TRANSCANADA CORPORATION | ||
By: | /s/ Gregory A. Lohnes | |
Gregory A. Lohnes | ||
Executive Vice-President and | ||
Chief Financial Officer | ||
By: | /s/ G. Glenn Menuz | |
G. Glenn Menuz | ||
Vice-President and Controller | ||
|
EXHIBIT
INDEX
|
§
|
For
fourth quarter
|
o
|
Net
income applicable to common shares of $381 million or $0.56 per
share
|
o
|
Comparable
earnings of $328 million or $0.48 per
share
|
o
|
Comparable
EBITDA of $965 million
|
o
|
Funds
generated from operations of $850
million
|
§
|
For
the year ended December 31
|
o
|
Net
income applicable to common shares of $1.4 billion or $2.11 per
share
|
o
|
Comparable
earnings of $1.3 billion or $2.03 per
share
|
o
|
Comparable
EBITDA of $4.1 billion
|
o
|
Funds
generated from operations of $3.1
billion
|
§
|
Invested
$6.3 billion to advance unprecedented $22 billion capital
program
|
§
|
Commissioning
of the first phase of the Keystone Oil Pipeline System (Keystone),
extending from Hardisty, Alberta to Wood River and Patoka, Illinois with
an initial nominal capacity of 435,000 barrels per day (Bbl/d), began in
late 2009 and commercial operations are expected to commence
mid-2010.
|
In September 2009, the National Energy Board (NEB) held a hearing to review the application for the new Canadian facilities required for the Keystone Gulf Coast expansion. A decision from the NEB is expected in first quarter 2010, approving a certificate for the construction and operation of the facilities, subject to Governor-in-Council approval, and the proposed tolling methodology. Facility permits for the U.S. portion of the expansion are expected by fourth quarter 2010. Construction of the expansion facilities is anticipated to commence in first quarter 2011 following the receipt of the necessary regulatory approvals. |
TransCanada
expects Keystone to begin generating EBITDA in 2010 with EBITDA increasing
through 2011, 2012 and 2013 as subsequent phases are placed in service.
Contracted volumes of 217,500 Bbl/d will increase to 910,000 Bbl/d from
2010 through to 2013 in conjunction with commencement of the Cushing and
Gulf Coast phases. Based on these current long-term commitments,
TransCanada expects to generate EBITDA of approximately US$1.2 billion
from Keystone in 2013, its first full year of commercial operation
servicing 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,
TransCanada would generate annual EBITDA of approximately US$1.5 billion
from Keystone. 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.
|
§
|
TransCanada
and ExxonMobil continued to advance the Alaska pipeline project by filing
an open season plan in the first quarter of 2010 with the U.S. Federal
Energy Regulatory Commission (FERC). The filing was made to obtain
approval to conduct the first natural gas pipeline open season to develop
Alaska’s vast natural gas resources. If the FERC approves the plan, the
project will commence its open season in April
2010.
|
§
|
TransCanada
and the other co-venture companies involved in the Mackenzie Gas Pipeline
Project (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. The regulatory process reached
a milestone in late December 2009 with the release of the Joint Review
Panel’s report on environmental and socio-economic factors relating to the
project. That report has been submitted into the NEB review process for
approval of the project, which is scheduled to conclude in April 2010 with
final arguments. A decision is currently expected by fourth quarter
2010.
|
§
|
In
November 2009, the NEB concluded a public hearing process on TransCanada’s
application for approval to construct and operate the Groundbirch
pipeline, which is comprised of a 77 kilometre (km) (48 miles) natural gas
pipeline and related above ground facilities. Upon approval, the
Groundbirch pipeline will be an extension of the Alberta System and is
expected to connect natural gas supply primarily from the Montney shale
gas formation in northeast B.C. to existing infrastructure in northwest
Alberta. Construction of the Groundbirch pipeline is expected to commence
in July 2010 with final completion anticipated in November 2010. A
decision from the NEB is expected in first quarter 2010. The proposed project
is expected to cost approximately $200 million with secured firm
transportation contracts that will reach 1.1 billion cubic feet per day
(Bcf/d) by 2014.
|
§
|
Total
contractual commitments for the Alberta System’s Horn River project have
increased from 378 million cubic feet per day (mmcf/d) to 503 mmcf/d by
2014 as a result of newly contracted volumes from a recently announced
natural gas processing facility that will be located in the Horn River
area of British Columbia. The Horn River project will connect
new shale gas supply in the Horn River development region to the Alberta
System. As part of the Horn River project, in November 2009, TransCanada
entered into an agreement to acquire the Ekwan Pipeline from EnCana
Corporation. This acquisition is expected to close in September 2011. In
February 2010, TransCanada filed an application with the NEB for approval
to construct and operate the Horn River project, including acquisition of
the Ekwan pipeline. Subject to regulatory approvals, the Horn River
project is anticipated to be placed in-service in second quarter
2012.
|
§
|
TransCanada
continued work on the 160 km (99 miles) Red Earth section of the North
Central Corridor (NCC) pipeline expansion of the Alberta System that is
expected to be completed by April 2010. The 140 km (87 miles) North Star
section was 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.
|
§
|
Regulatory
approvals were received in December 2009 for the approximate 305 km (190
miles), US$320 million Guadalajara natural gas pipeline project in
Mexico. Construction is underway with an expected in-service
date of first quarter 2011.
|
§
|
TransCanada
is expecting FERC approval in March 2010 of the Bison pipeline project, a
proposed 487 km (303 miles) natural gas pipeline. Once approval is
received, TransCanada will commence construction in May 2010. The project
has shipping commitments for approximately 407 mmcf/d and is expected to
be in service in fourth quarter 2010. The capital cost of the Bison
pipeline project is estimated to be US$600
million.
|
§
|
During
2009, TransCanada negotiated a Rate Design Settlement for the Alberta
System, which provided for a new rate design for the existing system and
expansions which addresses the evolving nature of the Alberta System and
the commercial and operational integration of ATCO Pipelines. The changes
are expected to improve the Alberta System services by making them more
consistent and adding flexibility for customers. TransCanada filed a
combination application with the NEB on November 27, 2009 for approval of
both the Rate Design Settlement and the integration of commercial and
operational services on the Alberta System and ATCO Pipelines’ system in
Alberta. A final decision is expected from the NEB by mid-2010 with
implementation occurring within 12 months following
approval.
|
§
|
In
October 2009, TransCanada placed into service the first phase of Kibby
Wind, which included 22 turbines capable of producing 66 MW of power.
Construction continues on the 66 MW second phase of the project, which
includes the installation of an additional 22 turbines. The second phase
is expected to be in service in third quarter
2010.
|
§
|
Construction
of the 683 MW Halton Hills power plant in Ontario and the 575 MW Coolidge
generating station in Arizona continued to progress on schedule with in
service dates of third quarter 2010 and second quarter 2011,
respectively.
|
§
|
Clearing
for the 58 MW Montagne-Sèche wind farm was completed in fourth quarter of
2009. The Montagne-Sèche project and phase one of the Gros-Morne wind farm
are expected to be operational in 2011. Gros-Morne phase two is
expected to be operational in 2012. These are the fourth and fifth
Québec-based wind farms of Cartier Wind, which is 62 per cent owned by
TransCanada.
|
§
|
Construction
activity is continuing on the refurbishment and restart of Bruce A Units 1
and 2 with a focus on the reassembly of the reactors and other related
activities. As of December 31, 2009, Bruce A had incurred approximately
$3.2 billion in costs for the refurbishment and restart of these units and
approximately $0.2 billion for the refurbishment of Units 3 and 4.
TransCanada believes that its share of the total capital cost to complete
the Unit 1 and 2 refurbishment and restart program will be approximately
$2 billion. The bulk of the highly technical, high-risk work on this
project is now finished or nearing completion. Although a significant
amount of work remains to be completed, most of the work is conventional
power plant construction activity. A project optimization plan implemented
by Bruce Power last year is achieving success in improving productivity.
TransCanada expects that Unit 2 will be restarted in mid-2011, with Unit 1
to follow approximately four months
later.
|
Bruce
Power continues to advance an initiative to further extend the operating
lives of Units 3 and 4. Unit 4 is now expected to continue to operate
beyond 2018 and plans are in place to implement an extensive maintenance
program that, if successful and approved by the Canadian Nuclear Safety
Commission would see the life of Unit 3 extended for a similar period of
time.
|
§
|
TransCanada’s
open seasons for capacity on its proposed Zephyr and Chinook power
transmission line projects closed in December 2009. A comprehensive review
of the bids will be undertaken. Each project would be capable of
delivering primarily renewable (wind) power originating in Wyoming
(Zephyr) and Montana (Chinook) to
Nevada.
|
§
|
The
Board of Directors of TransCanada declared a quarterly dividend of $0.40
per common share, an increase of five per cent, for the quarter ending
March 31, 2010, on TransCanada’s outstanding common
shares.
|
§
|
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 financing
its capital program.
|
Media
Inquiries:
|
Cecily
Dobson/Terry Cunha
|
403.920.7859
|
1.800.608.7859
|
||
Analyst
Inquiries:
|
David
Moneta/Myles Dougan/Terry Hook
|
403.920.7911
|
1.800.361.6522
|
(unaudited)
|
Three
months ended December 31
|
Year
ended December 31
|
|||||||||||||||
(millions
of dollars)
|
2009
|
2008
|
2009
|
2008
|
|||||||||||||
Revenues
|
2,206
|
2,332
|
8,966
|
8,619
|
|||||||||||||
Comparable EBITDA(1)
|
965
|
1,044
|
4,107
|
4,125
|
|
||||||||||||
Comparable EBIT(1)
|
622
|
740
|
2,730
|
2,878
|
|||||||||||||
EBIT(1)
|
658
|
747
|
2,760
|
3,133
|
|||||||||||||
Net
Income
|
387
|
277
|
1,380
|
1,440
|
|||||||||||||
Net
Income Applicable to Common Shares
|
381
|
277
|
1,374
|
1,440
|
|||||||||||||
Comparable Earnings(1)
|
328
|
271
|
1,325
|
1,279
|
|||||||||||||
Cash
Flows
|
|||||||||||||||||
Funds generated from
operations(1)
|
850
|
712
|
3,080
|
3,021
|
|||||||||||||
(Increase)/decrease in
operating working capital
|
(217
|
)
|
(150
|
)
|
(90
|
)
|
135
|
||||||||||
Net cash provided by
operations
|
633
|
562
|
2,990
|
3,156
|
|||||||||||||
Capital
Expenditures
|
1,474
|
1,235
|
5,417
|
3,134
|
|||||||||||||
Acquisitions,
Net of Cash Acquired
|
-
|
171
|
902
|
3,229
|
Three
months ended December 31
|
Year
ended December 31
|
||||||||||||||||
(unaudited)
|
2009
|
2008
|
2009
|
2008
|
|||||||||||||
Net
Income Per Share - Basic
|
$0.56
|
$0.47
|
$2.11
|
$2.53
|
|||||||||||||
Comparable Earnings Per
Share(1)
|
$0.48
|
$0.46
|
$2.03
|
$2.25
|
|||||||||||||
Dividends
Declared Per Share
|
$0.38
|
$0.36
|
$1.52
|
$1.44
|
|||||||||||||
Basic Common Shares Outstanding
(millions)
|
|||||||||||||||||
Average for the
period
|
683
|
597
|
652
|
570
|
|||||||||||||
End of period
|
684
|
616
|
684
|
616
|
(1)
|
Refer
to the Non-GAAP Measures section in this news release for further
discussion of comparable EBITDA, comparable EBIT, EBIT, comparable
earnings, funds generated from operations and comparable earnings per
share.
|
For
the three months ended December 31
|
||||||||||||||||||||
(unaudited)(millions
of dollars
|
Pipelines
|
Energy
|
Corporate
|
Total
|
||||||||||||||||
except
per share amounts)
|
2009
|
2008
|
2009
|
2008
|
2009
|
2008
|
2009
|
2008
|
||||||||||||
Comparable EBITDA(1)
|
745
|
780
|
248
|
297
|
(28
|
)
|
(33
|
)
|
965
|
1,044
|
||||||||||
Depreciation
and amortization
|
(257
|
)
|
(224
|
)
|
(86
|
)
|
(80
|
)
|
-
|
-
|
(343
|
)
|
(304
|
)
|
||||||
Comparable EBIT(1)
|
488
|
556
|
162
|
217
|
(28
|
)
|
(33
|
)
|
622
|
740
|
||||||||||
Specific
items:
|
||||||||||||||||||||
Dilution
gain from reduced interest in PipeLines LP
|
29
|
-
|
-
|
-
|
-
|
-
|
29
|
-
|
||||||||||||
Fair
value adjustments of natural gas inventory in storage and forward
contracts
|
-
|
-
|
7
|
7
|
-
|
-
|
7
|
7
|
||||||||||||
EBIT(1)
|
517
|
556
|
169
|
224
|
(28
|
)
|
(33
|
)
|
658
|
747
|
||||||||||
Interest
expense
|
(184
|
)
|
(326
|
)
|
||||||||||||||||
Interest
expense of joint ventures
|
(17
|
)
|
(21
|
)
|
||||||||||||||||
Interest
income and other
|
22
|
(4
|
)
|
|||||||||||||||||
Income
taxes
|
(67
|
)
|
(95
|
)
|
||||||||||||||||
Non-controlling
interests
|
(25
|
)
|
(24
|
)
|
||||||||||||||||
Net
Income
|
387
|
277
|
||||||||||||||||||
Preferred
share dividends
|
(6
|
)
|
-
|
|||||||||||||||||
Net
Income Applicable to Common Shares
|
381
|
277
|
||||||||||||||||||
Specific
items (net of tax, where applicable):
|
||||||||||||||||||||
Dilution
gain from reduced interest in PipeLines LP
|
(18
|
)
|
-
|
|||||||||||||||||
Fair
value adjustments of natural gas inventory in storage and forward
contracts
|
(5
|
)
|
(6
|
)
|
||||||||||||||||
Income
tax adjustments
|
(30
|
)
|
-
|
|||||||||||||||||
Comparable Earnings(1)
|
328
|
271
|
||||||||||||||||||
Net
Income Per Share
|
||||||||||||||||||||
- Basic (2)
|
$0.56
|
$0.47
|
||||||||||||||||||
-
Diluted
|
$0.56
|
$0.46
|
(1)
|
Refer
to the Non-GAAP Measures section in this news release for further
discussion of comparable EBITDA, comparable EBIT, EBIT, comparable
earnings and comparable earnings per
share.
|
(2)
|
For
the three months ended December 31
|
||||||||||||||||||||||||||||
(unaudited)
|
2009
|
2008
|
|||||||||||||||||||||||||||
Net
Income Per Share
|
$0.56
|
$0.47
|
|||||||||||||||||||||||||||
Specific items (net of tax,
where applicable):
|
|||||||||||||||||||||||||||||
Dilution
gain from reduced interest in PipeLines LP
|
(0.03
|
)
|
-
|
||||||||||||||||||||||||||
Fair
value adjustments of natural gas inventory in storage and forward
contracts
|
(0.01
|
)
|
(0.01
|
)
|
|||||||||||||||||||||||||
Income
tax adjustments
|
(0.04
|
)
|
-
|
||||||||||||||||||||||||||
Comparable Earnings Per
Share(1)
|
$0.48
|
$0.46
|
For
the year ended December 31
|
|||||||||||||||||||||||||||||
(unaudited)(millions
of dollars except
|
Pipelines
|
Energy
|
Corporate
|
Total
|
|||||||||||||||||||||||||
per
share amounts)
|
2009
|
2008
|
2009
|
2008
|
2009
|
2008
|
2009
|
2008
|
|||||||||||||||||||||
Comparable EBITDA(1)
|
3,093
|
3,019
|
1,131
|
1,210
|
(117
|
)
|
(104
|
)
|
4,107
|
4,125
|
|||||||||||||||||||
Depreciation
and amortization
|
(1,030
|
)
|
(989
|
)
|
(347
|
)
|
(258
|
)
|
-
|
-
|
(1,377
|
)
|
(1,247
|
)
|
|||||||||||||||
Comparable EBIT(1)
|
2,063
|
2,030
|
784
|
952
|
(117
|
)
|
(104
|
)
|
2,730
|
2,878
|
|||||||||||||||||||
Specific
items:
|
|||||||||||||||||||||||||||||
Dilution
gain from reduced interest in PipeLines LP
|
29
|
-
|
-
|
-
|
-
|
-
|
29
|
-
|
|||||||||||||||||||||
Fair value adjustments of natural
gas inventory in storage and forward contracts
|
-
|
-
|
1
|
-
|
-
|
-
|
1
|
-
|
|||||||||||||||||||||
Calpine bankruptcy
settlements
|
-
|
279
|
-
|
-
|
-
|
-
|
-
|
279
|
|||||||||||||||||||||
GTN lawsuit
settlement
|
-
|
17
|
-
|
-
|
-
|
-
|
-
|
17
|
|||||||||||||||||||||
Writedown of Broadwater LNG
project
costs
|
-
|
-
|
-
|
(41
|
)
|
-
|
-
|
-
|
(41
|
)
|
|||||||||||||||||||
EBIT(1)
|
2,092
|
2,326
|
785
|
911
|
(117
|
)
|
(104
|
)
|
2,760
|
3,133
|
|||||||||||||||||||
Interest
expense
|
(954
|
)
|
(943
|
)
|
|||||||||||||||||||||||||
Interest
expense of joint ventures
|
(64
|
)
|
(72
|
)
|
|||||||||||||||||||||||||
Interest
income and other
|
121
|
54
|
|||||||||||||||||||||||||||
Income
taxes
|
(387
|
)
|
(602
|
)
|
|||||||||||||||||||||||||
Non-controlling
interests
|
(96
|
)
|
(130
|
)
|
|||||||||||||||||||||||||
Net
Income
|
1,380
|
1,440
|
|||||||||||||||||||||||||||
Preferred
share dividends
|
(6
|
)
|
-
|
||||||||||||||||||||||||||
Net
Income Applicable to Common Shares
|
1,374
|
1,440
|
|||||||||||||||||||||||||||
Specific
items (net of tax, where applicable):
|
|||||||||||||||||||||||||||||
Dilution
gain from reduced interest in PipeLines LP
|
(18
|
)
|
-
|
||||||||||||||||||||||||||
Fair value adjustments of
natural gas inventory in storage and forward contracts
|
(1
|
)
|
-
|
||||||||||||||||||||||||||
Calpine bankruptcy
settlements
|
-
|
(152
|
)
|
||||||||||||||||||||||||||
GTN lawsuit
settlement
|
-
|
(10
|
)
|
||||||||||||||||||||||||||
Writedown of Broadwater LNG
project costs
|
-
|
27
|
|||||||||||||||||||||||||||
Income
tax adjustments
|
(30
|
)
|
(26
|
)
|
|||||||||||||||||||||||||
Comparable Earnings(1)
|
1,325
|
1,279
|
|||||||||||||||||||||||||||
Net
Income Per Share
|
|||||||||||||||||||||||||||||
- Basic (2)
|
$2.11
|
$2.53
|
|||||||||||||||||||||||||||
-
Diluted
|
$2.11
|
$2.52
|
(1)
|
Refer
to the Non-GAAP Measures section in this news release for further
discussion of comparable EBITDA, comparable EBIT, EBIT, comparable
earnings and comparable earnings per
share.
|
(2)
|
For
the year ended December 31
|
||||||
(unaudited)
|
2009
|
2008
|
|||||
Net
Income Per Share
|
$2.11
|
$2.53
|
|||||
Specific items (net of tax,
where applicable):
|
|||||||
Dilution
gain from reduced interest in PipeLines LP
|
(0.03
|
)
|
-
|
||||
Calpine bankruptcy
settlements
|
-
|
(0.27
|
)
|
||||
GTN
lawsuit settlement
|
-
|
(0.02
|
)
|
||||
Writedown
of Broadwater LNG project costs
|
-
|
0.05
|
|||||
Income
tax adjustments
|
(0.05
|
)
|
(0.04
|
)
|
|||
Comparable Earnings Per
Share(1)
|
$2.03
|
$2.25
|
·
|
decreased
EBIT from Pipelines primarily due to the negative impact of a weaker U.S.
dollar on Pipeline’s U.S. operations and increased business development
costs related to the Alaska pipeline project. These decreases were
partially offset by an $18 million after tax ($29 million pre-tax)
dilution gain resulting from TransCanada’s reduced ownership interest in
PipeLines LP following PipeLines LP’s public issuance of common
units.
|
·
|
decreased
EBIT from Energy primarily due to lower power prices in Western Power and
U.S. Power, and the impact of a weaker U.S. dollar on Energy’s U.S.
operations, partially offset by higher contribution from the Natural Gas
Storage business due to increased third party storage revenues and
increased earnings as a result of the start up of Portlands
Energy.
|
·
|
decreased
interest expense primarily due to increased capitalized interest, reduced
losses from changes in the fair value of interest rate derivatives used to
manage TransCanada’s exposure to fluctuating interest rates and the
positive impact of a weaker U.S. dollar. These decreases were partially
offset by incremental interest expense for new debt issuances in
2009.
|
·
|
increased
interest income and other due to the positive impact of a weaker U.S.
dollar on working capital balances and changes in the fair value of
derivatives used to manage the Company’s exposure to foreign exchange rate
fluctuations; and
|
·
|
decreased
income tax expense primarily due to positive income tax adjustments in
fourth quarter 2009, including $30 million resulting from a reduction in
the Province of Ontario’s corporate income tax rates, partially offset by
higher pre-tax income.
|
•
|
increased
comparable EBIT from Pipelines primarily due to higher earnings from the
Alberta System revenue requirement settlement and the positive impact in
2009 of a stronger U.S. dollar on Pipelines’ U.S. operations, partially
offset by increased costs for developing new Pipelines projects, primarily
the Alaska pipeline project;
|
•
|
decreased
comparable EBIT from Energy primarily due to lower power prices and a
decreased demand for power in Western Power and U.S. Power, reflecting the
downturn in the North American economy, partially offset by increased
earnings from the start up of Portlands Energy and the Carleton phase of
the Cartier Wind project, and higher realized power prices for Bruce
Power;
|
•
|
increased
comparable EBIT losses from Corporate primarily due to higher support
services costs, reflecting a growing asset
base;
|
•
|
increased
interest expense as a result of long-term debt issuances in the second
half of 2008 and first quarter 2009 and the negative impact of a stronger
U.S. dollar. These increases were partially offset by an increase in
capitalized interest relating to Keystone and other capital projects and
reduced losses from changes in the fair value of derivatives used to
manage TransCanada’s exposure to fluctuating interest
rates;
|
•
|
the
positive impact of a weakening U.S. dollar throughout 2009 on working
capital balances and higher gains from derivatives used to manage the
Company’s exposure to foreign exchange rate
fluctuations;
|
•
|
decreased
income tax expense due to lower pre-tax earnings, higher income tax
savings from income tax rate differentials and other positive income tax
adjustments in 2009; and
|
•
|
a
reduction in non-controlling interests due to Portland’s portion of the
Calpine bankruptcy settlements recorded in 2008, partially offset by
higher PipeLines LP earnings in
2009.
|
(unaudited)
|
Three
months ended December 31
|
Year
ended December 31
|
|||||||||||
(millions
of dollars)
|
2009
|
2008
|
2009
|
2008
|
|||||||||
Canadian
Pipelines
|
|||||||||||||
Canadian
Mainline
|
282
|
300
|
1,133
|
1,141
|
|||||||||
Alberta
System
|
193
|
152
|
728
|
692
|
|||||||||
Foothills
|
32
|
31
|
132
|
133
|
|||||||||
Other
(TQM, Ventures LP)
|
15
|
11
|
59
|
50
|
|||||||||
Canadian Pipelines Comparable
EBITDA(1)
|
522
|
494
|
2,052
|
2,016
|
|||||||||
U.S.
Pipelines
|
|||||||||||||
ANR
|
84
|
99
|
347
|
347
|
|||||||||
GTN(2)
|
43
|
52
|
195
|
198
|
|||||||||
Great
Lakes
|
30
|
34
|
138
|
127
|
|||||||||
PipeLines
LP(2)(3)
|
20
|
23
|
84
|
70
|
|||||||||
Iroquois
|
16
|
17
|
78
|
59
|
|||||||||
Portland(4)
|
8
|
9
|
26
|
27
|
|||||||||
International
(Tamazunchale, TransGas, Gas
Pacifico/INNERGY)
|
12
|
8
|
58
|
40
|
|||||||||
General,
administrative and support costs(5)
|
-
|
(1
|
)
|
(17
|
)
|
(15
|
)
|
||||||
Non-controlling
interests(6)
|
46
|
54
|
194
|
187
|
|||||||||
U.S. Pipelines Comparable
EBITDA(1)
|
259
|
295
|
1,103
|
1,040
|
|||||||||
Business Development Comparable
EBITDA(1)
|
(36
|
)
|
(9
|
)
|
(62
|
)
|
(37
|
)
|
|||||
Pipelines Comparable
EBITDA(1)
|
745
|
780
|
3,093
|
3,019
|
|||||||||
Depreciation
and amortization
|
(257
|
)
|
(224
|
)
|
(1,030
|
)
|
(989
|
)
|
|||||
Pipelines Comparable
EBIT(1)
|
488
|
556
|
2,063
|
2,030
|
|||||||||
Specific
items:
|
|||||||||||||
Dilution gain from reduced
interest in PipeLines LP(3)(7)
|
29
|
-
|
29
|
-
|
|||||||||
Calpine bankruptcy
settlements(8)
|
-
|
-
|
-
|
279
|
|||||||||
GTN lawsuit
settlement
|
-
|
-
|
-
|
17
|
|||||||||
Pipelines EBIT(1)
|
517
|
556
|
2,092
|
2,326
|
(1)
|
Refer
to the Non-GAAP Measures section in this news release for further
discussion of comparable EBITDA, comparable EBIT and
EBIT.
|
(2)
|
GTN’s
results include North Baja until July 1, 2009 when it was sold to
PipeLines LP.
|
(3)
|
Effective
November 18, 2009, PipeLines LP’s results reflect TransCanada’s ownership
interest in PipeLines LP of 38.2 per cent. From July 1, 2009 to November
17, 2009, TransCanada’s ownership interest in PipeLines LP was 42.6 per
cent. From January 1, 2008 to June 30, 2009, TransCanada’s ownership
interest in PipeLines LP was 32.1 per
cent.
|
(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)
|
Non-controlling
interests reflects EBITDA for the portions of PipeLines LP and Portland
not owned by TransCanada.
|
(7)
|
As
a result of PipeLines LP issuing common units to the public, the Company’s
ownership in PipeLines LP was reduced to 38.2 per cent from 42.6 per cent
and a dilution gain of $29 million was
realized.
|
(8)
|
GTN
and Portland received shares of Calpine with an initial value of $154
million and $103 million, respectively, as a result of the bankruptcy
settlements with Calpine. These shares were subsequently sold for an
additional gain of $22 million.
|
(unaudited)
|
Three
months ended December 31
|
Year
ended December 31
|
|||||||||||
(millions
of dollars)
|
2009
|
2008
|
2009
|
2008
|
|||||||||
Canadian
Mainline
|
72
|
74
|
273
|
278
|
|||||||||
Alberta
System
|
45
|
48
|
168
|
145
|
|||||||||
Foothills
|
5
|
5
|
23
|
24
|
(unaudited)
|
Three
months ended December 31
|
Year
ended December 31
|
|||||||||||||||
(millions
of dollars)
|
2009
|
2008
|
2009
|
2008
|
|||||||||||||
Canadian
Power
|
|||||||||||||||||
Western
Power
|
61
|
128
|
279
|
510
|
|||||||||||||
Eastern
Power(1)
|
56
|
43
|
220
|
147
|
|||||||||||||
Bruce
Power
|
70
|
70
|
352
|
275
|
|||||||||||||
General,
administrative and support costs
|
(11
|
)
|
(11
|
)
|
(39
|
)
|
(39
|
)
|
|||||||||
Canadian Power Comparable
EBITDA(2)
|
176
|
230
|
812
|
893
|
|||||||||||||
U.S. Power(3)
|
|||||||||||||||||
Northeast
Power
|
39
|
63
|
237
|
272
|
|||||||||||||
General,
administrative and support costs
|
(10
|
)
|
(13
|
)
|
(45
|
)
|
(41
|
)
|
|||||||||
U.S. Power Comparable
EBITDA(2)
|
29
|
50
|
192
|
231
|
|||||||||||||
Natural
Gas Storage
|
|||||||||||||||||
Alberta
Storage
|
51
|
38
|
173
|
152
|
|||||||||||||
General,
administrative and support costs
|
(2
|
)
|
(4
|
)
|
(9
|
)
|
(14
|
)
|
|||||||||
Natural Gas Storage Comparable
EBITDA(2)
|
49
|
34
|
164
|
138
|
|||||||||||||
Business Development Comparable
EBITDA(2)
|
(6
|
)
|
(17
|
)
|
(37
|
)
|
(52
|
)
|
|||||||||
Energy Comparable
EBITDA(2)
|
248
|
297
|
1,131
|
1,210
|
|||||||||||||
Depreciation
and amortization
|
(86
|
)
|
(80
|
)
|
(347
|
)
|
(258
|
)
|
|||||||||
Energy Comparable
EBIT(2)
|
162
|
217
|
784
|
952
|
|||||||||||||
Specific
items:
|
|||||||||||||||||
Fair
value adjustments of natural gas inventory in storage and forward
contracts
|
7
|
7
|
1
|
-
|
|||||||||||||
Writedown of Broadwater LNG
project costs
|
-
|
-
|
-
|
(41
|
)
|
||||||||||||
Energy EBIT(2)
|
169
|
224
|
785
|
911
|
(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 news release for further
discussion of comparable EBITDA, comparable EBIT and
EBIT.
|
(3)
|
Includes
phase one of Kibby Wind and Ravenswood effective October 2009 and August
2008, respectively.
|
(unaudited)
|
Three
months ended December 31
|
Year
ended December 31
|
||||||||||||||||
(millions
of dollars)
|
2009
|
2008
|
2009
|
2008
|
||||||||||||||
Revenues
|
||||||||||||||||||
Western power
|
203
|
298
|
788
|
1,140
|
||||||||||||||
Eastern power
|
72
|
54
|
281
|
175
|
||||||||||||||
Other(3)
|
62
|
51
|
184
|
186
|
||||||||||||||
337
|
403
|
1,253
|
1,501
|
|||||||||||||||
Commodity
Purchases Resold
|
||||||||||||||||||
Western power
|
(124
|
)
|
(137
|
)
|
(451
|
)
|
(517
|
)
|
||||||||||
Eastern power
|
-
|
2
|
-
|
-
|
||||||||||||||
Other(4)
|
(44
|
)
|
(41
|
)
|
(124
|
)
|
(112
|
)
|
||||||||||
(168
|
)
|
(176
|
)
|
(575
|
)
|
(629
|
)
|
|||||||||||
Plant
operating costs and other
|
(49
|
)
|
(57
|
)
|
(178
|
)
|
(216
|
)
|
||||||||||
General,
administrative and support costs
|
(11
|
)
|
(11
|
)
|
(39
|
)
|
(39
|
)
|
||||||||||
Other
(expenses)/income
|
(3
|
)
|
1
|
(1
|
)
|
1
|
||||||||||||
Comparable EBITDA(1)
|
106
|
160
|
460
|
618
|
(1)
|
Refer
to the Non-GAAP Measures section in this news release for further
discussion of comparable EBITDA.
|
(2)
|
Includes
Portlands Energy and the Carleton wind farm effective April 2009 and
November 2008, respectively.
|
(3)
|
Other
revenue includes sales of natural gas, sulphur (in 2008) and thermal
carbon black.
|
(4)
|
Other
commodity purchases resold includes the cost of natural gas
sold.
|
Three
months ended December 31
|
Year
ended December 31
|
|||||||||||||||
(unaudited)
|
2009
|
2008
|
2009
|
2008
|
||||||||||||
Sales
Volumes (GWh)(2)
|
||||||||||||||||
Supply
|
||||||||||||||||
Generation
|
||||||||||||||||
Western Power
|
616
|
589
|
2,334
|
2,322
|
||||||||||||
Eastern Power
|
469
|
332
|
1,550
|
1,069
|
||||||||||||
Purchased
|
||||||||||||||||
Sundance A & B and
Sheerness PPAs
|
2,878
|
3,225
|
10,603
|
12,368
|
||||||||||||
Other
purchases
|
109
|
181
|
529
|
970
|
||||||||||||
4,072
|
4,327
|
15,016
|
16,729
|
|||||||||||||
Sales
|
||||||||||||||||
Contracted
|
||||||||||||||||
Western Power
|
2,780
|
2,705
|
9,944
|
11,284
|
||||||||||||
Eastern Power
|
471
|
333
|
1,588
|
1,232
|
||||||||||||
Spot
|
||||||||||||||||
Western Power
|
821
|
1,289
|
3,484
|
4,213
|
||||||||||||
4,072
|
4,327
|
15,016
|
16,729
|
(1)
|
Includes
Portlands Energy and the Carleton wind farm effective April 2009 and
November 2008, respectively.
|
(2)
|
Gigawatt
hours.
|
(TransCanada’s proportionate
share)
(unaudited)
|
Three
months ended December 31
|
Year
ended
December
31
|
||||||||||||||
(millions
of dollars unless otherwise indicated)
|
2009
|
2008
|
2009
|
2008
|
||||||||||||
Revenues(1)(2)
|
198
|
182
|
883
|
785
|
||||||||||||
Operating
Expenses(2)
|
(128
|
)
|
(112
|
)
|
(531
|
)
|
(510
|
)
|
||||||||
Comparable EBITDA(3)
|
70
|
70
|
352
|
275
|
||||||||||||
Bruce A Comparable
EBITDA(3)
|
(29
|
)
|
(1
|
)
|
48
|
78
|
||||||||||
Bruce B Comparable
EBITDA(3)
|
99
|
71
|
304
|
197
|
||||||||||||
Comparable EBITDA(3)
|
70
|
70
|
352
|
275
|
||||||||||||
Bruce
Power – Other Information
|
||||||||||||||||
Plant
availability
|
||||||||||||||||
Bruce A
|
47%
|
62%
|
78%
|
82%
|
||||||||||||
Bruce B
|
95%
|
98%
|
91%
|
87%
|
||||||||||||
Combined Bruce
Power
|
80%
|
86%
|
87%
|
86%
|
||||||||||||
Planned
outage days
|
||||||||||||||||
Bruce A
|
10
|
46
|
56
|
91
|
||||||||||||
Bruce B
|
-
|
-
|
45
|
100
|
||||||||||||
Unplanned
outage days
|
||||||||||||||||
Bruce A
|
74
|
17
|
82
|
27
|
||||||||||||
Bruce B
|
3
|
5
|
47
|
65
|
||||||||||||
Sales
volumes (GWh)
|
||||||||||||||||
Bruce A
|
737
|
977
|
4,894
|
5,159
|
||||||||||||
Bruce B
|
2,016
|
2,218
|
7,767
|
7,799
|
||||||||||||
2,753
|
3,195
|
12,661
|
12,958
|
|||||||||||||
Results
per MWh
|
||||||||||||||||
Bruce A power
revenues
|
$64
|
$63
|
$64
|
$62
|
||||||||||||
Bruce B power revenues(4)
|
$62
|
$57
|
$64
|
$57
|
||||||||||||
Combined Bruce Power
revenues
|
$62
|
$58
|
$64
|
$59
|
||||||||||||
Percentage
of Bruce B output sold to spot market(5)
|
46%
|
24%
|
43%
|
33%
|
(1)
|
Revenues
include Bruce A’s fuel cost recoveries of $6 million and $34 million for
fourth quarter and the year ended December 31, 2009, respectively (2008 -
$8 million and $30 million, respectively). Revenues also include Bruce B
unrealized gains of $1 million and $5 million as a result of changes in
the fair value of held-for-trading derivatives for fourth quarter and the
year ended December 31, 2009, respectively (2008 – losses of $1 million
and $2 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 news release for further
discussion of comparable EBITDA.
|
(4)
|
Includes
revenues received under the floor price mechanism, contract settlements,
deemed generation and the associated generation and deemed generation
volumes.
|
(5)
|
All
of Bruce B’s output is covered by the floor price mechanism, including
volumes sold to the spot market.
|
(unaudited)
|
Three
months ended December 31
|
Year
ended December 31
|
||||||||||||||||
(millions
of dollars)
|
2009
|
2008
|
2009
|
2008
|
||||||||||||||
Revenues
|
||||||||||||||||||
Power
|
233
|
282
|
1,118
|
938
|
||||||||||||||
Capacity
|
40
|
37
|
190
|
85
|
||||||||||||||
Other(3)(4)
|
145
|
92
|
509
|
350
|
||||||||||||||
418
|
411
|
1,817
|
1,373
|
|||||||||||||||
Commodity
Purchases Resold
|
||||||||||||||||||
Power
|
(125
|
)
|
(159
|
)
|
(544
|
)
|
(519
|
)
|
||||||||||
Other(5)
|
(120
|
)
|
(85
|
)
|
(391
|
)
|
(324
|
)
|
||||||||||
(245
|
)
|
(244
|
)
|
(935
|
)
|
(843
|
)
|
|||||||||||
Plant
operating costs and other(4)
|
(134
|
)
|
(104
|
)
|
(645
|
)
|
(258
|
)
|
||||||||||
General,
administrative and support costs
|
(10
|
)
|
(13
|
)
|
(45
|
)
|
(41
|
)
|
||||||||||
Comparable EBITDA(1)
|
29
|
50
|
192
|
231
|
(1)
|
Refer
to the Non-GAAP Measures section of this news release for further
discussion of comparable EBITDA.
|
(2)
|
Includes
phase one of Kibby Wind and Ravenswood effective October 2009 and August
2008, respectively.
|
(3)
|
Other
revenue includes sales of natural
gas.
|
(4)
|
Includes
revenues and costs at Ravenswood related to a third-party service
agreement.
|
(5)
|
Other
commodity purchases resold includes the cost of natural gas
sold.
|
Three
months ended December 31
|
Year
ended December 31
|
||||||||||||||||
(unaudited)
|
2009
|
2008
|
2009
|
2008
|
|||||||||||||
Sales
Volumes (GWh)
|
|||||||||||||||||
Supply
|
|||||||||||||||||
Generation
|
1,400
|
1,127
|
5,993
|
3,974
|
|||||||||||||
Purchased
|
1,657
|
1,637
|
5,310
|
6,020
|
|||||||||||||
3,057
|
2,764
|
11,303
|
9,994
|
||||||||||||||
Sales
|
|||||||||||||||||
Contracted
|
2,999
|
2,726
|
10,264
|
9,758
|
|||||||||||||
Spot
|
58
|
38
|
1,039
|
236
|
|||||||||||||
3,057
|
2,764
|
11,303
|
9,994
|
(1)
|
Includes
phase one of Kibby Wind and Ravenswood effective October 2009 and August
2008, respectively.
|
(unaudited)
|
Three
months ended December 31
|
Year
ended December 31
|
|||||||||||||||
(million
of dollars)
|
2009
|
2008
|
2009
|
2008
|
|||||||||||||
Interest
on long-term debt(1)
|
304
|
299
|
1,285
|
1,038
|
|||||||||||||
Other
interest and amortization
|
8
|
71
|
27
|
46
|
|||||||||||||
Capitalized
interest
|
(128
|
)
|
(44
|
)
|
(358
|
)
|
(141
|
)
|
|||||||||
184
|
326
|
954
|
943
|
(1)
|
Includes
interest for Junior Subordinated
Notes.
|
(unaudited)
|
|||||||||||||||||
(millions
of dollars except number of shares and
|
Three
months ended December 31
|
Year
ended December 31
|
|||||||||||||||
per
share amounts)
|
2009
|
2008
|
2009
|
2008
|
|||||||||||||
Revenues
|
2,206
|
2,332
|
8,966
|
8,619
|
|||||||||||||
Operating
and Other Expenses/(Income)
|
|||||||||||||||||
Plant
operating costs and other
|
823
|
857
|
3,367
|
3,014
|
|||||||||||||
Commodity
purchases resold
|
411
|
424
|
1,511
|
1,501
|
|||||||||||||
Other
income
|
(29
|
)
|
-
|
(49
|
)
|
(38
|
)
|
||||||||||
Calpine
bankruptcy settlements
|
-
|
-
|
-
|
(279
|
)
|
||||||||||||
Writedown
of Broadwater LNG project costs
|
-
|
-
|
-
|
41
|
|||||||||||||
1,205
|
1,281
|
4,829
|
4,239
|
||||||||||||||
1,001
|
1,051
|
4,137
|
4,380
|
||||||||||||||
Depreciation
and amortization
|
343
|
304
|
1,377
|
1,247
|
|||||||||||||
658
|
747
|
2,760
|
3,133
|
||||||||||||||
Financial
Charges/(Income)
|
|||||||||||||||||
Interest
expense
|
184
|
326
|
954
|
943
|
|||||||||||||
Interest
expense of joint ventures
|
17
|
21
|
64
|
72
|
|||||||||||||
Interest
income and other
|
(22
|
)
|
4
|
(121
|
)
|
(54
|
)
|
||||||||||
179
|
351
|
897
|
961
|
||||||||||||||
Income
before Income Taxes and Non-Controlling Interests
|
479
|
396
|
1,863
|
2,172
|
|||||||||||||
Income
Taxes
|
|||||||||||||||||
Current
|
(73
|
)
|
47
|
30
|
526
|
||||||||||||
Future
|
140
|
48
|
357
|
76
|
|||||||||||||
67
|
95
|
387
|
602
|
||||||||||||||
Non-Controlling
Interests
|
|||||||||||||||||
Non-controlling
interest in PipeLines LP
|
15
|
16
|
66
|
62
|
|||||||||||||
Preferred
share dividends of subsidiary
|
5
|
5
|
22
|
22
|
|||||||||||||
Non-controlling
interest in Portland
|
5
|
3
|
8
|
46
|
|||||||||||||
25
|
24
|
96
|
130
|
||||||||||||||
Net
Income
|
387
|
277
|
1,380
|
1,440
|
|||||||||||||
Preferred
Share Dividends
|
6
|
-
|
6
|
-
|
|||||||||||||
Net
Income Applicable to Common Shares
|
381
|
277
|
1,374
|
1,440
|
|||||||||||||
Net
Income Per Common Share
|
|||||||||||||||||
Basic
|
$0.56
|
$0.47
|
$2.11
|
$2.53
|
|||||||||||||
Diluted
|
$0.56
|
$0.46
|
$2.11
|
$2.52
|
|||||||||||||
Average Common Shares
Outstanding – Basic (millions)
|
683
|
597
|
652
|
570
|
|||||||||||||
Average Common Shares
Outstanding – Diluted (millions)
|
684
|
599
|
653
|
572
|
Three
months ended December 31
|
Year
ended December 31
|
||||||||||||
(unaudited)(millions
of dollars)
|
2009
|
2008
|
2009
|
2008
|
|||||||||
Cash
Generated From Operations
|
|||||||||||||
Net
income
|
387
|
277
|
1,380
|
1,440
|
|||||||||
Depreciation
and amortization
|
343
|
304
|
1,377
|
1,247
|
|||||||||
Future
income taxes
|
140
|
48
|
357
|
76
|
|||||||||
Non-controlling
interests
|
25
|
24
|
96
|
130
|
|||||||||
Employee
future benefits funding (in excess of)/lower than expense
|
(32
|
)
|
(6
|
)
|
(111
|
)
|
17
|
||||||
Writedown
of Broadwater LNG project costs
|
-
|
-
|
-
|
41
|
|||||||||
Other
|
(13
|
)
|
65
|
(19
|
)
|
70
|
|||||||
850
|
712
|
3,080
|
3,021
|
||||||||||
(Increase)/decrease
in operating working capital
|
(217
|
)
|
(150
|
)
|
(90
|
)
|
135
|
||||||
Net
cash provided by operations
|
633
|
562
|
2,990
|
3,156
|
|||||||||
Investing
Activities
|
|||||||||||||
Capital
expenditures
|
(1,474
|
)
|
(1,235
|
)
|
(5,417
|
)
|
(3,134
|
)
|
|||||
Acquisitions,
net of cash acquired
|
-
|
(171
|
)
|
(902
|
)
|
(3,229
|
)
|
||||||
Disposition
of assets, net of current income taxes
|
-
|
7
|
-
|
28
|
|||||||||
Deferred
amounts and other
|
(300
|
)
|
(372
|
)
|
(594
|
)
|
(484
|
)
|
|||||
Net
cash used in investing activities
|
(1,774
|
)
|
(1,771
|
)
|
(6,913
|
)
|
(6,819
|
)
|
|||||
Financing
Activities
|
|||||||||||||
Dividends
on common and preferred shares
|
(193
|
)
|
(167
|
)
|
(728
|
)
|
(577
|
)
|
|||||
Distributions
paid to non-controlling interests
|
(24
|
)
|
(31
|
)
|
(100
|
)
|
(141
|
)
|
|||||
Notes
payable issued/(repaid), net
|
363
|
827
|
(244
|
)
|
1,293
|
||||||||
Long-term
debt issued, net of issue costs
|
-
|
-
|
3,267
|
2,197
|
|||||||||
Reduction
of long-term debt
|
(496
|
)
|
(52
|
)
|
(1,005
|
)
|
(840
|
)
|
|||||
Long-term
debt of joint ventures issued
|
25
|
16
|
226
|
173
|
|||||||||
Reduction
of long-term debt of joint ventures
|
(138
|
)
|
(19
|
)
|
(246
|
)
|
(120
|
)
|
|||||
Common
shares issued, net of issue costs
|
15
|
1,132
|
1,820
|
2,384
|
|||||||||
Partnership
units of subsidiary issued, net of issue costs
|
193
|
-
|
193
|
-
|
|||||||||
Preferred
shares issued, net of issue costs
|
-
|
-
|
539
|
-
|
|||||||||
Net
cash (used in)/provided by financing activities
|
(255
|
)
|
1,706
|
3,722
|
4,369
|
||||||||
Effect
of Foreign Exchange Rate Changes on Cash and Cash
Equivalents
|
(13
|
)
|
59
|
(110
|
)
|
98
|
|||||||
(Decrease)/Increase
in Cash and Cash Equivalents
|
(1,409
|
)
|
556
|
(311
|
)
|
804
|
|||||||
Cash
and Cash Equivalents
|
|||||||||||||
Beginning
of period
|
2,406
|
752
|
1,308
|
504
|
|||||||||
Cash
and Cash Equivalents
|
|||||||||||||
End
of period
|
997
|
1,308
|
997
|
1,308
|
|||||||||
December
31
|
|||||||
(unaudited)(millions
of dollars)
|
2009
|
2008
|
|||||
ASSETS
|
|||||||
Current
Assets
|
|||||||
Cash
and cash equivalents
|
997
|
1,308
|
|||||
Accounts
receivable
|
966
|
1,280
|
|||||
Inventories
|
511
|
489
|
|||||
Other
|
701
|
523
|
|||||
3,175
|
3,600
|
||||||
Plant,
Property and Equipment
|
32,879
|
29,189
|
|||||
Goodwill
|
3,763
|
4,397
|
|||||
Regulatory
Assets
|
1,524
|
201
|
|||||
Intangibles
and Other Assets
|
2,500
|
2,027
|
|||||
43,841
|
39,414
|
||||||
LIABILITIES
AND SHAREHOLDERS’ EQUITY
|
|||||||
Current
Liabilities
|
|||||||
Notes
payable
|
1,687
|
1,702
|
|||||
Accounts
payable
|
2,195
|
2,110
|
|||||
Accrued
interest
|
377
|
359
|
|||||
Current
portion of long-term debt
|
478
|
786
|
|||||
Current
portion of long-term debt of joint ventures
|
212
|
207
|
|||||
4,949
|
5,164
|
||||||
Regulatory
Liabilities
|
385
|
317
|
|||||
Deferred
Amounts
|
743
|
1,168
|
|||||
Future
Income Taxes
|
2,856
|
1,223
|
|||||
Long-Term
Debt
|
16,186
|
15,368
|
|||||
Long-Term
Debt of Joint Ventures
|
753
|
869
|
|||||
Junior
Subordinated Notes
|
1,036
|
1,213
|
|||||
26,908
|
25,322
|
||||||
Non-Controlling
Interests
|
|||||||
Non-controlling
interest in PipeLines LP
|
705
|
721
|
|||||
Preferred
shares of subsidiary
|
389
|
389
|
|||||
Non-controlling
interest in Portland
|
80
|
84
|
|||||
1,174
|
1,194
|
||||||
Shareholders’
Equity
|
15,759
|
12,898
|
|||||
43,841
|
39,414
|
Three
months ended December 31
|
Pipelines
|
Energy
|
Corporate
|
Total
|
||||||||||||||||
(unaudited)(millions
of dollars)
|
2009
|
2008
|
2009
|
2008
|
2009
|
2008
|
2009
|
2008
|
||||||||||||
Revenues
|
1,171
|
1,233
|
1,035
|
1,099
|
-
|
-
|
2,206
|
2,332
|
||||||||||||
Plant
operating costs and other
|
(428
|
)
|
(451
|
)
|
(368
|
)
|
(373
|
)
|
(27
|
)
|
(33
|
)
|
(823
|
)
|
(857
|
)
|
||||
Commodity
purchases resold
|
-
|
-
|
(411
|
)
|
(424
|
)
|
-
|
-
|
(411
|
)
|
(424
|
)
|
||||||||
Other
income/(expense)
|
31
|
(2
|
)
|
(1
|
)
|
2
|
(1
|
)
|
-
|
29
|
-
|
|||||||||
774
|
780
|
255
|
304
|
(28
|
)
|
(33
|
)
|
1,001
|
1,051
|
|||||||||||
Depreciation
and amortization
|
(257
|
)
|
(224
|
)
|
(86
|
)
|
(80
|
)
|
-
|
-
|
(343
|
)
|
(304
|
)
|
||||||
517
|
556
|
169
|
224
|
(28
|
)
|
(33
|
)
|
658
|
747
|
|||||||||||
Interest
expense
|
(184
|
)
|
(326
|
)
|
||||||||||||||||
Interest
expense of joint ventures
|
(17
|
)
|
(21
|
)
|
||||||||||||||||
Interest
income and other
|
22
|
(4
|
)
|
|||||||||||||||||
Income
taxes
|
(67
|
)
|
(95
|
)
|
||||||||||||||||
Non-controlling
interests
|
(25
|
)
|
(24
|
)
|
||||||||||||||||
Net
Income
|
387
|
277
|
||||||||||||||||||
Preferred
share dividends
|
(6
|
)
|
-
|
|||||||||||||||||
Net
Income Applicable to Common Shares
|
381
|
277
|
Year
ended December 31
|
Pipelines
|
Energy
|
Corporate
|
Total
|
||||||||||||||||
(unaudited)(millions
of dollars)
|
2009
|
2008
|
2009
|
2008
|
2009
|
2008
|
2009
|
2008
|
||||||||||||
Revenues
|
4,729
|
4,650
|
4,237
|
3,969
|
-
|
-
|
8,966
|
8,619
|
||||||||||||
Plant
operating costs and other
|
(1,655
|
)
|
(1,645
|
)
|
(1,595
|
)
|
(1,259
|
)
|
(117
|
)
|
(110
|
)
|
(3,367
|
)
|
(3,014
|
)
|
||||
Commodity
purchases resold
|
-
|
-
|
(1,511
|
)
|
(1,501
|
)
|
-
|
-
|
(1,511
|
)
|
(1,501
|
)
|
||||||||
Other
income
|
48
|
31
|
1
|
1
|
-
|
6
|
49
|
38
|
||||||||||||
Calpine
bankruptcy settlements
|
-
|
279
|
-
|
-
|
-
|
-
|
-
|
279
|
||||||||||||
Writedown
of Broadwater LNG project costs
|
-
|
-
|
-
|
(41
|
)
|
-
|
-
|
-
|
(41
|
)
|
||||||||||
3,122
|
3,315
|
1,132
|
1,169
|
(117
|
)
|
(104
|
)
|
4,137
|
4,380
|
|||||||||||
Depreciation
and amortization
|
(1,030
|
)
|
(989
|
)
|
(347
|
)
|
(258
|
)
|
-
|
-
|
(1,377
|
)
|
(1,247
|
)
|
||||||
2,092
|
2,326
|
785
|
911
|
(117
|
)
|
(104
|
)
|
2,760
|
3,133
|
|||||||||||
Interest
expense
|
(954
|
)
|
(943
|
)
|
||||||||||||||||
Interest
expense of joint ventures
|
(64
|
)
|
(72
|
)
|
||||||||||||||||
Interest
income and other
|
121
|
54
|
||||||||||||||||||
Income
taxes
|
(387
|
)
|
(602
|
)
|
||||||||||||||||
Non-controlling
interests
|
(96
|
)
|
(130
|
)
|
||||||||||||||||
Net
Income
|
1,380
|
1,440
|
||||||||||||||||||
Preferred
share dividends
|
(6
|
)
|
-
|
|||||||||||||||||
Net
Income Applicable to Common Shares
|
1,374
|
1,440
|
TransCanada welcomes questions from shareholders and potential investors.
Please telephone:
|
Investor
Relations, at 1.800.361.6522 (Canada and U.S. Mainland) or direct dial
David Moneta/Myles Dougan/Terry Hook at 403.920.7911. The investor fax
line is 403.920.2457. Media Relations: Cecily Dobson/Terry
Cunha
403.920.7859
or 1.800.608.7859.
|
Visit
the TransCanada website at: http://www.transcanada.com.
|