate derivative financial instruments designated as fair value
hedges with a fair value of $6 million and a notional amount of US$150
million. Net realized gains on fair value hedges for the three and nine
months ended September 30, 2009 were $1 million and $3 million, respectively,
and were included in Interest Expense. In third quarter 2009, the Company
did not record any amounts in Net Income related to ineffectiveness for
fair value hedges.
|
THIRD
QUARTER REPORT 2009 - TRANSCANADA [26
|
(6)
|
Net
Income for the three and nine months ended September 30, 2009 included
gains of $1 million and $2 million, 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 underlying positions.
There were no gains or losses included in Net Income for the three and
nine months ended September 30, 2009 for discontinued cash flow hedges. No
amounts have been excluded from the assessment of hedge
effectiveness.
|
|
2008
|
||||||||||||||||
|
(unaudited)
(all
amounts in millions unless otherwise indicated)
|
Power
|
Natural
Gas
|
Oil
Products
|
Foreign
Exchange
|
Interest
|
|||||||||||
|
Derivative
Financial Instruments Held for Trading
|
||||||||||||||||
|
Fair
Values(1)(4)
|
||||||||||||||||
|
Assets
|
$132
|
$144
|
$10
|
$41
|
$57
|
|||||||||||
|
Liabilities
|
$(82
|
)
|
$(150
|
)
|
$(10
|
)
|
$(55
|
)
|
$(117
|
) | ||||||
|
Notional
Values(4)
|
||||||||||||||||
|
Volumes(2)
|
||||||||||||||||
|
Purchases
|
4,035
|
172
|
410
|
-
|
-
|
|||||||||||
|
Sales
|
5,491
|
162
|
252
|
-
|
-
|
|||||||||||
|
Canadian dollars
|
-
|
-
|
-
|
-
|
1,016
|
|||||||||||
|
U.S. dollars
|
-
|
-
|
-
|
U.S.
479
|
U.S.
1,575
|
|||||||||||
|
Japanese yen (in
billions)
|
-
|
-
|
-
|
JPY
4.3
|
-
|
|||||||||||
|
Cross-currency
|
-
|
-
|
-
|
227/
U.S. 157
|
-
|
|||||||||||
|
Net
unrealized gains/(losses) in the period(3)
|
||||||||||||||||
|
Three months ended September 30,
2008
|
$5
|
$(1
|
)
|
-
|
-
|
$5
|
||||||||||
|
Nine months ended September 30,
2008
|
-
|
$(12
|
)
|
-
|
$(7
|
)
|
$3
|
|||||||||
|
Net
realized gains/(losses) in the period(3)
|
||||||||||||||||
|
Three months ended September 30,
2008
|
$12
|
$(11
|
)
|
-
|
$2
|
$2
|
||||||||||
|
Nine months ended September 30,
2008
|
$21
|
$(6
|
)
|
-
|
$12
|
$12
|
||||||||||
|
Maturity
dates(4)
|
2009-2014
|
2009-2011
|
2009
|
2009-2012
|
2009-2018
|
|||||||||||
|
Derivative Financial
Instruments in Hedging Relationships(5)(6)
|
||||||||||||||||
|
Fair
Values(1)(4)
|
||||||||||||||||
|
Assets
|
$115
|
-
|
-
|
$2
|
$8
|
|||||||||||
|
Liabilities
|
$(160
|
)
|
$(18
|
)
|
-
|
$(24
|
)
|
$(122
|
) | |||||||
|
Notional
Values(4)
|
||||||||||||||||
|
Volumes(2)
|
||||||||||||||||
|
Purchases
|
8,926
|
9
|
-
|
-
|
-
|
|||||||||||
|
Sales
|
13,113
|
-
|
-
|
-
|
-
|
|||||||||||
|
Canadian dollars
|
-
|
-
|
-
|
-
|
50
|
|||||||||||
|
U.S. dollars
|
-
|
-
|
-
|
U.S.
15
|
U.S.
1,475
|
|||||||||||
|
Cross-currency
|
-
|
-
|
-
|
136/
U.S. 100
|
-
|
|||||||||||
|
Net
realized gains/(losses) in the period(3)
|
||||||||||||||||
|
Three months ended September 30,
2008
|
$14
|
$(1
|
)
|
-
|
-
|
$(2
|
) | |||||||||
|
Nine months ended September 30,
2008
|
$(24
|
)
|
$18
|
-
|
-
|
$(4
|
) | |||||||||
|
Maturity
dates(4)
|
2009-2014
|
2009-2011
|
n/a
|
2009-2013
|
2009-2019
|
|||||||||||
|
(1)
|
Fair
values equal carrying values.
|
|
(2)
|
Volumes
for power, natural gas and oil products derivatives are in GWh, Bcf and
thousands of barrels, respectively.
|
|
(3)
|
Realized
and unrealized gains and losses on power, natural gas and oil products
derivative financial instruments held for trading are included in
Revenues. Realized and unrealized gains and losses on interest rate and
foreign exchange derivative financial instruments held for trading are
included in Interest Expense and Interest Income and Other, respectively.
The effective portion of unrealized gains and losses on derivative
financial instruments in hedging relationships are initially recognized in
Other Comprehensive Income, and are reclassified to Revenues, Interest
Expense and Interest Income and Other, as appropriate, as the original
hedged item settles.
|
|
(4)
|
As
at December 31, 2008.
|
THIRD
QUARTER REPORT 2009 - TRANSCANADA [27
|
(5)
|
All hedging relationships are designated as cash flow hedges except for interest rate derivative financial instruments designated as fair value hedges with a fair value of $8 million and notional amounts of $50 million and US$50 million at December 31, 2008. Net realized gains on fair value hedges for the three and nine months ended September 30, 2008 were $1 million and $1 million, respectively, and were included in Interest Expense. In third quarter 2008, the Company did not record any amounts in Net Income related to ineffectiveness for fair value hedges. |
|
(6)
|
Net
Income for the three and nine months ended September 30, 2008 included
gains of $7 million and $4 million, 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 underlying positions.
There were no gains or losses included in Net Income for the three and
nine months ended September 30, 2008 for discontinued cash flow hedges. No
amounts have been excluded from the assessment of hedge
effectiveness.
|
Balance
Sheet Presentation of Derivative Financial Instruments
The fair
value of the derivative financial instruments in the Company’s Balance Sheet was
as follows:
|
(unaudited)
|
||||||||
|
(millions
of dollars)
|
September
30, 2009
|
December
31, 2008
|
||||||
|
Current
|
||||||||
|
Other current
assets
|
370 | 318 | ||||||
|
Accounts
payable
|
(359 | ) | (298 | ) | ||||
|
Long-term
|
||||||||
|
Other assets
|
216 | 191 | ||||||
|
Deferred
amounts
|
(266 | ) | (694 | ) | ||||
Other
Risks
Additional
risks faced by the Company are discussed in the MD&A in TransCanada’s 2008
Annual Report. These risks remain substantially unchanged since December 31,
2008.
Controls and
Procedures
As of
September 30, 2009, an evaluation was carried out under the supervision of, and
with the participation of management, including the President and Chief
Executive Officer and the Chief Financial Officer, of the effectiveness of
TransCanada’s disclosure controls and procedures as defined under the rules
adopted by the Canadian securities regulatory authorities and by the SEC. Based
on this evaluation, the President and Chief Executive Officer and the Chief
Financial Officer concluded that the design and operation of TransCanada’s
disclosure controls and procedures were effective as at September 30,
2009.
During
the recent fiscal quarter, there have been no changes in TransCanada’s internal
control over financial reporting that have materially affected, or are
reasonably likely to materially affect, TransCanada’s internal control over
financial reporting. During second quarter 2009, TransCanada completed its
integration of Ravenswood’s internal controls over financial
reporting.
Outlook
TransCanada
does not expect the slowdown in the North American economy to have a material
effect on the Company’s financial position, access to capital markets, committed
projects or corporate strategy.
Since the
disclosure in TransCanada’s 2008 Annual Report, the Company's earnings outlook
for 2009 has declined due to the negative impact of reduced market prices for
power on Energy’s results. With respect to the Pipelines segment, although the
global economic downturn has an impact on throughput on certain pipelines and on
some drilling activities, the short-term financial outlook for the
Company’s Pipelines segment is not expected to be materially impacted as the
pipeline assets are generally underpinned by contracts or earn a regulated rate
of return.
THIRD
QUARTER REPORT 2009 - TRANSCANADA [28
TransCanada
completed the issuance of $550 million of preferred shares in third quarter
2009, $1.8 billion of common shares in second quarter 2009, $3.1 billion of
long-term debt in first quarter 2009 and $1.1 billion of common shares at the
end of 2008. While these offerings will impact future net income and earnings
per share through carrying costs and dilution, when combined with $2.6 billion
of cash provided by operations in the first nine months of 2009, they have
contributed to a cash balance of $2.4 billion at September 30, 2009 and provided
the necessary financing for the Company’s 2009 capital expenditure program and
acquisition of the remaining interest in Keystone. This strategy of
strengthening TransCanada’s liquidity and financial position through its ability
to successfully access capital markets in uncertain economic times has reduced
the Company’s future financing risk around its committed growth program. For
further information on outlook, refer to the MD&A in TransCanada’s 2008
Annual Report.
TransCanada’s
issuer rating assigned by Moody’s Investors Service (Moody’s) is Baa1 with a
stable outlook. TransCanada PipeLines Limited’s senior unsecured debt is rated A
with a stable outlook by DBRS, A3 with a stable outlook by Moody’s and A- with a
stable outlook by Standard and Poor’s (S&P). On September 30, 2009, DBRS and
S&P assigned ratings of Pfd-2 (low) and P-2, respectively, to TransCanada’s
cumulative redeemable first preferred shares, Series 1 and in connection with
the offering, S&P assigned TransCanada an A- long-term corporate credit
rating with a stable outlook.
Recent
Developments
Pipelines
Keystone
On August
14, 2009, TransCanada purchased ConocoPhillips’ remaining 20 per cent ownership
interest in Keystone for US$553 million plus the assumption of US$197 million of
short-term indebtedness. Following this acquisition TransCanada owns 100 per
cent of Keystone and began consolidating Keystone into the Pipelines
segment.
The first
phase of Keystone is currently under construction, extending from Hardisty,
Alberta to serve markets in Wood River and Patoka, Illinois with an initial
nominal capacity of 435,000 barrels per day (bbl/d). Commissioning of this
segment commenced in third quarter 2009 with commercial operations to follow in
first quarter 2010. At September 30, 2009, the first phase was
approximately 90 per cent complete. The second phase of Keystone will expand
nominal capacity to 591,000 bbl/d and extend the pipeline to Cushing, Oklahoma.
Commissioning of the Cushing segment is expected to commence in late 2010. At
September 30, 2009, this phase of the project was approximately 20 per cent
complete.
Keystone
is also currently seeking the necessary regulatory approvals in Canada and the
U.S. to construct and operate an expansion and extension of the pipeline system
that will provide additional capacity of 500,000 bbl/d from Western Canada to
the Gulf Coast in 2012. In September 2009, the NEB held a hearing to review the
application for the Canadian portion of the Keystone Gulf Coast expansion with a
decision expected in early 2010. Permits for the U.S. portion of the
expansion are expected by mid-2010. Construction of the expansion facilities is
anticipated to commence in 2010 following the receipt of all the necessary
regulatory approvals.
THIRD
QUARTER REPORT 2009 - TRANSCANADA [29
The total
capital cost of Keystone is expected to be approximately US$12 billion.
Approximately US$5 billion has been spent to date with the remaining US$7
billion to be invested between now and the end of 2012. Capital costs related to
the construction of Keystone are subject to capital cost risk-and-reward sharing
mechanisms with its customers.
Keystone
is expected to begin generating EBITDA in first quarter 2010 when commercial
operations to Wood River and Patoka, Illinois commence, with EBITDA increasing
through 2011 and 2012 as subsequent phases are placed in service. Based on
current long-term commitments of 910,000 bbl/d, Keystone is expected to generate
EBITDA of approximately US$1.2 billion in 2013, its first full year of
commercial operation serving both the U.S. Midwest and Gulf Coast markets. If
volumes were to increase to 1.1 million bbl/d, the full commercial design of the
system, Keystone would generate approximately US$1.5 billion of annual EBITDA.
In the future, Keystone could be economically expanded from 1.1 million bbl/d to
1.5 million bbl/d in response to additional market demand.
Alberta
System
On
October 30, 2009, following discussions with stakeholders to migrate the
2008-2009 Revenue Requirement Settlement to NEB jurisdiction, TransCanada
submitted an application to the NEB requesting that 2009 interim rates be made
final.
In
September 2009, the Company began construction on the final phase of the North
Central Corridor expansion, which is expected to be complete in April 2010. The
capital cost of this phase of the project is estimated to be approximately $400
million.
Ventures
LP
In
September 2009, the Alberta Court of Appeal granted Ventures LP leave to appeal
the AUC Decision 2009-065 where the AUC announced that it would seek an Order in
Council allowing it to establish a process for regulating rates on the Ventures
LP pipeline. The appeal is expected to be heard during first quarter
2010.
Review
of NEB ROE Formula
In July
2009, the NEB initiated a review of the RH-2-94 Decision by seeking comments on
the continuing applicability of that decision. The RH-2-94 Decision pursuant to
the National Energy Board Act
(Canada) established an ROE formula tied to Government of Canada bond
yields that has formed the basis of determining tolls for pipelines under NEB
jurisdiction since January 1, 1995. In October 2009, the NEB issued a decision
that the RH-2-94 Decision would not continue to be in effect. The NEB stated
that instead of a multi-pipeline approach, the cost of capital will be
determined by negotiations between pipeline companies and their shippers or by
the NEB if a pipeline company files a cost of capital application. This decision
impacts all of TransCanada’s NEB regulated pipelines, which include the Canadian
Mainline, Alberta System and Foothills. The Canadian Mainline is expected to
continue to base its return on the result of the RH-2-94 NEB ROE formula for the
years 2010 and 2011 in accordance with the terms of the current Canadian
Mainline tolls settlement. TransCanada will be working with customers and
interested parties to determine the cost of capital to be used in calculating
tolls for 2010 on its other NEB regulated pipelines. If agreements cannot be
reached, TransCanada will file applications with the NEB requesting an
appropriate cost of capital component.
THIRD
QUARTER REPORT 2009 - TRANSCANADA [30
Energy
Bruce
Power
Progress
continues on the refurbishment and restart of Bruce A Units 1 and 2 with work
now advanced to the re-assembly of the reactors. As at September 30,
2009, Bruce A had incurred approximately $3.1 billion in costs for the
refurbishment and restart of Units 1 and 2 and approximately $0.2 billion for
the refurbishment of Units 3 and 4. TransCanada believes that the work on Units
1 and 2 is now approximately 75 per cent complete, with the bulk of the highly
technical, high risk work now finished. Although a significant amount of work
remains to be done, most of this work is conventional power plant construction
activity.
The
project has experienced delays and TransCanada now expects that Unit 2 will be
restarted mid-2011, with Unit 1 expected to follow approximately four months
thereafter. The impact of this delay is mitigated by the previously announced
extension of the operating lives of Unit 3 to 2011 and Unit 4 to 2016, with
further life extensions expected as additional reactor optimization activities
proceed. TransCanada continues to work closely with Bruce Power to address
productivity and overall project management and notes that there have been
recent, significant successes in this area.
Oakville
On
September 30, 2009, the OPA awarded TransCanada a 20-year Clean Energy Supply
contract to build, own and operate the 900 MW Oakville generating station in
Oakville, Ontario. TransCanada expects to invest approximately $1.2 billion in
the natural gas-fired, combined-cycle plant which is scheduled to start
producing power by the end of 2013. TransCanada expects this project will
deliver an after-tax unlevered rate of return of nine per cent.
Kibby
Wind
In
September 2009, the first phase of the Kibby Wind power project, capable of
producing 66 MW of power, entered the commissioning phase. The 22 turbines
included in this first phase were placed in service on October 30, 2009 on time
and on budget. Construction continues on the 66 MW second phase of the project,
which includes the installation of an additional 22 turbines. This phase is
expected to be in service in third quarter 2010.
Coolidge
In
August, 2009, TransCanada began construction of the US$500 million Coolidge
generating station located near Phoenix, Arizona. The 575 MW, simple-cycle,
natural gas-fired peaking power facility is expected to be in service in second
quarter 2011 on time and on budget. All of the power produced by the facility
will be sold to the Phoenix, Arizona based utility Salt River Project under a
20-year PPA.
Cartier
Wind
In third
quarter 2009, construction activity began on the 212 MW Gros-Morne and 58.5 MW
Montagne-Sèche wind farms. The Montagne-Sèche project and phase one of the
Gros-Morne project (101 MW) are expected to be operational in 2011. Phase two of
the Gros-Morne project (111 MW) is expected to be operational in 2012. These are
the fourth and fifth Québec-based wind farms either operating or under
development by Cartier Wind, which is 62 per cent owned by TransCanada. These
two
wind farms are expected to have a capital cost of approximately $340 million.
Once these two phases are complete, Cartier Wind will be capable of producing
590 MW of electricity. All of the power produced by Cartier Wind is sold to
Hydro-Québec Distribution under a 20-year PPA.
THIRD
QUARTER REPORT 2009 - TRANSCANADA [31
Power
Transmission Line Projects
On
October 13, 2009, TransCanada commenced open seasons on its proposed Zephyr and
Chinook power transmission line projects. The open seasons are scheduled to end
in fourth quarter 2009. Pending successful completion of the open seasons,
regulatory work could commence in fourth quarter 2009, with construction
commencing in 2012 and a potential in-service date of late 2014. Each project
would cost approximately US$3 billion and be capable of delivering 3,000 MW of
power originating in Wyoming and Montana, respectively, to Nevada.
Share
Information
As at
November 3, 2009, TransCanada had 684 million issued and outstanding common
shares. In addition, there were 9 million outstanding options to purchase common
shares, of which 7 million were exercisable as at November 3, 2009.
Selected
Quarterly Consolidated Financial Data(1)
|
(unaudited)
|
2009
|
2008 |
2007
|
||||||||||||||||||||||
|
(millions
of dollars except per share amounts)
|
Third
|
Second
|
First
|
Fourth
|
Third
|
Second
|
First
|
Fourth
|
|||||||||||||||||
|
Revenues
|
2,253 | 2,127 | 2,380 | 2,332 | 2,137 | 2,017 | 2,133 | 2,189 | |||||||||||||||||
|
Net
Income
|
345 | 314 | 334 | 277 | 390 | 324 | 449 | 377 | |||||||||||||||||
|
Share
Statistics
|
|||||||||||||||||||||||||
|
Net
income per common share – Basic
|
$ | 0.50 | $ | 0.50 | $ | 0.54 | $ | 0.47 | $ | 0.67 | $ | 0.58 | $ | 0.83 | $ | 0.70 | |||||||||
|
Net
income per common share – Diluted
|
$ | 0.50 | $ | 0.50 | $ | 0.54 | $ | 0.46 | $ | 0.67 | $ | 0.58 | $ | 0.83 | $ | 0.70 | |||||||||
|
Dividend
declared per common share
|
$ | 0.38 | $ | 0.38 | $ | 0.38 | $ | 0.36 | $ | 0.36 | $ | 0.36 | $ | 0.36 | $ | 0.34 | |||||||||
|
(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 regulated natural gas storage facilities, annual revenues and net
income fluctuate over the long term based on regulators' decisions and
negotiated settlements with shippers. Generally, quarter-over-quarter revenues
and net income 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 volumes on U.S. pipelines, acquisitions and divestitures,
and developments 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 income are affected by seasonal weather
conditions, customer demand, market prices, capacity payments, planned and
unplanned plant outages, acquisitions and divestitures, certain fair value
adjustments and developments outside of the normal course of
operations.
THIRD
QUARTER REPORT 2009 - TRANSCANADA [32
Significant
developments that impacted the last eight quarters' EBIT and Net Income are as
follows:
|
|
·
|
Third
quarter 2009, Energy’s EBIT included net unrealized gains of $14 million
pre-tax ($10 million after tax) due to changes in the fair value of
proprietary natural gas storage inventory and natural gas forward purchase
and sale contracts.
|
|
|
·
|
Second
quarter 2009, Energy’s EBIT included net unrealized losses of $7 million
pre-tax ($5 million after tax) due to changes in the fair value of
proprietary natural gas storage inventory and natural gas forward purchase
and sale contracts. Energy’s EBIT also included contributions from
Portlands Energy, which was placed in service in April
2009.
|
|
|
·
|
First
quarter 2009, Energy’s EBIT included net unrealized losses of $13 million
pre-tax ($9 million after tax) due to changes in the fair value of
proprietary natural gas storage inventory and natural gas forward purchase
and sale contracts.
|
|
|
·
|
Fourth
quarter 2008, Energy’s EBIT included net unrealized gains of $7 million
pre-tax ($6 million after tax) due to changes in the fair value of
proprietary natural gas storage inventory and natural gas forward purchase
and sale contracts. Corporate’s EBIT included net unrealized losses of $57
million pre-tax ($39 million after tax) for changes in the fair value of
derivatives used to manage the Company’s exposure to rising interest rates
but which did not qualify as hedges for accounting
purposes.
|
|
|
·
|
Third
quarter 2008, Energy’s EBIT included contributions from the August 26,
2008 acquisition of Ravenswood. Net Income included favourable income tax
adjustments of $26 million from an internal restructuring and realization
of losses.
|
|
|
·
|
Second
quarter 2008, Energy’s EBIT included net unrealized gains of $12 million
pre-tax ($8 million after tax) due to changes in the fair value of
proprietary natural gas storage inventory and natural gas forward purchase
and sale contracts. In addition, Western Power’s revenues and EBIT
increased due to higher overall realized prices and market heat rates in
Alberta.
|
|
|
·
|
First
quarter 2008, Pipelines’ EBIT included $279 million pre-tax ($152 million
after tax) from the Calpine bankruptcy settlements received by GTN and
Portland, and proceeds of $17 million pre-tax ($10 million after tax) from
a lawsuit settlement. Energy’s EBIT included a writedown of $41 million
pre-tax ($27 million after tax) of costs related to the Broadwater LNG
project and net unrealized losses of $17 million pre-tax ($12 million
after tax) due to changes in the fair value of proprietary natural gas
storage inventory and natural gas forward purchase and sale
contracts.
|
|
|
·
|
Fourth
quarter 2007, Net Income included $56 million of favourable income tax
adjustments resulting from reductions in Canadian federal income tax rates
and other legislative changes. Pipelines’ EBIT increased as a result of
recording incremental earnings related to a rate case settlement reached
for the GTN System, effective January 1, 2007. Energy’s EBIT increased due
to a $16 million pre-tax ($14 million after tax) gain on sale of land
previously held for development. Energy’s EBIT included net unrealized
gains of $15 million pre-tax ($10 million after tax) due to changes in the
fair value of proprietary natural gas storage inventory and natural gas
forward purchase and sale
contracts.
|
EXHIBIT
13.2
Consolidated
Income
|
(unaudited)
|
|||||||||||||||||
|
(millions
of dollars except number of shares and
|
Three
months ended September 30
|
Nine
months ended September 30
|
|||||||||||||||
|
per
share amounts)
|
2009
|
2008
|
2009
|
2008
|
|||||||||||||
|
Revenues
|
2,253
|
2,137
|
6,760
|
6,287
|
|||||||||||||
|
Operating
and Other Expenses/(Income)
|
|||||||||||||||||
|
Plant
operating costs and other
|
879
|
750
|
2,544
|
2,181
|
|||||||||||||
|
Commodity
purchases resold
|
371
|
324
|
1,100
|
1,053
|
|||||||||||||
|
Other
income
|
(5
|
)
|
(1
|
)
|
(20
|
)
|
(38
|
)
|
|||||||||
|
Calpine
bankruptcy settlements
|
-
|
-
|
-
|
(279
|
)
|
||||||||||||
|
Writedown
of Broadwater LNG project costs
|
-
|
-
|
-
|
41
|
|||||||||||||
|
1,245
|
1,073
|
3,624
|
2,958
|
||||||||||||||
|
1,008
|
1,064
|
3,136
|
3,329
|
||||||||||||||
|
Depreciation
and amortization
|
343
|
318
|
1,034
|
943
|
|||||||||||||
|
665
|
746
|
2,102
|
2,386
|
||||||||||||||
|
Financial
Charges/(Income)
|
|||||||||||||||||
|
Interest
expense
|
216
|
213
|
770
|
617
|
|||||||||||||
|
Financial
charges of joint ventures
|
17
|
18
|
47
|
51
|
|||||||||||||
|
Interest
income and other
|
(43
|
)
|
(22
|
)
|
(99
|
)
|
(58
|
)
|
|||||||||
|
190
|
209
|
718
|
610
|
||||||||||||||
|
Income
before Income Taxes and Non-Controlling Interests
|
475
|
537
|
1,384
|
1,776
|
|||||||||||||
|
Income
Taxes
|
|||||||||||||||||
|
Current
|
14
|
127
|
103
|
479
|
|||||||||||||
|
Future
|
93
|
2
|
217
|
28
|
|||||||||||||
|
107
|
129
|
320
|
507
|
||||||||||||||
|
Non-Controlling
Interests
|
|||||||||||||||||
|
Preferred
share dividends of subsidiary
|
6
|
6
|
17
|
17
|
|||||||||||||
|
Non-controlling
interest in PipeLines LP
|
19
|
12
|
51
|
46
|
|||||||||||||
|
Non-controlling
interest in Portland
|
(2
|
)
|
-
|
3
|
43
|
||||||||||||
|
23
|
18
|
71
|
106
|
||||||||||||||
|
Net
Income
|
345
|
390
|
993
|
1,163
|
|||||||||||||
|
Net
Income Per Common Share - Basic and Diluted
|
$0.50
|
$0.67
|
$1.55
|
$2.07
|
|||||||||||||
|
Average Common Shares
Outstanding – Basic (millions)
|
681
|
579
|
641
|
560
|
|||||||||||||
|
Average Common Shares
Outstanding – Diluted (millions)
|
682
|
581
|
642
|
562
|
|||||||||||||
See
accompanying notes to the consolidated financial statements.
THIRD
QUARTER REPORT 2009 - TRANSCANADA [34
Consolidated
Cash Flows
|
Three
months ended September 30
|
Nine
months ended September 30
|
||||||||||||
|
(unaudited)(millions
of dollars)
|
2009
|
2008
|
2009
|
2008
|
|||||||||
|
Cash
Generated From Operations
|
|||||||||||||
|
Net
income
|
345
|
390
|
993
|
1,163
|
|||||||||
|
Depreciation
and amortization
|
343
|
318
|
1,034
|
943
|
|||||||||
|
Future
income taxes
|
93
|
2
|
217
|
28
|
|||||||||
|
Non-controlling
interests
|
23
|
18
|
71
|
106
|
|||||||||
|
Employee
future benefits funding (in excess of)/lower than expense
|
(22
|
)
|
10
|
(79
|
)
|
23
|
|||||||
|
Writedown
of Broadwater LNG project costs
|
-
|
-
|
-
|
41
|
|||||||||
|
Other
|
(10
|
)
|
(27
|
)
|
(6
|
)
|
5
|
||||||
|
772
|
711
|
2,230
|
2,309
|
||||||||||
|
(Increase)/decrease
in operating working capital
|
(31
|
)
|
114
|
362
|
16
|
||||||||
|
Net
cash provided by operations
|
741
|
825
|
2,592
|
2,325
|
|||||||||
|
Investing
Activities
|
|||||||||||||
|
Capital
expenditures
|
(1,557
|
)
|
(806
|
)
|
(3,943
|
)
|
(1,899
|
)
|
|||||
|
Acquisitions,
net of cash acquired
|
(653
|
)
|
(3,054
|
)
|
(902
|
)
|
(3,058
|
)
|
|||||
|
Disposition
of assets, net of current income taxes
|
-
|
21
|
-
|
21
|
|||||||||
|
Deferred
amounts and other
|
(190
|
)
|
58
|
(529
|
)
|
157
|
|||||||
|
Net
cash used in investing activities
|
(2,400
|
)
|
(3,781
|
)
|
(5,374
|
)
|
(4,779
|
)
|
|||||
|
Financing
Activities
|
|||||||||||||
|
Dividends
on common shares
|
(186
|
)
|
(143
|
)
|
(535
|
)
|
(410
|
)
|
|||||
|
Distributions
paid to non-controlling interests
|
(25
|
)
|
(24
|
)
|
(76
|
)
|
(110
|
)
|
|||||
|
Notes
payable issued/(repaid), net
|
77
|
(258
|
)
|
(607
|
)
|
466
|
|||||||
|
Long-term
debt issued, net of issue costs
|
207
|
2,085
|
3,267
|
2,197
|
|||||||||
|
Reduction
of long-term debt
|
(9
|
)
|
(15
|
)
|
(509
|
)
|
(788
|
)
|
|||||
|
Long-term
debt of joint ventures issued
|
93
|
123
|
201
|
157
|
|||||||||
|
Reduction
of long-term debt of joint ventures
|
(52
|
)
|
(44
|
)
|
(108
|
)
|
(101
|
)
|
|||||
|
Preferred
shares issued, net of issue costs
|
539
|
-
|
539
|
-
|
|||||||||
|
Common
shares issued, net of issue costs
|
2
|
6
|
1,805
|
1,252
|
|||||||||
|
Net
cash provided by financing activities
|
646
|
1,730
|
3,977
|
2,663
|
|||||||||
|
Effect
of Foreign Exchange Rate Changes on Cash and Cash
Equivalents
|
(63
|
)
|
19
|
(97
|
)
|
39
|
|||||||
|
(Decrease)/Increase
in Cash and Cash Equivalents
|
(1,076
|
)
|
(1,207
|
)
|
1,098
|
248
|
|||||||
|
Cash
and Cash Equivalents
|
|||||||||||||
|
Beginning
of period
|
3,482
|
1,959
|
1,308
|
504
|
|||||||||
|
Cash
and Cash Equivalents
|
|||||||||||||
|
End
of period
|
2,406
|
752
|
2,406
|
752
|
|||||||||
|
Supplementary
Cash Flow Information
|
|||||||||||||
|
Income
taxes (refunded)/paid
|
(63
|
)
|
106
|
50
|
418
|
||||||||
|
Interest
paid
|
297
|
177
|
834
|
658
|
|||||||||
See
accompanying notes to the consolidated financial statements.
THIRD
QUARTER REPORT 2009 - TRANSCANADA [35
Consolidated
Balance Sheet
|
September
30,
|
December
31,
|
||||||
|
(unaudited)(millions
of dollars)
|
2009
|
2008
|
|||||
|
ASSETS
|
|||||||
|
Current
Assets
|
|||||||
|
Cash
and cash equivalents
|
2,406
|
1,308
|
|||||
|
Accounts
receivable
|
834
|
1,280
|
|||||
|
Inventories
|
491
|
489
|
|||||
|
Other
|
505
|
523
|
|||||
|
4,236
|
3,600
|
||||||
|
Plant,
Property and Equipment
|
32,289
|
29,189
|
|||||
|
Goodwill
|
3,855
|
4,397
|
|||||
|
Regulatory
Assets
|
1,644
|
201
|
|||||
|
Other
Assets
|
2,132
|
2,027
|
|||||
|
44,156
|
39,414
|
||||||
|
LIABILITIES
AND SHAREHOLDERS’ EQUITY
|
|||||||
|
Current
Liabilities
|
|||||||
|
Notes
payable
|
1,324
|
1,702
|
|||||
|
Accounts
payable
|
2,350
|
1,876
|
|||||
|
Accrued
interest
|
342
|
359
|
|||||
|
Current
portion of long-term debt
|
678
|
786
|
|||||
|
Current
portion of long-term debt of joint ventures
|
235
|
207
|
|||||
|
4,929
|
4,930
|
||||||
|
Regulatory
Liabilities
|
430
|
551
|
|||||
|
Deferred
Amounts
|
723
|
1,168
|
|||||
|
Future
Income Taxes
|
2,784
|
1,223
|
|||||
|
Long-Term
Debt
|
16,730
|
15,368
|
|||||
|
Long-Term
Debt of Joint Ventures
|
855
|
869
|
|||||
|
Junior
Subordinated Notes
|
1,061
|
1,213
|
|||||
|
27,512
|
25,322
|
||||||
|
Non-Controlling
Interests
|
|||||||
|
Non-controlling
interest in PipeLines LP
|
561
|
721
|
|||||
|
Preferred
shares of subsidiary
|
389
|
389
|
|||||
|
Non-controlling
interest in Portland
|
77
|
84
|
|||||
|
1,027
|
1,194
|
||||||
|
Shareholders’
Equity
|
15,617
|
12,898
|
|||||
|
44,156
|
39,414
|
See
accompanying notes to the consolidated financial statements.
THIRD
QUARTER REPORT 2009 - TRANSCANADA [36
Consolidated
Comprehensive Income
|
Three
months ended
September
30
|
Nine
months ended
September
30
|
||||||||||||
|
(unaudited)(millions
of dollars)
|
2009
|
2008
|
2009
|
2008
|
|||||||||
|
Net
Income
|
345
|
390
|
993
|
1,163
|
|||||||||
|
Other
Comprehensive (Loss)/Income, Net of Income
Taxes
|
|||||||||||||
|
Change in foreign currency
translation gains and losses
on investments in foreign operations(1)
|
(230
|
)
|
107
|
(381
|
)
|
146
|
|||||||
|
Change in gains and losses on
hedges of investments
in foreign operations(2)
|
113
|
(79
|
)
|
209
|
(103
|
)
|
|||||||
|
Change in gains and losses on
derivative instruments
designated as cash flow hedges(3)
|
16
|
7
|
80
|
40
|
|||||||||
|
Reclassification to net income
of gains and losses on
derivative instruments designated as cash
flow hedges pertaining to prior periods(4)
|
(1
|
)
|
(6
|
)
|
(6
|
)
|
(24
|
)
|
|||||
|
Other Comprehensive
(Loss)/Income
|
(102
|
)
|
29
|
(98
|
)
|
59
|
|||||||
|
Comprehensive
Income
|
243
|
419
|
895
|
1,222
|
|||||||||
|
(1)
|
Net
of income tax expense of $68 million and $68 million for the three and
nine months ended September 30, 2009, respectively (2008 – recovery of $23
million and $43 million,
respectively).
|
|
(2)
|
Net
of income tax expense of $50 million and $102 million for the three and
nine months ended September 30, 2009, respectively (2008 – recovery of $36
million and $50 million,
respectively).
|
|
(3)
|
Net
of income tax expense of $4 million and $20 million for the three and nine
months ended September 30, 2009, respectively (2008 – $25 million recovery
and $24 million expense,
respectively).
|
|
(4)
|
Net
of income tax expense of $4 million and $4 million for the three and nine
months ended September 30, 2009, respectively (2008 – recovery of $9
million and $20 million,
respectively).
|
See
accompanying notes to the consolidated financial statements.
THIRD
QUARTER REPORT 2009 - TRANSCANADA [37
Consolidated
Accumulated Other Comprehensive Income
|
Currency
|
Cash
Flow
|
|||||||||
|
Translation
|
Hedges
and
|
|||||||||
|
(unaudited)(millions
of dollars)
|
Adjustments
|
Other
|
Total
|
|||||||
|
Balance
at December 31, 2008
|
(379
|
)
|
(93
|
)
|
(472
|
)
|
||||
|
Change
in foreign currency translation gains and losses on investments in foreign
operations(1)
|
(381
|
)
|
-
|
(381
|
)
|
|||||
|
Change
in gains and losses on hedges of investments in foreign operations(2)
|
209
|
-
|
209
|
|||||||
|
Change
in gains and losses on derivative instruments designated as cash flow
hedges(3)
|
-
|
80
|
80
|
|||||||
|
Reclassification
to net income of gains and losses on derivative instruments designated as
cash flow hedges pertaining to prior periods(4)(5)
|
-
|
(6
|
)
|
(6
|
)
|
|||||
|
Balance
at September 30, 2009
|
(551
|
)
|
(19
|
)
|
(570
|
)
|
||||
|
Balance
at December 31, 2007
|
(361
|
)
|
(12
|
)
|
(373
|
)
|
||||
|
Change
in foreign currency translation gains and losses on investments in foreign
operations(1)
|
146
|
-
|
146
|
|||||||
|
Change
in gains and losses on hedges of investments in foreign operations(2)
|
(103
|
)
|
-
|
(103
|
)
|
|||||
|
Change
in gains and losses on derivative instruments designated as cash flow
hedges(3)
|
-
|
40
|
40
|
|||||||
|
Reclassification
to net income of gains and losses on derivative instruments designated as
cash flow hedges pertaining to prior periods(4)
|
-
|
(24
|
)
|
(24
|
)
|
|||||
|
Balance
at September 30, 2008
|
(318
|
)
|
4
|
(314
|
)
|
|
(1)
|
Net
of income tax expense of $68 million for the nine months ended September
30, 2009 (2008 - $43 million
recovery).
|
|
(2)
|
Net
of income tax expense of $102 million for the nine months ended September
30, 2009 (2008 - $50 million
recovery).
|
|
(3)
|
Net
of income tax expense of $20 million for the nine months ended September
30, 2009 (2008 - $24 million
expense).
|
|
(4)
|
Net
of income tax expense of $4 million for the nine months ended September
30, 2009 (2008 - $20 million
recovery).
|
|
(5)
|
The
amount of gains related to cash flow hedges reported in Accumulated Other
Comprehensive Income that is expected to be reclassified to Net Income in
the next 12 months is estimated to be $30 million ($25 million, net of
tax). These estimates assume constant commodity prices, interest rates and
foreign exchange rates over time, however, the amounts reclassified will
vary based on the actual value of these factors at the date of
settlement.
|
See
accompanying notes to the consolidated financial statements.
THIRD
QUARTER REPORT 2009 - TRANSCANADA [38
Consolidated
Shareholders’ Equity
|
Nine
months ended September 30
|
|||||||
|
(unaudited)(millions
of dollars)
|
2009
|
2008
|
|||||
|
Common
Shares
|
|||||||
|
Balance at beginning of
period
|
9,264
|
6,662
|
|||||
|
Proceeds from shares issued under public offering, net of issue
costs
|
1,792
|
1,235
|
|||||
|
Shares issued under dividend
reinvestment plan
|
182
|
177
|
|||||
|
Proceeds from shares issued on exercise of
stock options
|
13
|
17
|
|||||
|
Balance at end of
period
|
11,251
|
8,091
|
|||||
|
Preferred
Shares
|
|||||||
|
Balance at beginning of
period
|
-
|
-
|
|||||
|
Proceeds from shares issued
under public offering, net of issue costs
|
539
|
-
|
|||||
|
Balance at end of
period
|
539
|
-
|
|||||
|
Contributed
Surplus
|
|||||||
|
Balance at beginning of
period
|
279
|
276
|
|||||
|
Increased ownership in
PipeLines LP (Note 8)
|
49
|
-
|
|||||
|
Issuance of stock
options
|
3
|
2
|
|||||
|
Balance at end of
period
|
331
|
278
|
|||||
|
Retained
Earnings
|
|||||||
|
Balance at beginning of
period
|
3,827
|
3,220
|
|||||
|
Net income
|
993
|
1,163
|
|||||
|
Common share
dividends
|
(754
|
)
|
(612
|
)
|
|||
|
Balance at end of
period
|
4,066
|
3,771
|
|||||
|
Accumulated
Other Comprehensive Income
|
|||||||
|
Balance at beginning of
period
|
(472
|
)
|
(373
|
)
|
|||
|
Other comprehensive
income
|
(98
|
)
|
59
|
||||
|
Balance at end of
period
|
(570
|
)
|
(314
|
)
|
|||
|
3,496
|
3,457
|
||||||
|
Total
Shareholders’ Equity
|
15,617
|
11,826
|
|||||
See
accompanying notes to the consolidated financial statements.
THIRD
QUARTER REPORT 2009 - TRANSCANADA [39
Notes
to Consolidated Financial Statements
(Unaudited)
|
1.
|
Significant
Accounting Policies
|
The
consolidated financial statements of TransCanada Corporation (TransCanada 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 TransCanada's annual audited Consolidated Financial
Statements for the year ended December 31, 2008, except as described in Note 2.
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 2008
audited Consolidated Financial Statements included in TransCanada’s 2008 Annual
Report. Unless otherwise indicated, “TransCanada“ or “the Company“ includes
TransCanada Corporation and its subsidiaries. Amounts are stated in Canadian
dollars unless otherwise indicated. Certain comparative figures have been
reclassified to conform with the current year’s presentation.
In
Pipelines, which consists primarily of the Company's investments in regulated
pipelines and regulated natural gas storage facilities, annual revenues and net
income fluctuate over the long term based on regulators' decisions and
negotiated settlements with shippers. Generally, quarter-over-quarter revenues
and net income 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 volumes on U.S. pipelines, acquisitions and divestitures,
and developments 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 income are affected by seasonal weather
conditions, customer demand, market prices, capacity payments, planned and
unplanned plant outages, acquisitions and divestitures, certain fair value
adjustments and developments outside of the normal course of
operations.
In
preparing these financial statements, TransCanada is required to make estimates
and assumptions that affect both the amount and timing of recording assets,
liabilities, revenues and expenses as the determination of these items may be
dependent on future events. The Company uses the most current information
available and exercises careful judgement in making these 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
|
The
Company’s accounting policies have not changed materially from those described
in TransCanada’s 2008 Annual Report except as follows:
THIRD
QUARTER REPORT 2009 - TRANSCANADA [40
2009
Accounting Changes
Rate-Regulated
Operations
Effective
January 1, 2009, the temporary exemption was withdrawn from the Canadian
Institute of Chartered Accountants (CICA) Handbook Section 1100 “Generally
Accepted Accounting Principles”, which permitted the recognition and measurement
of assets and liabilities arising from rate regulation. In addition, Section
3465 “Income Taxes” was amended to require the recognition of future income tax
assets and liabilities for rate-regulated entities. The Company chose to adopt
accounting policies consistent with the U.S. Financial Accounting Standards
Board’s Financial Accounting Standard (FAS) 71 “Accounting for the Effects of
Certain Types of Regulation”. As a result, TransCanada retained its current
method of accounting for its rate-regulated operations, except that TransCanada
is required to recognize future income tax assets and liabilities, instead of
using the taxes payable method, and records an offsetting adjustment to
regulatory assets and liabilities. As a result of adopting this accounting
change, additional future income tax liabilities and a regulatory asset in the
amount of $1.4 billion were recorded January 1, 2009 in each of Future Income
Taxes and Regulatory Assets, respectively.
Adjustments
to the 2009 financial statements have been made in accordance with the
transitional provisions for Section 3465, which required a cumulative adjustment
in the current period to Future Income Taxes and Regulatory Assets. Restatement
of prior periods’ financial statements was not permitted under Section
3465.
Intangible
Assets
Effective
January 1, 2009, the Company adopted CICA Handbook Section 3064 “Goodwill and
Intangible Assets”, which replaced Section 3062 “Goodwill and Other Intangible
Assets”. Section 3064 gives guidance on the recognition of intangible assets as
well as the recognition and measurement of internally developed intangible
assets. In addition, Section 3450 “Research and Development Costs” was withdrawn
from the CICA Handbook. Adopting this accounting change did not have a material
effect on the Company’s financial statements.
Credit
Risk and the Fair Value of Financial Assets and Financial
Liabilities
Effective
January 1, 2009, the Company adopted the accounting provisions of Emerging
Issues Committee (EIC) Abstract EIC 173, “Credit Risk and the Fair Value of
Financial Assets and Financial Liabilities”. Under EIC 173 an entity’s own
credit risk and the credit risk of its counterparties is taken into account in
determining the fair value of financial assets and financial liabilities,
including derivative instruments. Adopting this accounting change did not have a
material effect on the Company’s financial statements.
Future Accounting
Changes
International
Financial Reporting Standards
The
CICA’s Accounting Standards Board announced that Canadian publicly accountable
enterprises are required to adopt International Financial Reporting Standards
(IFRS), as issued by the International Accounting Standards Board (IASB),
effective January 1, 2011. The Company will prepare its financial statements
under IFRS commencing January 1, 2011.
Under
existing Canadian GAAP, TransCanada follows specific accounting policies unique
to a rate-regulated business. TransCanada is actively monitoring developments
regarding potential future guidance on the applicability of certain aspects of
rate-regulated accounting under IFRS. Developments in this area could have a
significant effect on the scope of the Company’s IFRS project and on
TransCanada’s financial results under
IFRS. On July 23, 2009, the IASB issued an exposure draft “Rate-regulated
Activities” and the Company is assessing the impact of this exposure draft on
TransCanada.
THIRD
QUARTER REPORT 2009 - TRANSCANADA [41
At the
current stage of its IFRS project, TransCanada cannot reasonably determine the
full impact that adopting IFRS would have on its financial position and future
results.
Financial
Instruments Disclosure
The CICA
implemented revisions to Handbook Section 3862 “Financial Instruments –
Disclosures” for fiscal years ending after September 30, 2009. These revisions
are intended to align the disclosure requirements for financial instruments to
the maximum extent possible with the disclosure required under IFRS. These
revisions require additional disclosure based on a three level hierarchy that
reflects the significance of inputs used in measuring fair value. Fair values of
assets and liabilities included in Level 1 are determined by reference to quoted
prices in active markets for identical assets and liabilities. Fair values of
assets and liabilities included in Level 2 include valuations using inputs other
than quoted prices for which all significant outputs are observable, either
directly or indirectly. Fair values of assets and liabilities included in Level
3 valuations are based on inputs that are unobservable and significant to the
overall fair value measurement. These changes will be applied by TransCanada
effective December 31, 2009.
|
3.
|
Segmented
Information
|
Effective
January 1, 2009, TransCanada revised its presentation of certain income and
expense items in the Consolidated Statement of Income to better reflect the
operating and financing structure of the Company. To conform with the new
presentation, certain of the income and expense amounts pertaining to operations
that were previously classified on the Consolidated Income Statement as Other
Expenses/(Income) are now included in Operating and Other Expenses/(Income).
Depreciation expense has been redefined as Depreciation and Amortization expense
and includes amortization of $14 million and $43 million in the three and nine
months ended September 30, 2009, respectively (2008 - $14 million and $43
million, respectively), for power purchase arrangements, which was previously
included in Commodity Purchases Resold. Support services costs previously
allocated to Pipelines and Energy of $25 million and $87 million in the three
and nine months ended September 30, 2009, respectively (2008 - $24 million
and $75 million, respectively), are now included in Corporate. In addition,
amounts related to Interest Expense and Financial Charges of Joint Ventures,
Interest Income and Other, Income Taxes and Non-Controlling Interests are no
longer reported on a segmented basis. Segmented information has been
retroactively reclassified to reflect these changes. These changes had no
impact on reported consolidated Net Income.
THIRD
QUARTER REPORT 2009 - TRANSCANADA [42
|
Three
months ended September 30
|
Pipelines
|
Energy
|
Corporate
|
Total
|
||||||||||||||||
|
(unaudited)(millions
of dollars)
|
2009
|
2008
|
2009
|
2008
|
2009
|
2008
|
2009
|
2008
|
||||||||||||
|
Revenues
|
1,152
|
1,141
|
1,101
|
996
|
-
|
-
|
2,253
|
2,137
|
||||||||||||
|
Plant
operating costs and other
|
(427
|
)
|
(421
|
)
|
(424
|
)
|
(306
|
)
|
(28
|
)
|
(23
|
)
|
(879
|
)
|
(750
|
)
|
||||
|
Commodity
purchases resold
|
-
|
-
|
(371
|
)
|
(324
|
)
|
-
|
-
|
(371
|
)
|
(324
|
)
|
||||||||
|
Other
income/(expense)
|
5
|
3
|
-
|
(2
|
)
|
-
|
-
|
5
|
1
|
|||||||||||
|
730
|
723
|
306
|
364
|
(28
|
)
|
(23
|
)
|
1,008
|
1,064
|
|||||||||||
|
Depreciation
and amortization
|
(255
|
)
|
(254
|
)
|
(88
|
)
|
(64
|
)
|
-
|
-
|
(343
|
)
|
(318
|
)
|
||||||
|
475
|
469
|
218
|
300
|
(28
|
)
|
(23
|
)
|
665
|
746
|
|||||||||||
|
Interest
expense
|
(216
|
)
|
(213
|
)
|
||||||||||||||||
|
Financial
charges of joint ventures
|
(17
|
)
|
(18
|
)
|
||||||||||||||||
|
Interest
income and other
|
43
|
22
|
||||||||||||||||||
|
Income
taxes
|
(107
|
)
|
(129
|
)
|
||||||||||||||||
|
Non-controlling
interests
|
(23
|
)
|
(18
|
)
|
||||||||||||||||
|
Net
Income
|
345
|
390
|
||||||||||||||||||
|
Nine
months ended September 30
|
Pipelines
|
Energy
|
Corporate
|
Total
|
||||||||||||||||
|
(unaudited)(millions
of dollars)
|
2009
|
2008
|
2009
|
2008
|
2009
|
2008
|
2009
|
2008
|
||||||||||||
|
Revenues
|
3,558
|
3,417
|
3,202
|
2,870
|
-
|
-
|
6,760
|
6,287
|
||||||||||||
|
Plant
operating costs and other
|
(1,227
|
)
|
(1,194
|
)
|
(1,227
|
)
|
(910
|
)
|
(90
|
)
|
(77
|
)
|
(2,544
|
)
|
(2,181
|
)
|
||||
|
Commodity
purchases resold
|
-
|
-
|
(1,100
|
)
|
(1,053
|
)
|
-
|
-
|
(1,100
|
)
|
(1,053
|
)
|
||||||||
|
Other
income/(expense)
|
17
|
33
|
2
|
(1
|
)
|
1
|
6
|
20
|
38
|
|||||||||||
|
Calpine
bankruptcy settlements
|
-
|
279
|
-
|
-
|
-
|
-
|
-
|
279
|
||||||||||||
|
Writedown
of Broadwater LNG project costs
|
-
|
-
|
-
|
(41
|
)
|
-
|
-
|
-
|
(41
|
)
|
||||||||||
|
2,348
|
2,535
|
877
|
865
|
(89
|
)
|
(71
|
)
|
3,136
|
3,329
|
|||||||||||
|
Depreciation
and amortization
|
(773
|
)
|
(765
|
)
|
(261
|
)
|
(178
|
)
|
-
|
-
|
(1,034
|
)
|
(943
|
)
|
||||||
|
1,575
|
1,770
|
616
|
687
|
(89
|
)
|
(71
|
)
|
2,102
|
2,386
|
|||||||||||
|
Interest
expense
|
(770
|
)
|
(617
|
)
|
||||||||||||||||
|
Financial
charges of joint ventures
|
(47
|
)
|
(51
|
)
|
||||||||||||||||
|
Interest
income and other
|
99
|
58
|
||||||||||||||||||
|
Income
taxes
|
(320
|
)
|
(507
|
)
|
||||||||||||||||
|
Non-controlling
interests
|
(71
|
)
|
(106
|
)
|
||||||||||||||||
|
Net
Income
|
993
|
1,163
|
||||||||||||||||||
THIRD
QUARTER REPORT 2009 - TRANSCANADA [43
For the
years ended December 31, 2008 and 2007, segmented information has been
retroactively reclassified to reflect all changes.
|
For
the year ended December 31
|
Pipelines
|
Energy
|
Corporate
|
Total
|
||||||||||||||||
|
(unaudited)(millions
of dollars)
|
2008
|
2007
|
2008
|
2007
|
2008
|
2007
|
2008
|
2007
|
||||||||||||
|
Revenues
|
4,650
|
4,712
|
3,969
|
4,116
|
-
|
-
|
8,619
|
8,828
|
||||||||||||
|
Plant
operating costs and other
|
(1,645
|
)
|
(1,590
|
)
|
(1,307
|
)
|
(1,336
|
)
|
(110
|
)
|
(104
|
)
|
(3,062
|
)
|
(3,030
|
)
|
||||
|
Commodity
purchases resold
|
-
|
(72
|
)
|
(1,453
|
)
|
(1,829
|
)
|
-
|
-
|
(1,453
|
)
|
(1,901
|
)
|
|||||||
|
Calpine
bankruptcy settlements
|
279
|
-
|
-
|
16
|
-
|
-
|
279
|
16
|
||||||||||||
|
Writedown
of Broadwater LNG project costs
|
-
|
-
|
(41
|
)
|
-
|
-
|
-
|
(41
|
)
|
-
|
||||||||||
|
Other
income
|
31
|
27
|
1
|
3
|
6
|
2
|
38
|
32
|
||||||||||||
|
3,315
|
3,077
|
1,169
|
970
|
(104
|
)
|
(102
|
)
|
4,380
|
3,945
|
|||||||||||
|
Depreciation
and amortization
|
(989
|
)
|
(1,021
|
)
|
(258
|
)
|
(216
|
)
|
-
|
-
|
(1,247
|
)
|
(1,237
|
)
|
||||||
|
2,326
|
2,056
|
911
|
754
|
(104
|
)
|
(102
|
)
|
3,133
|
2,708
|
|||||||||||
|
Interest
expense
|
(943
|
)
|
(943
|
)
|
||||||||||||||||
|
Financial
charges of joint ventures
|
(72
|
)
|
(75
|
)
|
||||||||||||||||
|
Interest
income and other
|
54
|
120
|
||||||||||||||||||
|
Income
taxes
|
(602
|
)
|
(490
|
)
|
||||||||||||||||
|
Non-controlling
interests
|
(130
|
)
|
(97
|
)
|
||||||||||||||||
|
Net
Income
|
1,440
|
1,223
|
||||||||||||||||||
Total
Assets
|
(unaudited)(millions
of dollars)
|
September
30, 2009
|
December
31, 2008
|
|||||
|
Pipelines
|
28,895
|
25,020
|
|||||
|
Energy
|
12,078
|
12,006
|
|||||
|
Corporate
|
3,183
|
2,388
|
|||||
|
44,156
|
39,414
|
|
4.
|
Long-Term
Debt
|
On
October 20, 2009, the Company retired $250 million of 10.625 per cent
debentures.
In April
2009, TCPL filed a $2.0 billion Canadian Medium-Term Notes shelf prospectus to
replace a March 2007 $1.5 billion Canadian Medium-Term Notes shelf prospectus,
which expired in April 2009. No amounts have been issued under this shelf
prospectus.
In
February 2009, TCPL issued Medium-Term Notes of $300 million and $400 million
maturing in February 2014 and February 2039, respectively, and bearing interest
at 5.05 per cent and 8.05 per cent, respectively. These notes were issued under
the $1.5 billion debt shelf prospectus filed in March 2007.
In
January 2009, TCPL issued Senior Unsecured Notes of US$750 million and US$1.25
billion maturing in January 2019 and January 2039, respectively, and bearing
interest at 7.125 per cent and 7.625 per cent, respectively. These notes were
issued under a US$3.0 billion debt shelf prospectus filed in January 2009, which
has remaining capacity of US$1.0 billion.
In the
three and nine months ended September 30, 2009, the Company capitalized interest
related to capital projects of $113 million and $230 million, respectively (2008
- - $38 million and $97 million, respectively).
THIRD
QUARTER REPORT 2009 - TRANSCANADA [44
|
5.
|
Share
Capital
|
On
September 30, 2009, TransCanada completed a public offering of 22 million
cumulative redeemable first preferred shares under the September 21, 2009
prospectus, discussed below, for gross proceeds of $550 million. The holders of
the preferred shares are entitled to receive fixed cumulative dividends at an
annual rate of $1.15 per share, payable quarterly, yielding 4.6 per cent per
annum, for the initial five-year period ending December 31, 2014, with the first
dividend payment date scheduled for December 31, 2009. The dividend rate will
reset on December 31, 2014 and every five years thereafter to a yield per annum
equal to the then sum of the five-year Government of Canada bond yield and 1.92
per cent. The preferred shares are redeemable by TransCanada on or after
December 31, 2014 at a price of $25 per share plus all accrued and unpaid
dividends.
The
preferred shareholders will have the right to convert their shares into Series 2
cumulative redeemable first preferred shares on December 31, 2014 and on
December 31 of every fifth year thereafter. The holders of Series 2 preferred
shares will be entitled to receive quarterly floating rate cumulative dividends
at a yield per annum equal to the sum of the then 90-day Government of Canada
treasury bill rate and 1.92 per cent.
On
September 21, 2009, TransCanada filed a short form base shelf prospectus
qualifying for issuance $3.0 billion of common shares, first or second preferred
shares and/or subscription receipts in Canada and the U.S. until October 2011.
This base shelf prospectus replaced the base shelf prospectus filed in July
2008, which was exhausted by the common share issue discussed
below.
In June
2009, TransCanada completed a public offering of 58.4 million common shares,
including full exercise of an underwriters’ over-allotment option. Proceeds from
the common share offering and the over-allotment option totalled $1.8
billion.
In the
three and nine months ended September 30, 2009, TransCanada issued 2.5 million
and 6.0 million common shares, respectively, under its Dividend Reinvestment and
Share Purchase Plan (DRP), in lieu of making cash dividend payments totalling
$73 million and $182 million, respectively. In the three and nine months ended
September 30, 2008, TransCanada issued 1.7 million and 4.8 million common
shares, respectively, under its DRP, in lieu of making cash dividend payments
totalling $65 million and $177 million, respectively. The dividends under the
DRP were paid with common shares issued from treasury.
|
6.
|
Financial
Instruments and Risk Management
|
TransCanada
continues to manage and monitor its exposure to market, counterparty credit and
liquidity risk.
Counterparty
Credit and Liquidity Risk
TransCanada’s
maximum counterparty credit exposure with respect to financial instruments at
the balance sheet date, without taking into account security held, consisted
primarily of the carrying amount, which approximates fair value, of
non-derivative financial assets, such as accounts receivable, as well as the
fair value of derivative assets. Letters of credit and cash are the primary
types of security provided to support these amounts. The Company does not have
significant concentrations of counterparty credit risk with any individual
counterparties and the majority of counterparty credit exposure is with
counterparties who are investment grade. At September 30, 2009, there were no
significant amounts past due or impaired.
THIRD
QUARTER REPORT 2009 - TRANSCANADA [45
As a
level of uncertainty in the global financial markets remains, TransCanada
continues to closely monitor and reassess the creditworthiness of its
counterparties. This has resulted in TransCanada reducing or mitigating its
exposure to certain counterparties where it is deemed warranted and permitted
under contractual terms. As part of its ongoing operations, TransCanada must
balance its market and counterparty credit risks when making business
decisions.
The
Company continues to manage its liquidity risk by ensuring sufficient cash and
credit facilities are available to meet its operating and capital expenditure
obligations when due, under both normal and stressed economic
conditions.
VaR
Analysis
TransCanada
uses a Value-at-Risk (VaR) methodology to estimate the potential impact from its
exposure to market risk on its open liquid positions. VaR represents the
potential change in pre-tax earnings over a given holding period. It is
calculated assuming a 95 per cent confidence level that the daily change
resulting from normal market fluctuations in its open positions will not exceed
the reported VaR. Although losses are not expected to exceed the statistically
estimated VaR on 95 per cent of occasions, losses on the other five per cent of
occasions could be substantially greater than the estimated VaR. TransCanada’s
consolidated VaR was $14 million at September 30, 2009 (December 31, 2008 – $23
million). The decrease from December 31, 2008 was primarily due to decreased
prices and lower open positions in the U.S. Power portfolio.
Natural
Gas Inventory
At
September 30, 2009, the fair value of proprietary natural gas inventory held in
storage, as measured using a weighted average of forward prices for the
following four months less selling costs, was $73 million (December 31, 2008 -
$76 million).
The
change in fair value of proprietary natural gas inventory in storage in the
three and nine months ended September 30, 2009 resulted in a net pre-tax
unrealized gain of $16 million and a net pre-tax unrealized loss of $13 million,
respectively (2008 – unrealized losses of $108 million and $6 million,
respectively), which were recorded to Revenues and Inventories. The net change
in fair value of natural gas forward purchase and sales contracts in the three
and nine months ended September 30, 2009 resulted in a net pre-tax unrealized
loss of $2 million and a net pre-tax unrealized gain of $7 million, respectively
(2008 - unrealized gain of $106 million and unrealized loss of $1 million),
which were included in Revenues.
Net
Investment in Self-Sustaining Foreign Operations
The
Company hedges its net investment in self-sustaining foreign operations with
U.S. dollar-denominated debt, cross-currency swaps and foreign exchange forward
contracts and options. At September 30, 2009, the Company had designated as a
net investment hedge U.S. dollar-denominated debt with a carrying value of $8.1
billion (US$7.6 billion) and a fair value of $9.2 billion (US$8.6 billion). At
September 30, 2009, Other Assets included $51 million for the fair value of
derivatives used to hedge the Company’s net U.S. dollar investment in foreign
operations.
THIRD
QUARTER REPORT 2009 - TRANSCANADA [46
Information
for the derivatives used to hedge the Company’s net investment in its
self-sustaining foreign operations is as follows:
Derivatives
Hedging Net Investment in Self-Sustaining Foreign Operations
|
September
30, 2009
|
December
31, 2008
|
||||||||||||
|
Asset/(Liability)
(unaudited)
(millions
of dollars)
|
Fair
Value(1)
|
Notional
or Principal Amount
|
Fair
Value(1)
|
Notional
or Principal Amount
|
|||||||||
|
U.S.
dollar cross-currency swaps
|
|||||||||||||
|
(maturing 2009 to 2014)(2)
|
40
|
U.S.
1,650
|
(218
|
)
|
U.S.
1,650
|
||||||||
|
U.S.
dollar forward foreign exchange contracts
|
|||||||||||||
|
(maturing 2009 to 2010)(2)
|
7
|
U.S.
635
|
(42
|
)
|
U.S.
2,152
|
||||||||
|
U.S.
dollar options
|
|||||||||||||
|
(maturing 2009)(2)
|
4
|
U.S.
400
|
6
|
U.S.
300
|
|||||||||
|
51
|
U.S.
2,685
|
(254
|
)
|
U.S.
4,102
|
|||||||||
|
(1)
|
Fair
values equal carrying values.
|
|
(2)
|
As
at September 30, 2009.
|
Non-Derivative
Financial Instruments Summary
The
carrying and fair values of non-derivative financial instruments were as
follows:
|
September
30, 2009
|
December
31, 2008
|
||||||||||||
|
(unaudited)
(millions
of dollars)
|
Carrying
Amount
|
Fair
Value
|
Carrying
Amount
|
Fair
Value
|
|||||||||
|
Financial Assets(1)
|
|||||||||||||
|
Cash
and cash equivalents
|
2,406
|
2,406
|
1,308
|
1,308
|
|||||||||
|
Accounts
receivable and other assets(2)(3)
|
983
|
983
|
1,404
|
1,404
|
|||||||||
|
Available-for-sale
assets(2)
|
23
|
23
|
27
|
27
|
|||||||||
|
3,412
|
3,412
|
2,739
|
2,739
|
||||||||||
|
Financial
Liabilities(1)(3)
|
|||||||||||||
|
Notes
payable
|
1,324
|
1,324
|
1,702
|
1,702
|
|||||||||
|
Accounts
payable and deferred amounts(4)
|
1,606
|
1,606
|
1,372
|
1,372
|
|||||||||
|
Accrued
interest
|
342
|
342
|
359
|
359
|
|||||||||
|
Long-term
debt and junior subordinated notes
|
18,469
|
21,388
|
17,367
|
16,152
|
|||||||||
|
Long-term
debt of joint ventures
|
1,090
|
1,149
|
1,076
|
1,052
|
|||||||||
|
22,831
|
25,809
|
21,876
|
20,637
|
||||||||||
|
(1)
|
Consolidated
Net Income in 2009 and 2008 included unrealized gains or losses of nil for
the fair value adjustments to each of these financial
instruments.
|
|
(2)
|
At
September 30, 2009, the Consolidated Balance Sheet included financial
assets of $834 million (December 31, 2008 – $1,257 million) in Accounts
Receivable and $172 million (December 31, 2008 - $174 million) in Other
Assets.
|
|
(3)
|
Recorded
at amortized cost.
|
|
(4)
|
At
September 30, 2009, the Consolidated Balance Sheet included financial
liabilities of $1,604 million (December 31, 2008 – $1,350 million) in
Accounts Payable and $2 million (December 31, 2008 - $22 million) in
Deferred Amounts.
|
THIRD
QUARTER REPORT 2009 - TRANSCANADA [47
Derivative
Financial Instruments Summary
Information
for the Company’s derivative financial instruments, excluding hedges of the
Company’s net investment in self-sustaining foreign operations, is as
follows:
|
September
30, 2009
|
|||||||||||||||
|
(unaudited)
(all
amounts in millions unless otherwise indicated)
|
Power
|
Natural
Gas
|
Oil
Products
|
Foreign
Exchange
|
Interest
|
||||||||||
|
Derivative Financial
Instruments Held for Trading(1)
|
|||||||||||||||
|
Fair
Values(2)
|
|||||||||||||||
|
Assets
|
$126
|
$129
|
$4
|
$4
|
$35
|
||||||||||
|
Liabilities
|
$(71
|
)
|
$(134
|
)
|
$(3
|
)
|
$(64
|
)
|
$(81
|
)
|
|||||
|
Notional
Values
|
|||||||||||||||
|
Volumes(3)
|
|||||||||||||||
|
Purchases
|
9,876
|
204
|
180
|
-
|
-
|
||||||||||
|
Sales
|
9,718
|
171
|
228
|
-
|
-
|
||||||||||
|
Canadian dollars
|
-
|
-
|
-
|
-
|
699
|
||||||||||
|
U.S. dollars
|
-
|
-
|
-
|
U.S.
426
|
U.S.
1,425
|
||||||||||
|
Cross-currency
|
-
|
-
|
-
|
227/U.S.
157
|
-
|
||||||||||
|
Net
unrealized (losses)/gains in the period(4)
|
|||||||||||||||
|
Three months ended September 30,
2009
|
$(8
|
)
|
$21
|
$(1
|
)
|
$2
|
$(7
|
)
|
|||||||
|
Nine months ended September 30,
2009
|
$11
|
$(4
|
)
|
$1
|
$4
|
$20
|
|||||||||
|
Net
realized gains/(losses) in the period(4)
|
|||||||||||||||
|
Three months ended September 30,
2009
|
$23
|
$(43
|
)
|
$1
|
$11
|
$(5
|
)
|
||||||||
|
Nine months ended September 30,
2009
|
$53
|
$(56
|
)
|
-
|
$28
|
$(14
|
)
|
||||||||
|
Maturity
dates
|
2009-2014
|
2009-2014
|
2009-2010
|
2009-2012
|
2009-2018
|
||||||||||
|
Derivative Financial
Instruments in Hedging Relationships(5)(6)
|
|||||||||||||||
|
Fair
Values(2)
|
|||||||||||||||
|
Assets
|
$229
|
$2
|
-
|
-
|
$6
|
||||||||||
|
Liabilities
|
$(154
|
)
|
$(15
|
)
|
-
|
$(36
|
)
|
$(67
|
)
|
||||||
|
Notional
Values
|
|||||||||||||||
|
Volumes(3)
|
|||||||||||||||
|
Purchases
|
13,597
|
24
|
-
|
-
|
-
|
||||||||||
|
Sales
|
14,806
|
-
|
-
|
-
|
-
|
||||||||||
|
U.S. dollars
|
-
|
-
|
-
|
-
|
1,825
|
||||||||||
|
Cross-currency
|
-
|
-
|
-
|
136/U.S.
100
|
-
|
||||||||||
|
Net
realized gains/(losses) in the period(4)
|
|||||||||||||||
|
Three months ended September 30,
2009
|
$30
|
$(8
|
)
|
-
|
-
|
$(10
|
)
|
||||||||
|
Nine months ended September 30,
2009
|
$108
|
$(28
|
)
|
-
|
-
|
$(27
|
)
|
||||||||
|
Maturity
dates
|
2009-2015
|
2009-2012
|
n/a
|
2009-
2013
|
2010-2020
|
||||||||||
|
(1)
|
All
derivative financial instruments in the held-for-trading classification
have been entered into for risk management purposes and are subject to the
Company’s risk management strategies, policies and limits. These include
derivatives that have not been designated as hedges or do not qualify for
hedge accounting treatment but have been entered into as economic hedges
to manage the Company’s exposures to market
risk.
|
|
(2)
|
Fair
values equal carrying values.
|
|
(3)
|
Volumes
for power, natural gas and oil products derivatives are in GWh, Bcf and
thousands of barrels, respectively.
|
THIRD
QUARTER REPORT 2009 - TRANSCANADA [48
|
(4)
|
Realized
and unrealized gains and losses on power, natural gas and oil products
derivative financial instruments held for trading are included in
Revenues. Realized and unrealized gains and losses on interest rate and
foreign exchange derivative financial instruments held for trading are
included in Interest Expense and Interest Income and Other, respectively.
The effective portion of unrealized gains and losses on derivative
financial instruments in hedging relationships are initially recognized in
Other Comprehensive Income, and are reclassified to Revenues, Interest
Expense and Interest Income and Other, as appropriate, as the original
hedged item settles.
|
|
(5)
|
All
hedging relationships are designated as cash flow hedges except for
interest rate derivative financial instruments designated as fair value
hedges with a fair value of $6 million and a notional amount of US$150
million. Net realized gains on fair value hedges for the three and nine
months ended September 30, 2009 were $1 million and $3 million,
respectively, and were included in Interest Expense. In third quarter
2009, the Company did not record any amounts in Net Income related to
ineffectiveness for fair value
hedges.
|
|
(6)
|
Net
Income for the three and nine months ended September 30, 2009 included
gains of $1 million and $2 million, 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 underlying positions.
There were no gains or losses included in Net Income for the three and
nine months ended September 30, 2009 for discontinued cash flow hedges. No
amounts have been excluded from the assessment of hedge
effectiveness.
|
THIRD
QUARTER REPORT 2009 - TRANSCANADA [49
|
2008
|
||||||||||||||||
|
(unaudited)
(all
amounts in millions unless otherwise indicated)
|
Power
|
Natural
Gas
|
Oil
Products
|
Foreign
Exchange
|
Interest
|
|||||||||||
|
Derivative
Financial Instruments Held for Trading
|
||||||||||||||||
|
Fair
Values(1)(4)
|
||||||||||||||||
|
Assets
|
$132
|
$144
|
$10
|
$41
|
$57
|
|||||||||||
|
Liabilities
|
$(82
|
)
|
$(150
|
)
|
$(10
|
)
|
$(55
|
)
|
$(117
|
) | ||||||
|
Notional
Values(4)
|
||||||||||||||||
|
Volumes(2)
|
||||||||||||||||
|
Purchases
|
4,035
|
172
|
410
|
-
|
-
|
|||||||||||
|
Sales
|
5,491
|
162
|
252
|
-
|
-
|
|||||||||||
|
Canadian dollars
|
-
|
-
|
-
|
-
|
1,016
|
|||||||||||
|
U.S. dollars
|
-
|
-
|
-
|
U.S.
479
|
U.S.
1,575
|
|||||||||||
|
Japanese yen (in
billions)
|
-
|
-
|
-
|
JPY
4.3
|
-
|
|||||||||||
|
Cross-currency
|
-
|
-
|
-
|
227/
U.S. 157
|
-
|
|||||||||||
|
Net
unrealized gains/(losses) in the period(3)
|
||||||||||||||||
|
Three months ended September 30,
2008
|
$5
|
$(1
|
)
|
-
|
-
|
$5
|
||||||||||
|
Nine months ended September 30,
2008
|
-
|
$(12
|
)
|
-
|
$(7
|
)
|
$3
|
|||||||||
|
Net
realized gains/(losses) in the period(3)
|
||||||||||||||||
|
Three months ended September 30,
2008
|
$12
|
$(11
|
)
|
-
|
$2
|
$2
|
||||||||||
|
Nine months ended September 30,
2008
|
$21
|
$(6
|
)
|
-
|
$12
|
$12
|
||||||||||
|
Maturity
dates(4)
|
2009-2014
|
2009-2011
|
2009
|
2009-2012
|
2009-2018
|
|||||||||||
|
Derivative Financial
Instruments in Hedging Relationships(5)(6)
|
||||||||||||||||
|
Fair
Values(1)(4)
|
||||||||||||||||
|
Assets
|
$115
|
-
|
-
|
$2
|
$8
|
|||||||||||
|
Liabilities
|
$(160
|
)
|
$(18
|
)
|
-
|
$(24
|
)
|
$(122
|
) | |||||||
|
Notional
Values(4)
|
||||||||||||||||
|
Volumes(2)
|
||||||||||||||||
|
Purchases
|
8,926
|
9
|
-
|
-
|
-
|
|||||||||||
|
Sales
|
13,113
|
-
|
-
|
-
|
-
|
|||||||||||
|
Canadian dollars
|
-
|
-
|
-
|
-
|
50
|
|||||||||||
|
U.S. dollars
|
-
|
-
|
-
|
U.S.
15
|
U.S.
1,475
|
|||||||||||
|
Cross-currency
|
-
|
-
|
-
|
136/
U.S. 100
|
-
|
|||||||||||
|
Net
realized gains/(losses) in the period(3)
|
||||||||||||||||
|
Three months ended September 30,
2008
|
$14
|
$(1
|
)
|
-
|
-
|
$(2
|
) | |||||||||
|
Nine months ended September 30,
2008
|
$(24
|
)
|
$18
|
-
|
-
|
$(4
|
) | |||||||||
|
Maturity
dates(4)
|
2009-2014
|
2009-2011
|
n/a
|
2009-2013
|
2009-2019
|
|||||||||||
|
(1)
|
Fair
values equal carrying values.
|
|
(2)
|
Volumes
for power, natural gas and oil products derivatives are in GWh, Bcf and
thousands of barrels, respectively.
|
|
(3)
|
Realized
and unrealized gains and losses on power, natural gas and oil products
derivative financial instruments held for trading are included in
Revenues. Realized and unrealized gains and losses on interest rate and
foreign exchange derivative financial instruments held for trading are
included in Interest Expense and Interest Income and Other, respectively.
The effective portion of unrealized gains and losses on derivative
financial instruments in hedging relationships are initially recognized in
Other Comprehensive Income, and are reclassified to Revenues, Interest
Expense and Interest Income and Other, as appropriate, as the original
hedged item settles.
|
|
(4)
|
As
at December 31, 2008.
|
|
(5)
|
All
hedging relationships are designated as cash flow hedges except for
interest rate derivative financial instruments designated as fair value
hedges with a fair value of $8 million and notional amounts of $50 million
and US$50 million at December 31, 2008. Net realized gains on fair value
hedges for the three and nine months ended September 30, 2008 were $1
million and $1 million, respectively, and were included in Interest
Expense. In third quarter 2008, the Company did not record any amounts in
Net Income related to ineffectiveness for fair value
hedges.
|
THIRD
QUARTER REPORT 2009 - TRANSCANADA [50
|
(6)
|
Net
Income for the three and nine months ended September 30, 2008 included
gains of $7 million and $4 million, 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 underlying positions.
There were no gains or losses included in Net Income for the three and
nine months ended September 30, 2008 for discontinued cash flow hedges. No
amounts have been excluded from the assessment of hedge
effectiveness.
|
Balance
Sheet Presentation of Derivative Financial Instruments
The fair
value of the derivative financial instruments in the Company’s Balance Sheet was
as follows:
|
(unaudited)
|
|||||||
|
(millions
of dollars)
|
September
30, 2009
|
December
31, 2008
|
|||||
|
Current
|
|||||||
|
Other current
assets
|
370
|
318
|
|||||
|
Accounts
payable
|
(359
|
)
|
(298
|
)
|
|||
|
Long-term
|
|||||||
|
Other assets
|
216
|
191
|
|||||
|
Deferred
amounts
|
(266
|
)
|
(694
|
)
|
|
7.
|
Employee
Future Benefits
|
The net
benefit plan expense for the Company’s defined benefit pension plans and other
post-employment benefit plans is as follows:
|
Three
months ended September 30
|
Pension
Benefit Plans
|
Other
Benefit Plans
|
|||||||||||
|
(unaudited)(millions
of dollars)
|
2009
|
2008
|
2009
|
2008
|
|||||||||
|
Current
service cost
|
11
|
13
|
-
|
-
|
|||||||||
|
Interest
cost
|
22
|
20
|
2
|
2
|
|||||||||
|
Expected
return on plan assets
|
(24
|
)
|
(23
|
)
|
-
|
-
|
|||||||
|
Amortization
of net actuarial loss
|
2
|
4
|
1
|
1
|
|||||||||
|
Amortization
of past service costs
|
1
|
1
|
-
|
-
|
|||||||||
|
Net
benefit cost recognized
|
12
|
15
|
3
|
3
|
|||||||||
|
Nine
months ended September 30
|
Pension
Benefit Plans
|
Other
Benefit Plans
|
|||||||||||
|
(unaudited)(millions
of dollars)
|
2009
|
2008
|
2009
|
2008
|
|||||||||
|
Current
service cost
|
34
|
38
|
1
|
1
|
|||||||||
|
Interest
cost
|
67
|
59
|
6
|
6
|
|||||||||
|
Expected
return on plan assets
|
(75
|
)
|
(69
|
)
|
(1
|
)
|
(1
|
)
|
|||||
|
Amortization
of transitional obligation related to regulated
business
|
-
|
-
|
1
|
1
|
|||||||||
|
Amortization
of net actuarial loss
|
4
|
13
|
2
|
2
|
|||||||||
|
Amortization
of past service costs
|
3
|
3
|
-
|
-
|
|||||||||
|
Net
benefit cost recognized
|
33
|
44
|
9
|
9
|
|||||||||
|
8.
|
Acquisitions
and Dispositions
|
On August
14, 2009, TransCanada purchased ConocoPhillips’ remaining 20 per cent ownership
interest in Keystone for US$553 million plus the assumption of US$197 million of
short-term indebtedness. The acquisition increased TransCanada’s ownership
interest in Keystone to 100 per cent. The purchase price reflects
ConocoPhillips’ capital contributions to date and includes an allowance for
funds used during construction. TransCanada began fully consolidating Keystone
in the Pipelines segment upon acquisition.
THIRD
QUARTER REPORT 2009 - TRANSCANADA [51
On July
1, 2009, TransCanada sold the North Baja pipeline to PipeLines LP. As part of
the transaction, TransCanada agreed to amend its incentive distribution rights
with PipeLines LP. TransCanada received aggregate consideration totalling
approximately US$395 million from PipeLines LP, including US$200 million in cash
and 6,371,680 common units of PipeLines LP. PipeLines LP utilized US$170 million
of its US$250 million committed and available bank facility to fund this
transaction. TransCanada’s ownership in PipeLines LP increased to 42.6 per cent
as a result of this transaction. TransCanada’s increased ownership in PipeLines
LP resulted in a decrease in Non-Controlling Interests and an increase in
Contributed Surplus.
|
9.
|
Commitments,
Guarantees and Contingencies
|
Commitments
On August
14, 2009, the Company acquired ConocoPhillips’ remaining interest in Keystone.
As a result, TransCanada assumed responsibility for ConocoPhillips’ share of the
capital investment required to complete the project, which is expected to result
in an incremental commitment of US$1.7 billion through the end of
2012.
Guarantees
As a
result of the acquisition of the remaining interest in Keystone, the Company’s
potential exposure to guarantees of jointly owned entities was reduced by an
estimated $305 million to $678 million since December 31, 2008.
Contingencies
Amounts
received under the Bruce B floor price mechanism in any year are subject to
repayment if spot prices in the remainder of that year increase above the floor
price. With respect to 2009, TransCanada currently expects spot prices to be
less than the floor price for the remainder of the year, therefore, no amounts
recorded in revenue in the first nine months of 2009 are expected to be
repaid.
|
10.
|
Subsequent
Events
|
Subsequent
events have been assessed up to November 3, 2009, which is the date the
financial statements were available for issuance.
|
TransCanada welcomes questions from shareholders and potential investors.
Please telephone:
|
|
Investor
Relations, at (800) 361-6522 (Canada and U.S. Mainland) or direct dial
David Moneta/Myles Dougan/Terry Hook at (403) 920-7911. The investor fax
line is (403) 920-2457. Media Relations: Terry Cunha/
Cecily
Dobson (403) 920-7859 or (800) 608-7859.
|
|
Visit
the TransCanada website at: http://www.transcanada.com.
|
EXHIBIT
13.3
TRANSCANADA
CORPORATION
RECONCILIATION
TO UNITED STATES GAAP
September
30, 2009
TRANSCANADA
CORPORATION
RECONCILIATION
TO UNITED STATES GAAP
The
unaudited consolidated financial statements of TransCanada Corporation
(TransCanada or the Company) for the nine months ended September 30, 2009 have
been prepared in accordance with Canadian generally accepted accounting
principles (GAAP), which in some respects, differ from United States (U.S.)
GAAP.
The
effects of significant differences between Canadian and U.S. GAAP on the
Company’s consolidated financial statements for the three and nine month periods
ended September 30, 2009 are described below and should be read in conjunction
with TransCanada’s 2008 audited consolidated financial statements and U.S. GAAP
reconciliation for the year ended December 31, 2008 and unaudited consolidated
financial statements for the three and nine month periods ended September 30,
2009 prepared in accordance with Canadian GAAP.
Reconciliation
of Net Income and Comprehensive Income
|
(unaudited)
|
Three
months
ended
September
30
|
Nine
months
ended
September
30
|
||||||||||||||
|
(millions
of dollars, except per share amounts)
|
2009
|
2008
|
2009
|
2008
|
||||||||||||
|
Net Income in Accordance with Canadian GAAP
|
345 | 390 | 993 | 1,163 | ||||||||||||
|
U.S.
GAAP adjustments:
|
||||||||||||||||
|
Net income attributable to
non-controlling interests(1)
|
23 | 18 | 71 | 106 | ||||||||||||
|
Unrealized (gain)/loss on natural gas inventory held
in storage (2)
|
(16 | ) | 108 | 13 | 32 | |||||||||||
|
Tax impact of
unrealized (gain)/loss on natural gas inventory held
in storage
|
5 | (35 | ) | (4 | ) | (11 | ) | |||||||||
|
Tax
expense/(recovery) due to a change in tax legislation substantively
enacted in Canada(3)
|
2 | (1 | ) | 1 | (2 | ) | ||||||||||
|
Net
Income in Accordance with U.S. GAAP
|
359 | 480 | 1,074 | 1,288 | ||||||||||||
|
Less:
net income attributable to non-controlling interests(1)
|
(23 | ) | (18 | ) | (71 | ) | (106 | ) | ||||||||
|
Net Income Attributable to Common Shares in Accordance with U.S.
GAAP(1)
|
336 | 462 | 1,003 | 1,182 | ||||||||||||
|
Other Comprehensive Income/(Loss) (OCI) in Accordance with Canadian
GAAP
|
(102 | ) | 29 | (98 | )) | 59 | ||||||||||
|
U.S.
GAAP adjustments:
|
||||||||||||||||
|
Change in funded status of postretirement plan liability, net of tax(4)
|
1 | 2 | 3 | 5 | ||||||||||||
|
Change in equity investment funded status of postretirement plan
liability, net of tax(4)
|
(2 | ) | 2 | (2 | ) | 6 | ||||||||||
|
Comprehensive
Income in Accordance with U.S. GAAP
|
233 | 495 | 906 | 1,252 | ||||||||||||
|
Net Earnings Per Share in Accordance with U.S. GAAP, Basic and
Diluted
|
$ | 0.49 | $ | 0.79 | $ | 1.56 | $ | 2.10 | ||||||||
Page
2
Condensed
Balance Sheet in Accordance with U.S. GAAP
|
(unaudited)
(millions
of dollars)
|
September
30,
2009
|
December
31,
2008
|
||||||
|
Current
assets(2)
|
3,570 | 3,399 | ||||||
|
Long-term
investments(4)(5)(6)
|
4,772 | 5,221 | ||||||
|
Plant,
property and equipment(7)
|
27,204 | 22,901 | ||||||
|
Goodwill
|
3,733 | 4,258 | ||||||
|
Regulatory
assets(4)(8)
|
1,792 | 1,810 | ||||||
|
Other
assets
(4)(9)
|
1,787 | 1,608 | ||||||
| 42,858 | 39,197 | |||||||
|
Current
liabilities(3)
|
4,416 | 4,264 | ||||||
|
Deferred
amounts(4)(6)
|
934 | 1,238 | ||||||
|
Regulatory
liabilities
|
427 | 551 | ||||||
|
Deferred
income taxes(2)(4)(5)(8)
|
2,733 | 2,602 | ||||||
|
Long-term
debt and junior subordinated notes(9)
|
17,906 | 16,664 | ||||||
| 26,416 | 25,319 | |||||||
|
Shareholders’
equity:
|
||||||||
|
Common
shares
|
11,251 | 9,265 | ||||||
|
Preferred
shares
|
539 | - | ||||||
|
Non-controlling
interests(1)
|
1,027 | 1,194 | ||||||
|
Contributed
surplus
|
331 | 279 | ||||||
|
Retained
earnings(2)(3)(5)
|
4,059 | 3,809 | ||||||
|
Accumulated
other comprehensive income(4)(10)
|
(765 | ) | (669 | ) | ||||
| 16,442 | 13,878 | |||||||
| 42,858 | 39,197 | |||||||
|
(1)
|
As
required by U.S. GAAP, the Company has reclassified its non-controlling
interests on the income statement and balance sheet. On the balance sheet,
non-controlling interests are now presented in the equity section. On the
income statement, consolidated net income includes both the Company’s and
the non-controlling interests’ share of net income. In addition,
consolidated net income attributable to the Company and the
non-controlling interests are separately disclosed. This reclassification
has been applied retrospectively as
required.
|
|
(2)
|
In
accordance with Canadian GAAP, natural gas inventory held in storage is
recorded at its fair value. Under U.S. GAAP, inventory is recorded at
lower of cost or market.
|
|
(3)
|
In
accordance with Canadian GAAP, the Company recorded current income tax
benefits resulting from substantively enacted Canadian federal income tax
legislation. Under U.S. GAAP, the legislation must be fully enacted for
income tax adjustments to be
recorded.
|
|
(4)
|
Represents
the amortization of net loss and prior service cost amounts recorded in
Accumulated Other Comprehensive Income for the Company’s defined benefit
pension and other postretirement
plans.
|
|
(5)
|
Under
Canadian GAAP, pre-development 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 development costs incurred by Bruce Power L.P., an equity
investment, were expensed under U.S.
GAAP.
|
|
(6)
|
Under
Canadian GAAP, the Company accounts for certain investments using the
proportionate consolidation basis whereby the Company’s proportionate
share of the assets, liabilities, revenues, expenses and cash flows are
included in the Company’s financial statements. U.S. GAAP does
not allow the use of proportionate consolidation and requires that such
investments be recorded on an equity accounting
basis. Information on the balances that have been
proportionately consolidated is located in Note 8 to the Company’s audited
consolidated annual financial statements for the year ended December 31,
2008. As a consequence of using equity accounting for U.S.
GAAP, the Company is required to reflect an additional liability of $182
million at September 30, 2009 (December 31, 2008 - $51 million) for the
estimated fair value of certain guarantees related to debt and other
performance commitments of the joint venture operations that were not
required to be recorded when the underlying liability was reflected on the
balance sheet under the proportionate consolidation method of
accounting.
|
|
(7)
|
Under
Canadian GAAP, the Company’s purchase of ConocoPhilips’ remaining 20 per
cent interest in each of TransCanada Keystone Pipeline Limited Partnership
and TransCanada Keystone Pipeline, LP (Keystone) is considered an asset
purchase. Under U.S. GAAP, this transaction is considered a
business combination. The purchase price was allocated to
plant, property and equipment (US $734 million) and short-term debt (US
$197 million) using fair values of the net assets at the date of
acquisition. However there is no U.S. GAAP difference as no gain or loss
was created.
|
|
(8)
|
Under
U.S. GAAP, the Company is required to record a deferred income tax
liability for its cost-of-service regulated businesses and a corresponding
regulatory asset. Effective January 1, 2009, the Company chose
to adopt accounting policies consistent with U.S. GAAP for its Canadian
GAAP financial statements which eliminated the U.S. GAAP difference
subsequent to December 31, 2008.
|
|
(9)
|
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.
|
|
(10)
|
At
September 30, 2009, Accumulated Other Comprehensive Income in accordance
with U.S. GAAP is $195 million higher than under Canadian
GAAP. The difference relates to the accounting treatment for
defined benefit pension and other postretirement
plans.
|
Page
3
Fair
Value Measurements
The
Company adopted the U.S. standards for fair value measurements and disclosures
for its financial assets and liabilities measured at fair value on a recurring
basis effective January 1, 2008. Effective
January 1, 2009, the Company adopted these standards for all non-financial
assets and liabilities that are measured at fair value on a non-recurring
basis.
The
Company’s financial assets and liabilities that are recorded at fair value on a
recurring basis have been categorized into one of three categories based upon a
fair value hierarchy. Fair values
of assets and liabilities included in Level I are determined by reference to
quoted prices in active markets for identical assets and liabilities. Assets and
liabilities in Level II include valuations using inputs other than quoted prices
for which all significant outputs are observable, either directly or
indirectly. Level III
valuations are based on inputs that are unobservable and significant to the
overall fair value measurement. Long-dated commodity transactions in certain
markets and the fair value of guarantees are included in this category. There is
no current period disclosure required for items measured at fair value on a
non-recurring basis.
Assets
and liabilities measured at fair value on a recurring basis as of September 30,
2009, including both current and non-current portions, are categorized as
follows:
|
(unaudited)
(millions
of dollars)
|
Quoted
prices
in
active
markets
(Level
I)
|
Significant
other
observable
inputs
(Level
II)
|
Significant
unobservable
inputs
(Level
III)
|
Total
|
||||
|
Derivative
Financial Instruments:
|
||||||||
|
Assets
|
67
|
550
|
3
|
620
|
||||
|
Liabilities
|
(101
|
)
|
(532
|
)
|
(26
|
)
|
(659
|
)
|
|
Non-Derivative
Financial Instruments Available for Sale:
|
||||||||
|
Assets
|
23
|
-
|
-
|
23
|
||||
|
Guarantees:
|
||||||||
|
Liabilities
|
-
|
-
|
(188
|
)
|
(188
|
)
|
||
|
Total
|
(11
|
)
|
18
|
(211
|
)
|
(204
|
)
|
Long-term
debt fair value disclosures are based on quoted market prices for same or
similar debt instruments, or, when not available, by discounting future payments
of interest and principal at estimated interest rates. These fair
value disclosures fall under Level II in the hierarchy.
The
following table presents the net change in assets and liabilities measured at
fair value on a recurring basis and included in the Level III fair value
category:
|
(unaudited)
|
Three
Months Ended
September
30, 2009
|
Nine
Months Ended
September
30, 2009
|
||||||
|
(millions
of dollars, pre-tax)
|
Derivatives
|
(1)
|
Guarantees
|
Derivatives
|
(1)
|
Guarantees
|
||
|
Balance,
opening
|
(22
|
)
|
(190
|
)
|
-
|
-
|
||
|
Transfers
in(2)
|
-
|
-
|
-
|
(60
|
)
|
|||
|
Total realized and unrealized gains/(losses):
|
||||||||
|
Included
in OCI
|
6
|
-
|
6
|
-
|
||||
|
Included
in Balance Sheet (2)
|
-
|
(3
|
)
|
-
|
(127
|
)
|
||
|
New
contracts entered into or settled during the period, net(3)
|
(7
|
)
|
5
|
(29
|
)
|
(1
|
)
|
|
|
Balance,
closing
|
(23
|
)
|
(188
|
)
|
(23
|
)
|
(188
|
)
|
|
(1)
|
The fair value of derivative assets and liabilities are presented on a net basis. |
|
(2)
|
The
fair value of guarantees is recognized in Long-term investments and
Deferred amounts. No amounts were recognized in earnings for
the periods presented. Prior to June 30, 2009, the fair value
was previously included in the Level II fair value
category.
|
|
(3)
|
The
total amount of net gains included in earnings attributable to derivatives
that were entered into during the period and still held at the reporting
date is $1 million for the three and nine months ended September 30,
2009.
|
Page 4
Disclosures
about Hedging Instruments and Hedging Activities
The
Company adopted the U.S. standards for derivatives and hedging effective January
1, 2009. The statement is intended to enhance the current disclosure
requirements to provide more information about how derivatives and hedging
activities affect an entity’s financial position, financial performance and cash
flows. Many of these disclosures are provided in the Company’s
consolidated financial statements prepared under Canadian
GAAP. Additional information required is provided below.
Derivatives
in Cash Flow and Net Investment Hedging Relationships
|
Three
months ended September 30, 2009
|
Cash
Flow Hedges
|
Net
Investment Hedges
|
||||||||||||||||||
|
(unaudited)
(millions of dollars,
pre-tax)
|
Power
|
Natural
Gas
|
Foreign
Exchange
|
Interest
|
Foreign
Exchange
|
|||||||||||||||
|
Amount
of gain/(loss) recognized in OCI on derivative (effective
portion)
|
48 | - | (8 | ) | (20 | ) | 164 | |||||||||||||
|
Amount
of gain/(loss) reclassified from AOCI into income (effective
portion)
|
(19 | ) | 11 | - | 11 | - | (1) | |||||||||||||
|
Amount
of gain/(loss) recognized in income on derivative (ineffective portion and
amount excluded from effectiveness testing)
|
1 | - | - | - | - | (2) | ||||||||||||||
|
Nine
months ended September 30, 2009
|
Cash
Flow Hedges
|
Net
Investment Hedges
|
||||||||||||||||||
|
(unaudited)
(millions of dollars,
pre-tax)
|
Power
|
Natural
Gas
|
Foreign
Exchange
|
Interest
|
Foreign
Exchange
|
|||||||||||||||
|
Amount
of gain/(loss) recognized in OCI on derivative (effective
portion)
|
152 | (14 | ) | (12 | ) | (26 | ) | 311 | ||||||||||||
|
Amount
of gain/(loss) reclassified from AOCI into income (effective
portion)
|
(47 | ) | 13 | - | 32 | - | (1) | |||||||||||||
|
Amount
of gain/(loss) recognized in income on derivative (ineffective portion and
amount excluded from effectiveness testing)
|
1 | 1 | - | - | - | (2) | ||||||||||||||
|
|
(1)
|
Location
of gain (loss) is gain/(loss) on sale of
subsidiary
|
|
|
(2)
|
Location
of gain (loss) is other
income/(expense)
|
Derivative
contracts entered into to manage market risk often contain financial assurances
provisions that allow parties to the contracts to manage credit
risk. These provisions may require collateral to be provided if a
credit-risk-related contingent event occurs, such as a downgrade in the
Company’s credit rating to non-investment grade. Based on contracts
in place and market prices at September 30, 2009, the aggregate fair value of
all derivative instruments with credit-risk-related contingent features that are
in a net liability position is $107 million for which the Company has provided
collateral of $6 million in the normal course of business. If the
credit-risk-related contingent features in these agreements were triggered on
September 30, 2009, the Company may be required to provide additional collateral
of $101 million to its counterparties. The Company has sufficient
liquidity in the form of cash and undrawn committed revolving bank lines to meet
these contingent obligations should they arise.
Income
Taxes
At
September 30, 2009, the total unrecognized tax benefit is approximately $60
million (December 31, 2008 - $80 million). TransCanada’s continuing
practice is to recognize interest and penalties related to income tax
uncertainties in income tax expense. Included in net tax expense for
the nine month period ended September 30, 2009 is $7 million of interest income
and nil for penalties (September 30, 2008 - $9 million for interest expense and
nil for penalties). At September 30, 2009, the Company had $17 million accrued
for interest and nil accrued for penalties (December 31, 2008 - $24 million
accrued for interest and nil accrued for penalties).
Page 5
TransCanada
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, TransCanada 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.
Changes
in Accounting Policies
2009
Accounting Changes
In
December 2007, Financial Accounting Standards Board (FASB) issued new guidance
on “Noncontrolling Interests” and “Business Combinations” effective for annual
and interim periods beginning after December 15, 2008. The new standard on
noncontrolling interest requires that third party ownership interests in
subsidiaries be presented separately in the equity section of the balance
sheet. Consolidated net income will include both the shareholders’ and the
non-controlling interests’ share of net income. The new standard on Business
Combinations requires that most identifiable assets, liabilities (including
obligations for contingent consideration), non-controlling interests and
goodwill be recorded at “full fair value”. Also, for step acquisitions,
the acquirer will be required to re-measure its non-controlling equity
investment in the acquiree at fair value as of the date control is obtained and
recognize any gain or loss in income. The Company adopted these standards
on January 1, 2009 resulting in a reclassification of non-controlling interests
on the income statement and balance sheet.
In April
2009, FASB issued new guidance on “Accounting for Assets Acquired and
Liabilities Assumed in a Business Combination That Arise from Contingencies”
which amends and clarifies pre-existing business combination standards. Any asset or
liability assumed in a business combination that arises from a contingency will
be recognized at the fair value at the acquisition date if that fair value can
be determined. If the
acquisition-date fair value cannot be determined, then the asset or liability
will only be recognized if it is probable that the asset existed or the
liability had been incurred at the acquisition date and the amount can be
reasonably estimated. This guidance is effective for acquisitions after December
15, 2008. The Company applied this standard on the Keystone
acquisition.
In April
2009, FASB issued new guidance on “Interim Disclosures about Fair Value of
Financial Instruments” which requires fair value disclosure for interim
reporting periods in addition to annual financial statements. This guidance
is effective for interim reporting periods after June 15, 2009. The Company
adopted these standards for its second-quarter 2009 report by expanding its
financial instrument disclosure.
In April
2009, FASB issued new guidance on “Recognition and Presentation of
Other-Than-Temporary Impairments” which amends the guidance related to
other-than-temporary impairments specifically for debt securities. Other-than-temporary
impairments must be
recognized if the entity has the intention of selling the debt security or if it
is more likely than not that the entity will be required to sell the debt
security before its anticipated recovery. This guidance is
effective for interim reporting periods after June 15, 2009. The Company
adopted these standards for its second-quarter 2009 report without any impact to
its financial statements.
In May
2009, FASB issued new guidance on “Subsequent Events” which establishes general
standards of accounting for and disclosure of events that occur after the
balance sheet date but before financial statements are issued or available to be
issued. The accounting and disclosure requirements under this
standard have been incorporated in the Company’s Canadian GAAP financial
statements, therefore, there was no impact on the Company’s U.S. GAAP financial
statements.
Future
Accounting Changes
In
December 2008, FASB issued new guidance on “Employers’ Disclosures about
Postretirement Benefit Plan Assets”, which requires more detailed disclosures
regarding the employers’ plan assets, concentrations of risk within plan assets
and valuation techniques used to measure the fair value of plan assets. This
guidance will be effective for fiscal years ending after December 15, 2009. The
Company will adopt these standards for its 2009 year-end reporting by expanding
its postretirement benefit plan disclosures.
Page 6
Exhibit
31.1
Certifications
I, Harold
N. Kvisle, certify that:
|
1.
|
I have reviewed this quarterly report on Form 6-K of TransCanada Corporation; |
|
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 issuer as
of, and for, the periods presented in this
report;
|
|
4.
|
The
issuer’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
control over financial reporting (as defined in Exchange Act Rules
13a-15(f) and 15d-15(f)) for the issuer 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 issuer, 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 issuer’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 issuer’s internal control over financial
reporting that occurred during the issuer’s most recent fiscal quarter
(the issuer’s fourth fiscal quarter in the case of an annual report) that
has materially affected, or is reasonably likely to materially affect, the
issuer’s internal control over financial reporting;
and
|
|
5.
|
The
issuer’s other certifying officer(s) and I have disclosed, based on our
most recent evaluation of internal control over financial reporting, to
the issuer’s auditors and the audit committee of the issuer’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 issuer’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 issuer’s internal control
over financial reporting.
|
|
Dated:
|
November
4, 2009
|
/s/
Harold N. Kvisle
|
|
Harold
N. Kvisle
|
||
|
President
and Chief Executive Officer
|
Exhibit
31.2
Certifications
I,
Gregory A. Lohnes, certify that:
|
1.
|
I
have reviewed this quarterly report on Form 6-K of TransCanada
Corporation;
|
|
|
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 issuer as
of, and for, the periods presented in this report;
|
|
|
4.
|
The
issuer’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
control over financial reporting (as defined in Exchange Act Rules
13a-15(f) and 15d-15(f)) for the issuer 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 issuer, 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 issuer’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 issuer’s internal control over financial
reporting that occurred during the issuer’s most recent fiscal quarter
(the issuer’s fourth fiscal quarter in the case of an annual report) that
has materially affected, or is reasonably likely to materially affect, the
issuer’s internal control over financial reporting; and
|
|
|
5.
|
The
issuer’s other certifying officer(s) and I have disclosed, based on our
most recent evaluation of internal control over financial reporting, to
the issuer’s auditors and the audit committee of the issuer’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 issuer’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 issuer’s internal control
over financial reporting.
|
|
|
Dated:
|
November
4, 2009
|
/s/
Gregory A. Lohnes
|
|
Gregory
A. Lohnes
|
||
|
Executive
Vice-President
and
Chief Financial
Officer
|
Exhibit
32.1
TRANSCANADA
CORPORATION
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 Corporation (the
“Company”), in compliance with 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, hereby certify, in
connection with the Company’s Quarterly Report as filed on Form 6-K for the
period ended September 30, 2009 with the Securities and Exchange Commission (the
“Report”), that:
|
1.
|
the
Report fully complies with the requirements of Section 13(a) or 15(d) of
the Securities Exchange Act of 1934; and
|
|
2.
|
the
information contained in the Report fairly presents, in all material
respects, the financial condition and results of operations of the
Company.
|
|
/s/
Harold N. Kvisle
|
|
|
Harold
N. Kvisle
|
|
|
Chief
Executive Officer
|
|
|
November
4, 2009
|
Exhibit
32.2
TRANSCANADA
CORPORATION
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 Corporation (the
“Company”), in compliance with 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, hereby certify, in
connection with the Company’s Quarterly Report as filed on Form 6-K for the
period ended September 30, 2009 with the Securities and Exchange Commission (the
“Report”), that:
|
1.
|
the
Report fully complies with the requirements of Section 13(a) or 15(d) of
the Securities Exchange Act of 1934; and
|
|
2.
|
the
information contained in the Report fairly presents, in all material
respects, the financial condition and results of operations of the
Company.
|
|
/s/
Gregory A. Lohnes
|
|
|
Gregory
A. Lohnes
|
|
|
Chief
Financial Officer
|
|
|
November
4, 2009
|
EXHIBIT
99.1
TRANSCANADA
CORPORATION – THIRD QUARTER 2009
Quarterly Report to
Shareholders
|
Media
Inquiries:
|
Cecily
Dobson/Terry Cunha
|
(403)
920-7859
|
|
(800)
608-7859
|
||
|
Analyst
Inquiries:
|
David
Moneta/Myles Dougan/Terry Hook
|
(403)
920-7911
|
|
(800)
361-6522
|
TransCanada
Reports Third Quarter Net Income of $345 Million or $0.50 Per Common
Share
Funds
Generated from Operations of $772 Million
CALGARY,
Alberta – November 4,
2009 – TransCanada Corporation (TSX, NYSE: TRP) (TransCanada or the
Company) today announced net income for third quarter 2009 of $345 million or
$0.50 per common share. TransCanada’s Board of Directors also declared a
quarterly dividend of $0.38 per common share.
“TransCanada
continues to post solid earnings and strong cash flows on the strength of our
diverse energy infrastructure business. Third quarter earnings were ahead of
last year for our pipelines and natural gas storage assets, while the economic
downturn continues to impact power revenues,” said Hal Kvisle, TransCanada’s
president and chief executive officer.
“We made
significant progress during the quarter executing the major projects within our
$22 billion capital program. TransCanada is well positioned to fund this
unprecedented growth. The carrying costs and dilution associated with
financing this multi-year program continues to have a near-term impact on our
earnings and cash flow per share. However, we are confident that our
capital program will generate significant growth in cash flows and earnings over
the next four years as our large scale, highly attractive projects commence
operations.”
Third
Quarter 2009 Highlights
(All
financial figures are unaudited and in Canadian dollars unless noted
otherwise)
|
|
■
|
Net
income of $345 million or $0.50 per common
share
|
|
|
■
|
Comparable
earnings of $335 million or $0.49 per common
share
|
|
|
■
|
Comparable
earnings before interest, taxes, depreciation and amortization (EBITDA) of
$994 million
|
|
|
■
|
Funds
generated from operations of $772
million
|
|
|
■
|
Dividend
of $0.38 per common share declared by the Board of
Directors
|
|
|
■
|
Awarded
a 20-year contract to build, own and operate a $1.2 billion, 900 megawatt
(MW) power generating station in Oakville,
Ontario
|
|
|
■
|
Issued
$550 million of cumulative redeemable first preferred
shares
|
|
|
■
|
Continued
to advance $22 billion capital
program
|
TransCanada
reported net income for third quarter 2009 of $345 million ($0.50 per common
share) compared to $390 million ($0.67 per common share) for third quarter
2008.
Comparable
earnings were $335 million ($0.49 per common share) in third quarter 2009
compared to $366 million ($0.63 per common share) for the same period in 2008.
This decrease was primarily due to lower power prices and volumes sold in
Western Power and reduced generation volumes from New England and Bruce
Power.
Partially
offsetting these decreases were higher earnings from Canadian pipelines, natural
gas storage, Ravenswood acquired in August 2008 and the start up of Portlands
Energy and the Carleton wind farm.
Comparable
earnings per common share in third quarter 2009 was further reduced compared to
the same period last year due to an 18 per cent increase in the average number
of shares outstanding following the Company’s issuances of 58.4 million and 35.1
million common shares in second quarter 2009 and fourth quarter 2008,
respectively. Proceeds from the offerings were used to fund the
acquisition of additional interests in Keystone and for other capital projects,
general corporate purposes and to repay short-term debt. TransCanada’s $22
billion capital program is expected to boost cash flow and earnings in the
coming years as projects come on-line.
Comparable
earnings in third quarter 2009 and 2008 excluded $10 million of after tax net
unrealized gains and $2 million of after tax net unrealized losses,
respectively, resulting from changes in the fair value of proprietary natural
gas inventory in storage and natural gas forward purchase and sale
contracts. Comparable earnings in 2008 also excluded $26 million of
favourable income tax adjustments.
Comparable
EBITDA in third quarter 2009 was $994 million compared to $1,066 million in
third quarter 2008.
Funds
generated from operations in third quarter 2009 were $772 million compared to
$711 million in third quarter 2008.
Notable
recent developments in Pipelines, Energy and Corporate include:
Pipelines:
|
|
■
|
On
August 14, 2009, TransCanada purchased
ConocoPhillips’ remaining interest in Keystone for US$553 million plus the
assumption of US$197 million of short-term debt. TransCanada
now owns 100 per cent of this
project.
|
TransCanada
also assumed responsibility for ConocoPhillips’ share of the capital investment
required to complete the project, resulting in an incremental commitment of
US$1.7 billion through the end of 2012.
The first
phase of the pipeline is now approximately 90 per cent complete and TransCanada
expects to begin filling the line in the fourth quarter of this year with
deliveries of oil to the U.S. Midwest commencing in first quarter
2010.
Keystone
is currently seeking the necessary regulatory approvals in Canada and the U.S.
to build and operate an expansion and extension of the pipeline system that will
provide additional capacity of 500,000 barrels per day (bbl/d) from Western
Canada to the Gulf Coast in 2012.
In
September 2009, the National Energy Board (NEB) held a hearing to review the
application for the Canadian portion of the Keystone Gulf Coast expansion with a
decision expected in early 2010. Permits for the U.S. portion of the expansion
are expected by mid-2010. Construction of the Keystone expansion is expected to
begin in 2010 once TransCanada receives all the necessary regulatory
approvals.
When
completed, the approximately US$12 billion Keystone pipeline will be one of the
largest oil delivery systems in North America with the capacity to deliver 1.1
million bbl/d from Western Canada to the largest refining markets in the United
States.
Keystone
has secured long-term commitments for 910,000 bbl/d for an average term of 18
years, which represents 83 per cent of the commercial design of the
system.
The
pipeline is expected to begin generating EBITDA in first quarter 2010 when oil
begins flowing to Wood River and Patoka, Illinois. EBITDA is expected
to increase through 2011 and 2012 as future phases of Keystone become
operational.
Based on
current long-term commitments of 910,000 bbl/d, Keystone is expected to generate
EBITDA of approximately US$1.2 billion in 2013, its first full year of
commercial operation serving both the U.S. Midwest and Gulf Coast
markets.
If
volumes were to increase to 1.1 million bbl/d, Keystone would generate
approximately US$1.5 billion of annual EBITDA. In the future, the
pipeline could be economically expanded from 1.1 million bbl/d to 1.5 million
bbl/d based on market demand.
|
|
■
|
On
September 28, 2009, TransCanada began work on the 160 kilometre (km) Red
Earth section of the North Central Corridor (NCC) pipeline that is
expected to be complete by April 2010. The 140 km North Star section has
been completed and two 13 megawatt (MW) compressor units at the Meikle
River compressor station were operational on May 15, 2009 and August 21,
2009 respectively.
|
The NCC
project is a 300 km natural gas pipeline in the northern section of the Alberta
System. It will provide capacity needed to deal with increasing gas
supply in northwest Alberta and northeast B.C., declining gas supply in
northeast Alberta, growing markets within the province, and help deliver more
gas to interconnecting pipelines at the Alberta-Saskatchewan
border.
The NCC
pipeline is expected to reduce fuel consumption on the entire Alberta System by
approximately 50 per cent which is expected to result in shipper savings of
between $50 million-$75 million per year.
|
|
■
|
The
Alaska Pipeline Project continues to move forward, with the joint
TransCanada and ExxonMobil project team actively advancing the
engineering, technical, commercial, environmental and stakeholder
engagement work leading to the project's initial open season targeted for
completion by July 2010.
|
Energy:
|
|
■
|
On
September 30, 2009 the Ontario Power Authority (OPA) awarded TransCanada a
20-year clean energy supply contract to build, own and operate the 900 MW
Oakville Generating Station in Oakville, Ontario. A contract
has now been finalized with the
OPA.
|
TransCanada
expects to invest approximately $1.2 billion in the natural gas-fired,
combined-cycle plant, scheduled to start producing power by the end of
2013.
|
|
■
|
Commissioning
of the first phase of the Kibby Wind Power project began in September
2009. Twenty-two of the 44 turbines have been constructed and were in
service effective October 30, 2009. Roads and foundations for the
remaining 22 turbines will be completed this year and the turbines are
expected to be installed and operational by the end of third quarter 2010.
Kibby will have the capacity to produce 132
MW.
|
|
|
■
|
Construction
of the approximately $670 million, 683 MW Halton Hills Generating Station
is continuing on schedule and the facility is anticipated to be in service
in the summer of 2010. All of the power produced by the facility will be
sold to the OPA under a 20-year power purchase
agreement.
|
|
|
■
|
TransCanada
began construction of the US$500 million Coolidge Generating Station in
August 2009. The 575 MW power facility is expected to be
on-line in second quarter 2011. All of the power produced by the facility
will be sold to the Phoenix, Arizona based utility Salt River Project
under a 20-year power purchase
agreement.
|
The
simple-cycle, natural gas-fired peaking facility will provide a quick response
to peak power demand. The facility will also provide reserve capacity
and have the ability to generate power on short notice to support power
reliability in the region.
|
|
■
|
Initial
brush clearing work for the 212 MW Gros-Morne wind farm in Québec has been
completed. Clearing for the 58 MW Montagne-Sèche wind farm will be
completed by the end of November
2009.
|
The
Montagne-Sèche project and phase one of the Gros-Morne wind farm are expected to
be operational by 2011. Gros-Morne phase two is expected to be
operational by 2012.
These are
the fourth and fifth Québec-based wind farms under development by Cartier Wind,
which is 62 per cent owned by TransCanada. These two wind farms are expected to
have a capital cost of approximately $340 million. Once these two phases are
complete, Cartier Wind will be capable of producing
590 MW of electricity. All of the power produced by Cartier Wind is sold
to Hydro- Québec Distribution under a 20-year power purchase
agreement.
|
|
■
|
Progress
continues on the refurbishment and restart of Bruce A Units 1 and 2 with
work now advanced to the re-assembly of the reactors. As of September 30,
2009, Bruce A had incurred approximately $3.1 billion in costs for the
refurbishment and restart of Units 1 and 2. TransCanada believes that the
work on Units 1 and 2 is now approximately 75 per cent complete, with the
bulk of the highly technical, high risk work now finished. Although a
significant amount of work remains to be done, most of this work is
conventional power plant construction
activity.
|
The
project has experienced delays in reaching this stage and TransCanada now
expects that Unit 2 will be restarted in-mid 2011, with Unit 1 expected to
follow approximately four months thereafter. The impact of this delay is
mitigated by the previously announced extension of the operating lives of Unit 3
to 2011 and Unit 4 to 2016, with further life extensions expected as additional
reactor optimization activities proceed. TransCanada continues to work closely
with Bruce Power to address productivity and overall project management and
notes that there have been recent, significant successes in this
area.
Corporate:
|
|
■
|
TransCanada
and its subsidiaries held cash and cash equivalents of $2.4 billion at
September 30, 2009.
|
|
|
■
|
On
September 30, 2009, TransCanada completed a public offering of 22 million
cumulative redeemable first preferred shares. Net proceeds from
the $550 milion preferred share offering are expected to be used by
TransCanada to partially fund capital projects, for general corporate
purposes and to re-pay short-term debt of TransCanada and its
affiliates.
|
|
|
■
|
TransCanada is well positioned to
fund its existing capital program through its growing internally-generated
cash flow, its dividend reinvestment and share purchase plan, and its
continued access to capital markets. TransCanada will also continue to
examine opportunities for portfolio management, including an ongoing role
for TC PipeLines, LP in the financing of TransCanada’s capital
program.
|
Teleconference
– Audio and Slide Presentation
TransCanada
Corporation will hold a teleconference and webcast to discuss its 2009 third
quarter financial results. Hal Kvisle, TransCanada president and
chief executive officer and Greg Lohnes, executive vice-president and chief
financial officer, along with other members of the TransCanada executive
leadership team, will discuss the financial results and company developments,
including its $22 billion capital program, before opening the call to questions
from analysts, members of the media and other interested parties.
Event:
TransCanada
third quarter 2009 financial results teleconference and webcast
Date:
Wednesday,
November 4, 2009
Time:
9 a.m.
mountain standard time (MST) /11 a.m. eastern standard time (EST)
How:
To
participate in the teleconference, please call (800) 769-8320 or (416)
695-6622 (Toronto
area). Please dial in 10 minutes prior to the start of the call. No pass code is
required. A live webcast of the teleconference will also be available on
TransCanada’s website (www.transcanada.com).
A replay
of the teleconference will be available two hours after the conclusion of the
call until midnight (EST) November 11, 2009. Please call (800) 408-3053 or (416)
695-5800 (Toronto area) and enter pass code 1281126#. The webcast will be
archived and available for replay on www.transcanada.com.
With more
than 50 years’ experience, TransCanada is a leader in the responsible
development and reliable operation of North American energy infrastructure
including natural gas pipelines, power generation, gas storage
facilities, and projects related to oil pipelines. TransCanada’s network of
wholly owned pipelines extends more than 59,000 kilometres (36,500 miles),
tapping into virtually all major gas supply basins in North America. TransCanada
is one of the continent’s largest providers of gas storage and related services
with approximately 370 billion cubic feet of storage capacity. A growing
independent power producer, TransCanada owns, or has interests in, over 11,800
megawatts of power generation in Canada and the United States. TransCanada’s
common shares trade on the Toronto and New York stock exchanges under the symbol
TRP. For more information visit: www.transcanada.com
Forward-Looking
Information
This news
release may contain certain information that is forward looking and is subject
to important risks and uncertainties. The words "anticipate", "expect",
"believe", "may", "should", "estimate", "project", "outlook", "forecast" or
other similar words are used to identify such forward-looking information.
Forward-looking statements in this document are intended to provide TransCanada
security holders and potential investors with information regarding TransCanada
and its subsidiaries, including management’s assessment of TransCanada’s and its
subsidiaries’ future financial and operations plans and
outlook. Forward-looking statements in this document may include,
among others, statements regarding the anticipated business prospects and
financial performance of TransCanada and its subsidiaries, expectations or
projections about the future, and strategies and goals for growth and
expansion. All forward-looking
statements reflect TransCanada’s beliefs and assumptions based on information
available at the time the statements were made. Actual results or events may
differ from those predicted in these forward-looking statements. Factors that
could cause actual results or events to differ materially from current
expectations include, among others, the ability of TransCanada to successfully
implement its strategic initiatives and whether such strategic initiatives will
yield the expected benefits, the operating performance of TransCanada’s pipeline
and energy assets, the availability and price of energy commodities, capacity
payments, regulatory processes and decisions, changes in environmental and other
laws and regulations, competitive factors in the pipeline and energy sectors,
construction and completion of capital projects, labour, equipment and material
costs, access to capital markets, interest and currency exchange rates,
technological developments and the current economic conditions in North America.
By its nature, forward-looking information is subject to various risks and
uncertainties, which could cause TransCanada's actual results and experience to
differ materially from the anticipated results or expectations expressed.
Additional information on these and other factors is available in the reports
filed by TransCanada with Canadian securities regulators and with the U.S.
Securities and Exchange Commission (SEC). Readers are cautioned to not place
undue reliance on this forward-looking information, which is given as of the
date it is expressed in this news release or otherwise, and to not use
future-oriented information or financial outlooks for anything other than their
intended purpose. TransCanada 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
TransCanada
uses the measures "comparable earnings", "comparable earnings per common share",
"earnings before interest, taxes, depreciation and amortization" (EBITDA),
"comparable EBITDA", "earnings before interest and taxes" (EBIT), "comparable
EBIT" and "funds generated from operations" in this news release. These measures
do not have any standardized meaning prescribed by Canadian generally accepted
accounting principles (GAAP). They are, therefore, considered to be non-GAAP
measures and may not be comparable to similar measures presented by other
entities. Management of TransCanada uses these non-GAAP measures to improve its
ability to compare financial results among reporting periods and to enhance its
understanding of operating performance, liquidity and ability to generate funds
to finance operations. These non-GAAP measures are also provided to readers as
additional information on TransCanada’s operating performance, liquidity and
ability to generate funds to finance operations.
EBITDA is
an approximate measure of the Company’s pre-tax operating cash flow. EBITDA
comprises earnings before deducting interest and other financial charges, income
taxes, depreciation and amortization, and non-controlling interests. EBIT is a
measure of the Company’s earnings from ongoing operations. EBIT comprises
earnings before deducting interest and other financial charges, income taxes and
non-controlling interests.
Management
uses the measures of comparable earnings, EBITDA and EBIT to better evaluate
trends in the Company’s underlying operations. Comparable earnings, comparable
EBITDA and comparable EBIT comprise net income, EBITDA and EBIT, respectively,
adjusted for specific items that are significant, but are not reflective of the
Company’s underlying operations in the period. Specific items are subjective,
however, management uses its judgement and informed decision-making when
identifying items to be excluded in calculating comparable earnings, comparable
EBITDA and comparable EBIT, some of which may recur. Specific items may include
but
are not
limited to certain income tax refunds and adjustments, gains or losses on sales
of assets, legal and bankruptcy settlements, and certain fair value adjustments.
Comparable earnings per common share is calculated by dividing comparable
earnings by the weighted average number of common shares outstanding for the
period.
Funds
generated from operations comprises 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 Third Quarter
2009 Financial Highlights chart in this news release.
Third
Quarter 2009 Financial Highlights
|
(millions
of dollars)
|
2009
|
2008
|
2009
|
2008
|
|||||||||
|
Revenues
|
2,253
|
2,137
|
6,760
|
6,287
|
|||||||||
|
Comparable EBITDA(1)
|
994
|
|
1,066
|
3,142
|
|
3,081
|
|
||||||
|
Comparable EBIT(1)
|
651
|
748
|
2,108
|
2,138
|
|||||||||
|
EBIT(1)
|
665
|
746
|
2,102
|
2,386
|
|||||||||
|
Net
Income
|
345
|
390
|
993
|
1,163
|
|||||||||
|
Comparable Earnings(1)
|
335
|
366
|
997
|
1,008
|
|||||||||
|
Cash
Flows
|
|||||||||||||
|
Funds generated from
operations(1)
|
772
|
711
|
2,230
|
2,309
|
|||||||||
|
(Increase)/decrease in
operating working capital
|
(31
|
)
|
114
|
362
|
16
|
||||||||
|
Net cash provided by
operations
|
741
|
825
|
2,592
|
2,325
|
|||||||||
|
Capital
Expenditures
|
1,557
|
806
|
3,943
|
1,899
|
|||||||||
|
Acquisitions,
Net of Cash Acquired
|
653
|
3,054
|
902
|
3,058
|
Common
Share Statistics
|
Three
months ended September
30
|
Nine
months
ended September
30
|
||||||||||||||||
|
(unaudited)
|
2009
|
2008
|
2009
|
2008
|
|||||||||||||
|
Net
Income Per Share - Basic
|
$0.50
|
$0.67
|
$1.55
|
$2.07
|
|||||||||||||
|
Comparable Earnings Per
Share(1)
|
$0.49
|
$0.63
|
$1.56
|
$1.80
|
|||||||||||||
|
Dividends
Declared Per Share
|
$0.38
|
$0.36
|
$1.14
|
$1.08
|
|||||||||||||
|
Basic Common Shares Outstanding
(millions)
|
|||||||||||||||||
|
Average for the
period
|
681
|
579
|
641
|
560
|
|||||||||||||
|
End of period
|
681
|
580
|
681
|
580
|
|||||||||||||
|
|
(1)
|
Refer
to the Non-GAAP Measures section in this news release for further
discussion of comparable EBITDA, comparable EBIT, EBIT, comparable
earnings, comparable earnings per common share and funds generated from
operations.
|