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
|
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,
2008.
|
13.2
|
Consolidated
comparative interim unaudited financial statements of the registrant for
the period ended September 30, 2008 (included in the registrant's Third
Quarter 2008 Quarterly Report to Shareholders).
|
13.3
|
U.S.
GAAP reconciliation of the consolidated comparative interim unaudited
financial statements of the registrant contained in the registrant's Third
Quarter 2008 Quarterly Report to Shareholders.
|
31.1
|
Certification
of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002.
|
31.2
|
Certification
of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002.
|
32.1
|
Certification
of Chief Executive Officer regarding Periodic Report containing Financial
Statements.
|
32.2
|
Certification
of Chief Financial Officer regarding Periodic Report containing Financial
Statements.
|
99.1
|
A
copy of the registrant’s news release of October 28, 2008.
|
Reconciliation
of Comparable Earnings to Net Income
|
|||||||||||||||||||
(unaudited)
|
Three
months ended
September
30
|
Nine
months ended
September
30
|
|||||||||||||||||
(millions
of dollars except per share amounts)
|
2008
|
2007
|
2008
|
2007
|
|||||||||||||||
Pipelines
|
|||||||||||||||||||
Comparable
earnings
|
173 | 163 | 530 | 484 | |||||||||||||||
Specific
items (net of tax):
|
|||||||||||||||||||
Calpine
bankruptcy settlements
|
- | - | 152 | - | |||||||||||||||
GTN
lawsuit settlement
|
- | - | 10 | - | |||||||||||||||
Net
income
|
173 | 163 | 692 | 484 | |||||||||||||||
Energy
|
|||||||||||||||||||
Comparable
earnings
|
202 | 156 | 494 | 352 | |||||||||||||||
Specific
items (net of tax, where applicable):
|
|||||||||||||||||||
Fair
value adjustments of natural gas storage inventory
|
|||||||||||||||||||
and
forward contracts
|
(2 | ) | - | (6 | ) | - | |||||||||||||
Writedown
of Broadwater LNG project costs
|
- | - | (27 | ) | - | ||||||||||||||
Income
tax adjustments
|
- | - | - | 4 | |||||||||||||||
Net
income
|
200 | 156 | 461 | 356 | |||||||||||||||
Corporate
|
|||||||||||||||||||
Comparable
expenses
|
(9 | ) | (10 | ) | (16 | ) | (36 | ) | |||||||||||
Specific
item:
|
|||||||||||||||||||
Income
tax reassessments and adjustments
|
26 | 15 | 26 | 42 | |||||||||||||||
Net
income
|
17 | 5 | 10 | 6 | |||||||||||||||
Net Income (1)
|
390 | 324 | 1,163 | 846 | |||||||||||||||
Net Income Per Share
(2)
|
|||||||||||||||||||
Basic
and Diluted
|
$ | 0.67 | $ | 0.60 | $ | 2.07 | $ | 1.60 | |||||||||||
(1) |
Comparable
Earnings
|
366 | 309 | 1,008 | 800 | ||||||||||||||
Specific
items (net of tax, where applicable):
|
|||||||||||||||||||
Calpine
bankruptcy settlements
|
- | - | 152 | - | |||||||||||||||
GTN
lawsuit settlement
|
- | - | 10 | - | |||||||||||||||
Fair
value adjustments of natural gas storage inventory
|
|||||||||||||||||||
and
forward contracts
|
(2 | ) | - | (6 | ) | - | |||||||||||||
Writedown
of Broadwater LNG project costs
|
- | - | (27 | ) | - | ||||||||||||||
Income
tax reassessments and adjustments
|
26 | 15 | 26 | 46 | |||||||||||||||
Net
Income
|
390 | 324 | 1,163 | 846 | |||||||||||||||
(2) |
Comparable
Earnings Per Share
|
$ | 0.63 | $ | 0.57 | $ | 1.80 | $ | 1.51 | ||||||||||
Specific
items - per share
|
|||||||||||||||||||
Calpine
bankruptcy settlements
|
- | - | 0.27 | - | |||||||||||||||
GTN
lawsuit settlement
|
- | - | 0.02 | - | |||||||||||||||
Fair
value adjustments of natural gas storage inventory
|
|||||||||||||||||||
and
forward contracts
|
- | - | (0.01 | ) | - | ||||||||||||||
Writedown
of Broadwater LNG project costs
|
- | - | (0.05 | ) | - | ||||||||||||||
Income
tax reassessments and adjustments
|
0.04 | 0.03 | 0.04 | 0.09 | |||||||||||||||
Net
Income Per Share
|
$ | 0.67 | $ | 0.60 | $ | 2.07 | $ | 1.60 | |||||||||||
Pipelines
Results
|
||||||||||||||||
(unaudited)
|
Three
months ended
September
30
|
Nine
months ended
September
30
|
||||||||||||||
(millions
of dollars)
|
2008
|
2007
|
2008
|
2007
|
||||||||||||
Wholly
Owned Pipelines
|
||||||||||||||||
Canadian
Mainline
|
66 | 69 | 204 | 201 | ||||||||||||
Alberta
System
|
32 | 32 | 97 | 97 | ||||||||||||
ANR
(1)
|
24 | 19 | 94 | 69 | ||||||||||||
GTN
|
15 | 10 | 49 | 26 | ||||||||||||
Foothills
|
6 | 6 | 19 | 20 | ||||||||||||
143 | 136 | 463 | 413 | |||||||||||||
Other
Pipelines
|
||||||||||||||||
Great
Lakes (2)
|
9 | 11 | 32 | 36 | ||||||||||||
PipeLines
LP (3)
|
3 | 8 | 15 | 14 | ||||||||||||
Iroquois
|
5 | 3 | 13 | 11 | ||||||||||||
Tamazunchale
|
5 | 2 | 9 | 7 | ||||||||||||
Other
(4)
|
8 | 8 | 29 | 33 | ||||||||||||
Northern
Development
|
(2 | ) | (1 | ) | (3 | ) | (3 | ) | ||||||||
General,
administrative, support costs and other
|
2 | (4 | ) | (28 | ) | (27 | ) | |||||||||
30 | 27 | 67 | 71 | |||||||||||||
Comparable
Earnings
|
173 | 163 | 530 | 484 | ||||||||||||
Specific
items (net of tax):
|
||||||||||||||||
Calpine
bankruptcy settlements (5)
|
- | - | 152 | - | ||||||||||||
GTN
lawsuit settlement
|
- | - | 10 | - | ||||||||||||
Net
Income
|
173 | 163 | 692 | 484 | ||||||||||||
(1)
ANR's results include earnings from the date of acquisition of February
22, 2007.
|
||||||||||||||||
(2)
Great Lakes' results reflect TransCanada's 53.6 per cent ownership in
Great Lakes since February 22, 2007 and 50 per cent ownership prior to
that date.
|
||||||||||||||||
(3)
PipeLines LP's results include TransCanada's effective ownership of an
additional 14.9 per cent interest in Great Lakes since February
22,
2007 as a result of PipeLines LP's acquisition of a 46.4 per cent interest
in Great Lakes and TransCanada's 32.1 per cent interest in PipeLines
LP.
|
||||||||||||||||
(4)
Other includes results of Portland, Ventures LP, TQM, TransGas and
Gas Pacifico/INNERGY.
|
||||||||||||||||
(5)
GTN and Portland received shares of Calpine with an initial after-tax
value of $95 million and $38 million (TransCanada's share), respectively,
from the bankruptcy settlements with Calpine. These shares were
subsequently sold for an additional after-tax gain of $19
million.
|
||||||||||||||||
|
Operating
Statistics
|
|||||||||||
Canadian
|
Alberta
|
GTN
|
|||||||||
Nine
months ended September 30
|
Mainline(1)
|
System(2)
|
ANR(3)(4)
|
System(3)
|
Foothills
|
||||||
(unaudited)
|
2008
|
2007
|
2008
|
2007
|
2008
|
2007
|
2008
|
2007
|
2008
|
2007
|
|
Average
investment base
|
|||||||||||
($
millions)
|
7,065
|
7,323
|
4,322
|
4,236
|
n/a
|
n/a
|
n/a
|
n/a
|
755
|
824
|
|
Delivery
volumes (Bcf)
|
|||||||||||
Total
|
2,595
|
2,359
|
2,833
|
2,993
|
1,243
|
829
|
595
|
600
|
955
|
1,058
|
|
Average
per day
|
9.5
|
8.6
|
10.3
|
11.0
|
4.5
|
3.8
|
2.2
|
2.2
|
3.5
|
3.9
|
(1)
Canadian Mainline's physical receipts originating at the Alberta border
and in Saskatchewan for the nine months ended September 30, 2008 were
1,460 billion cubic feet (Bcf) (2007 - 1,601 Bcf); average per day was 5.3
Bcf
(2007 - 5.9 Bcf).
|
|||||||||||
(2)
Field receipt volumes for the Alberta System for the nine months ended
September 30, 2008 were 2,908 Bcf (2007 - 3,064 Bcf); average per day was
10.6 Bcf (2007 - 11.2 Bcf).
|
|||||||||||
(3)
ANR's and the GTN System's results are not impacted by current average
investment base as these systems operate under a fixed rate model approved
by the FERC.
|
|||||||||||
(4)
ANR's results include delivery volumes from the date of acquistion of
February 22, 2007.
|
Energy
Results
|
||||||||||||||||
(unaudited)
|
Three
months ended
September
30
|
Nine
months ended
September
30
|
||||||||||||||
(millions
of dollars)
|
2008
|
2007
|
2008
|
2007
|
||||||||||||
Western
Power
|
126 | 120 | 320 | 250 | ||||||||||||
Eastern
Power (1)
|
100 | 52 | 265 | 189 | ||||||||||||
Bruce
Power
|
83 | 64 | 151 | 124 | ||||||||||||
Natural
Gas Storage
|
29 | 39 | 95 | 89 | ||||||||||||
General,
administrative, support costs and other
|
(41 | ) | (38 | ) | (117 | ) | (113 | ) | ||||||||
Operating
income
|
297 | 237 | 714 | 539 | ||||||||||||
Financial
charges
|
(5 | ) | (6 | ) | (16 | ) | (16 | ) | ||||||||
Interest
income and other
|
(1 | ) | 2 | 3 | 8 | |||||||||||
Writedown
of Broadwater LNG project costs
|
- | - | (41 | ) | - | |||||||||||
Income
taxes
|
(91 | ) | (77 | ) | (199 | ) | (175 | ) | ||||||||
Net
Income
|
200 | 156 | 461 | 356 | ||||||||||||
Comparable
Earnings
|
202 | 156 | 494 | 352 | ||||||||||||
Specific
items (net of tax, where applicable):
|
||||||||||||||||
Fair
value adjustments of natural gas storage
|
||||||||||||||||
inventory
and forward contracts
|
(2 | ) | - | (6 | ) | - | ||||||||||
Writedown
of Broadwater LNG project costs
|
- | - | (27 | ) | - | |||||||||||
Income
tax adjustments
|
- | - | - | 4 | ||||||||||||
Net
Income
|
200 | 156 | 461 | 356 | ||||||||||||
(1)
Eastern Power results include earnings from Ravenswood from the date of
acquisition of August 26, 2008.
|
Western
Power Results
|
||||||||||||||||
(unaudited)
|
Three
months ended
September
30
|
Nine
months ended
September
30
|
||||||||||||||
(millions
of dollars)
|
2008
|
2007
|
2008
|
2007
|
||||||||||||
Revenues
|
||||||||||||||||
Power
|
264 | 302 | 842 | 800 | ||||||||||||
Other
(1)
|
56 | 22 | 108 | 71 | ||||||||||||
320 | 324 | 950 | 871 | |||||||||||||
Commodity
purchases resold
|
||||||||||||||||
Power
|
(129 | ) | (149 | ) | (423 | ) | (454 | ) | ||||||||
Other
(2)
|
(13 | ) | (18 | ) | (47 | ) | (53 | ) | ||||||||
(142 | ) | (167 | ) | (470 | ) | (507 | ) | |||||||||
Plant
operating costs and other
|
(47 | ) | (32 | ) | (141 | ) | (100 | ) | ||||||||
Depreciation
|
(5 | ) | (5 | ) | (19 | ) | (14 | ) | ||||||||
Operating
Income
|
126 | 120 | 320 | 250 | ||||||||||||
(1)
Other revenue includes sales of natural gas, sulphur and thermal carbon
black.
|
||||||||||||||||
(2)
Other commodity purchases resold includes the cost of natural gas
sold.
|
||||||||||||||||
Western
Power Sales Volumes
|
||||||||||||||||
(unaudited)
|
Three
months ended
September
30
|
Nine
months ended
September
30
|
||||||||||||||
(GWh)
|
2008
|
2007
|
2008
|
2007
|
||||||||||||
Supply
|
||||||||||||||||
Generation
|
598 | 560 | 1,733 | 1,683 | ||||||||||||
Purchased
|
||||||||||||||||
Sundance
A & B and Sheerness PPAs
|
2,949 | 2,860 | 9,143 | 8,990 | ||||||||||||
Other
purchases
|
180 | 362 | 627 | 1,227 | ||||||||||||
3,727 | 3,782 | 11,503 | 11,900 | |||||||||||||
Sales
|
||||||||||||||||
Contracted
|
2,686 | 2,845 | 8,579 | 9,354 | ||||||||||||
Spot
|
1,041 | 937 | 2,924 | 2,546 | ||||||||||||
3,727 | 3,782 | 11,503 | 11,900 | |||||||||||||
Eastern Power Results
(1)
|
||||||||||||||||
(unaudited)
|
Three
months ended
September
30
|
Nine
months ended
September
30
|
||||||||||||||
(millions
of dollars)
|
2008
|
2007
|
2008
|
2007
|
||||||||||||
Revenue
|
||||||||||||||||
Power
|
311 | 392 | 852 | 1,135 | ||||||||||||
Other
(2)
|
81 | 39 | 258 | 186 | ||||||||||||
392 | 431 | 1,110 | 1,321 | |||||||||||||
Commodity
purchases resold
|
||||||||||||||||
Power
|
(121 | ) | (226 | ) | (362 | ) | (586 | ) | ||||||||
Other
(3)
|
(77 | ) | (38 | ) | (239 | ) | (163 | ) | ||||||||
(198 | ) | (264 | ) | (601 | ) | (749 | ) | |||||||||
Plant
operating costs and other
|
(74 | ) | (103 | ) | (196 | ) | (347 | ) | ||||||||
Depreciation
|
(20 | ) | (12 | ) | (48 | ) | (36 | ) | ||||||||
Operating
Income
|
100 | 52 | 265 | 189 | ||||||||||||
(1)
Includes Ravenswood effective August 26, 2008 and Anse-à-Valleau effective
November 10, 2007.
|
||||||||
(2)
Other revenue includes sales of natural gas.
|
||||||||
(3)
Other commodity purchases resold includes the cost of natural gas
sold.
|
||||||||
Eastern Power Sales Volumes
(1)
|
||||||||||||||||
(unaudited)
|
Three
months ended
September
30
|
Nine
months ended
September
30
|
||||||||||||||
(GWh)
|
2008
|
2007
|
2008
|
2007
|
||||||||||||
Supply
|
||||||||||||||||
Generation
|
1,442 | 1,915 | 3,584 | 5,966 | ||||||||||||
Purchased
|
1,638 | 2,087 | 4,545 | 5,175 | ||||||||||||
3,080 | 4,002 | 8,129 | 11,141 | |||||||||||||
Sales
|
||||||||||||||||
Contracted
|
3,048 | 3,913 | 7,931 | 10,707 | ||||||||||||
Spot
|
32 | 89 | 198 | 434 | ||||||||||||
3,080 | 4,002 | 8,129 | 11,141 | |||||||||||||
(1)
Includes Ravenswood effective August 26, 2008, Anse-à-Valleau effective
November 10, 2007 and Bécancour for the nine months ended September 30,
2007.
|
Bruce
Power Results
|
Three
months ended
September
30
|
Nine
months ended
September
30
|
||||||||||||||
(unaudited)
|
2008
|
2007
|
2008
|
2007
|
||||||||||||
Bruce
Power (100 per cent basis)
|
||||||||||||||||
(millions
of dollars)
|
||||||||||||||||
Revenues
|
||||||||||||||||
Power
|
580 | 517 | 1,540 | 1,427 | ||||||||||||
Other
(1)
|
39 | 35 | 76 | 85 | ||||||||||||
619 | 552 | 1,616 | 1,512 | |||||||||||||
Operating
expenses
|
||||||||||||||||
Operations
and maintenance(2)
|
(245 | ) | (239 | ) | (827 | ) | (793 | ) | ||||||||
Fuel
|
(37 | ) | (23 | ) | (100 | ) | (76 | ) | ||||||||
Supplemental
rent(2)
|
(43 | ) | (43 | ) | (130 | ) | (128 | ) | ||||||||
Depreciation
and amortization
|
(37 | ) | (43 | ) | (110 | ) | (115 | ) | ||||||||
(362 | ) | (348 | ) | (1,167 | ) | (1,112 | ) | |||||||||
Operating
Income
|
257 | 204 | 449 | 400 | ||||||||||||
TransCanada's
proportionate share - Bruce A
|
18 | 12 | 68 | 29 | ||||||||||||
TransCanada's
proportionate share - Bruce B
|
69 | 57 | 97 | 108 | ||||||||||||
TransCanada's
proportionate share
|
87 | 69 | 165 | 137 | ||||||||||||
Adjustments
|
(4 | ) | (5 | ) | (14 | ) | (13 | ) | ||||||||
TransCanada's
combined operating income
|
||||||||||||||||
from
Bruce Power
|
83 | 64 | 151 | 124 | ||||||||||||
Bruce
Power - Other Information
|
||||||||||||||||
Plant
availability
|
||||||||||||||||
Bruce
A
|
85 | % | 79 | % | 88 | % | 81 | % | ||||||||
Bruce
B
|
94 | % | 96 | % | 82 | % | 88 | % | ||||||||
Combined
Bruce Power
|
92 | % | 90 | % | 85 | % | 86 | % | ||||||||
Planned
outage days
|
||||||||||||||||
Bruce
A
|
14 | 2 | 47 | 52 | ||||||||||||
Bruce
B
|
- | - | 100 | 80 | ||||||||||||
Unplanned
outage days
|
||||||||||||||||
Bruce
A
|
5 | 27 | 7 | 34 | ||||||||||||
Bruce
B
|
11 | 8 | 59 | 29 | ||||||||||||
Sales
volumes (GWh)
|
||||||||||||||||
Bruce
A - 100 per cent
|
2,790 | 2,610 | 8,580 | 7,930 | ||||||||||||
TransCanada's
proportionate share
|
1,356 | 1,272 | 4,182 | 3,863 | ||||||||||||
Bruce
B - 100 per cent
|
6,810 | 6,820 | 17,660 | 18,620 | ||||||||||||
TransCanada's
proportionate share
|
2,153 | 2,155 | 5,581 | 5,884 | ||||||||||||
Combined
Bruce Power - 100 per cent
|
9,600 | 9,430 | 26,240 | 26,550 | ||||||||||||
TransCanada's
proportionate share
|
3,509 | 3,427 | 9,763 | 9,747 | ||||||||||||
Results
per MWh
|
||||||||||||||||
Bruce
A power revenues
|
$ | 63 | $ | 60 | $ | 62 | $ | 59 | ||||||||
Bruce
B power revenues
|
$ | 59 | $ | 53 | $ | 57 | $ | 52 | ||||||||
Combined
Bruce Power revenues
|
$ | 60 | $ | 55 | $ | 59 | $ | 54 | ||||||||
Combined
Bruce Power fuel
|
$ | 4 | $ | 3 | $ | 4 | $ | 3 | ||||||||
Combined
Bruce Power operating expenses
(3)
|
$ | 36 | $ | 36 | $ | 43 | $ | 41 | ||||||||
Percentage
of output sold to spot market
|
23 | % | 52 | % | 25 | % | 45 | % | ||||||||
(1)
Other revenue includes Bruce A fuel cost recoveries of $17 million and $45
million for the three and nine months ended September 30, 2008,
respectively ($9 million and $25 million for the three and nine months
ended September 30, 2007, respectively). Other revenue also includes a
gain of $15 million and a loss of $3 million as a result of changes in
fair value of held-for-trading derivatives for the three and nine months
ended September 30, 2008, respectively (gains of $18 million and $36
million for the three and nine months ended September 30, 2007,
respectively).
|
|||||||
(2)
Includes adjustments to eliminate the effects of inter-partnership
transactions between Bruce A and Bruce B.
|
|||||||
(3) Net of fuel recoveries. |
Weighted Average Power Plant
Availability (1)
|
||||||||
Three
months ended September 30
|
Nine
months ended September 30
|
|||||||
(unaudited)
|
2008
|
2007
|
2008
|
2007
|
||||
Western
Power (2)
|
92%
|
91%
|
87%
|
93%
|
||||
Eastern
Power (3)
|
98%
|
99%
|
96%
|
97%
|
||||
Bruce
Power
|
92%
|
90%
|
85%
|
86%
|
||||
All
plants, excluding Bruce Power
|
97%
|
97%
|
94%
|
95%
|
||||
All
plants
|
94%
|
94%
|
90%
|
92%
|
||||
(1)
Plant availability represents the percentage of time in the period that
the plant is available to generate power, whether actually running or not,
reduced by planned and unplanned outages.
|
||||||||
(2)
Western Power plant availability decreased in the nine months ended
September 30, 2008 due to an outage at the Cancarb power
facility.
|
||||||||
(3)
Eastern Power includes Ravenswood effective August 26, 2008,
Anse-à-Valleau effective November 10, 2007 and Bécancour for the nine
months ended September 30, 2007.
|
||||||||
|
||||||||
Funds
Generated from Operations
|
|||||||||||
(unaudited)
|
Three
months ended September 30
|
Nine
months ended September 30
|
|||||||||
(millions
of dollars)
|
2008
|
2007
|
2008
|
2007
|
|||||||
Cash
Flows
|
|||||||||||
Funds
generated from operations (1)
|
711
|
702
|
2,309
|
1,880
|
|||||||
Decrease
in operating working capital
|
114
|
132
|
16
|
261
|
|||||||
Net
cash provided by operations
|
825
|
834
|
2,325
|
2,141
|
|||||||
(1) For
further discussion on funds generated from operations, refer to the
Non-GAAP Measures section in this MD&A.
|
|||||||||||
Derivatives
Hedging Net Investment in Foreign Operations
|
||||||
Asset/(Liability)
|
||||||
(unaudited)
|
||||||
(millions
of dollars)
|
September
30, 2008
|
December
31, 2007
|
||||
Notional
or
|
Notional
or
|
|||||
Fair
|
Principal
|
Fair
|
Principal
|
|||
Value(1)
|
Amount
|
Value(1)
|
Amount
|
|||
Derivative
financial instruments in hedging relationships
|
||||||
U.S.
dollar cross-currency swaps
|
||||||
(maturing
2009 to 2014)(2)
|
39
|
U.S.
1,550
|
77
|
U.S.
350
|
||
U.S.
dollar forward foreign exchange contracts
|
||||||
(maturing
2008 to 2009)(2)
|
(46)
|
U.S.
2,780
|
(4)
|
U.S.
150
|
||
U.S.
dollar options
|
||||||
(maturing
2008)(2)
|
(2)
|
U.S.
500
|
3
|
U.S.
600
|
||
(9)
|
U.S.
4,830
|
76
|
U.S.
1,100
|
|||
(1)
Fair values are equal to carrying values.
|
||||||
(2)
As at September 30, 2008.
|
September
30, 2008
|
||||||||||||
(all
amounts in millions unless otherwise indicated)
|
Power
|
Natural
Gas
|
Interest
|
|||||||||
Derivative
Financial Instruments Held for Trading
|
||||||||||||
Fair
Values(1)
|
||||||||||||
Assets
|
$ | 62 | $ | 95 | $ | 30 | ||||||
Liabilities
|
$ | (48 | ) | $ | (75 | ) | $ | (25 | ) | |||
Notional
Values
|
||||||||||||
Volumes(2)
|
||||||||||||
Purchases
|
3,170 | 57 | - | |||||||||
Sales
|
3,775 | 62 | - | |||||||||
Canadian
dollars
|
- | - | 1,021 | |||||||||
U.S.
dollars
|
- | - | U.S. 1,400 | |||||||||
Net
unrealized gains/(losses) in the period(3)
|
||||||||||||
Three
months ended September 30, 2008
|
$ | 5 | $ | - | $ | 5 | ||||||
Nine
months ended September 30, 2008
|
$ | - | $ | (12 | ) | $ | 3 | |||||
Net
realized gains/(losses) in the period(3)
|
||||||||||||
Three
months ended September 30, 2008
|
$ | 12 | $ | (12 | ) | $ | 2 | |||||
Nine
months ended September 30, 2008
|
$ | 21 | $ | (6 | ) | $ | 12 | |||||
Maturity
dates
|
2008-2014 | 2008-2011 | 2008-2018 |
Derivative Financial
Instruments in Hedging Relationships(4)(5)
|
||||||||||||
Fair
Values(1)
|
||||||||||||
Assets
|
$ | 156 | $ | 3 | $ | 5 | ||||||
Liabilities
|
$ | (88 | ) | $ | (14 | ) | $ | (20 | ) | |||
Notional
Values
|
||||||||||||
Volumes(2)
|
||||||||||||
Purchases
|
7,024 | 14 | - | |||||||||
Sales
|
15,549 | - | - | |||||||||
Canadian
dollars
|
- | - | 50 | |||||||||
U.S.
dollars
|
- | - | U.S. 1,125 | |||||||||
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
|
2008-2014 | 2008-2011 | 2009-2019 | |||||||||
(1)
Fair value is equal to the carrying value of these
derivatives.
|
|||||||||||||||
(2) Volumes
for power and natural gas derivatives are in gigawatt hours (Gwh) and
billion cubic feet (Bcf), respectively.
|
|||||||||||||||
(3)
All realized and unrealized gains and losses are included in Net Income.
Realized gains and losses are included in Net Income after the financial
instrument has been settled.
|
|||||||||||||||
(4)
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 $3 million.
|
|||||||||||||||
(5)
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.
|
2007
|
||||||||||||
(all
amounts in millions unless otherwise indicated)
|
Power
|
Natural
Gas
|
Interest
|
|||||||||
Derivative
Financial Instruments Held for Trading
|
||||||||||||
Fair
Values(1)(4)
|
||||||||||||
Assets
|
$ | 55 | $ | 43 | $ | 23 | ||||||
Liabilities
|
$ | (44 | ) | $ | (19 | ) | $ | (18 | ) | |||
Notional
Values(4)
|
||||||||||||
Volumes(2)
|
||||||||||||
Purchases
|
3,774 | 47 | - | |||||||||
Sales
|
4,469 | 64 | - | |||||||||
Canadian
dollars
|
- | - | 615 | |||||||||
U.S.
dollars
|
- | - |
U.S.
550
|
|||||||||
Net
unrealized gains/(losses) in the period(3)
|
||||||||||||
Three
months ended September 30, 2007
|
$ | 2 | $ | 23 | $ | - | ||||||
Nine
months ended September 30, 2007
|
$ | 11 | $ | 6 | $ | 1 | ||||||
Net
realized gains/(losses) in the period(3)
|
||||||||||||
Three
months ended September 30, 2007
|
$ | 2 | $ | 18 | $ | 3 | ||||||
Nine
months ended September 30, 2007
|
$ | (7 | ) | $ | 36 | $ | 4 | |||||
Maturity dates (4) | 2008-2016 | 2008-2010 | 2008-2016 |
Derivative Financial
Instruments in Hedging Relationships(5)(6)
|
||||||||||||
Fair
Values(1)(4)
|
||||||||||||
Assets
|
$ | 135 | $ | 19 | $ | 2 | ||||||
Liabilities
|
$ | (104 | ) | $ | (7 | ) | $ | (16 | ) | |||
Notional
Values(4)
|
||||||||||||
Volumes(2)
|
||||||||||||
Purchases
|
7,362 | 28 | - | |||||||||
Sales
|
16,367 | 4 | - | |||||||||
Canadian
dollars
|
- | - | 150 | |||||||||
U.S.
dollars
|
- | - |
U.S. 875
|
|||||||||
Net
realized (losses)/gains in the period(3)
|
||||||||||||
Three
months ended September 30, 2007
|
$ | (51 | ) | $ | 10 | $ | 2 | |||||
Nine
months ended September 30, 2007
|
$ | (37 | ) | $ | 7 | $ | 3 | |||||
Maturity dates (4) | 2008-2013 | 2008-2010 | 2008-2013 |
(1)
Fair value is equal to the carrying value of these
derivatives.
|
|||||||||||||||
(2) Volumes
for power and natural gas derivatives are in Gwh and Bcf,
respectively.
|
|||||||||||||||
(3)
All realized and unrealized gains and losses are included in Net Income.
Realized gains and losses are included in Net Income after the financial
instrument has been settled.
|
|||||||||||||||
(4) As
at December 31, 2007.
|
|||||||||||||||
(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 $2 million at December 31,
2007.
|
|||||||||||||||
(6)
Net Income for the three and nine months ended September 30, 2007 included
losses of $4 million and $7 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.
Net Income for the three and nine months ended September 30, 2007 included
nil and a $4 million loss, respectively, for the changes in
fair value of an interest-
rate cash flow hedge that was reclassified as a result of discontinuance
of cash flow hedge accounting when the anticipated transaction was
identified as not probable of occurring by the end of the originally
specified time period.
|
(unaudited)
|
2008
|
2007
|
2006
|
|||||||||||
(millions
of dollars except per share amounts)
|
Third
|
Second
|
First
|
Fourth
|
Third
|
Second
|
First
|
Fourth
|
||||||
Revenues
|
2,137
|
2,017
|
2,133
|
2,189
|
2,187
|
2,208
|
2,244
|
2,091
|
||||||
Net
Income
|
390
|
324
|
449
|
377
|
324
|
257
|
265
|
269
|
||||||
Share
Statistics
|
||||||||||||||
Net
income per share - Basic
|
$ 0.67
|
$ 0.58
|
$ 0.83
|
$ 0.70
|
$ 0.60
|
$ 0.48
|
$ 0.52
|
$ 0.55
|
||||||
Net
income per share - Diluted
|
$ 0.67
|
$ 0.58
|
$ 0.83
|
$ 0.70
|
$ 0.60
|
$ 0.48
|
$ 0.52
|
$ 0.54
|
||||||
Dividend
declared per common share
|
$ 0.36
|
$ 0.36
|
$ 0.36
|
$ 0.34
|
$ 0.34
|
$ 0.34
|
$ 0.34
|
$ 0.32
|
||||||
(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.
|
·
|
Fourth-quarter
2006 net income included approximately $12 million related to income tax
refunds and related interest.
|
·
|
First-quarter
2007 net income included $15 million related to favourable income tax
adjustments. In addition, Pipelines’ net income included contributions
from the February 22, 2007 acquisitions of ANR and additional ownership
interests in Great Lakes. Energy’s net income included earnings from the
Edson natural gas facility, which was placed in service on December 31,
2006.
|
·
|
Second-quarter
2007 net income included $16 million ($12 million in Corporate and $4
million in Energy) related to favourable income tax adjustments resulting
from reductions in Canadian federal income tax rates. Pipelines’ net
income increased as a result of a settlement reached on the Canadian
Mainline, which was approved by the NEB in May
2007.
|
·
|
Third-quarter
2007 net income included $15 million of favourable income tax
reassessments and associated interest income relating to prior
years.
|
·
|
Fourth-quarter
2007 net income included $56 million ($30 million in Energy and $26
million in Corporate) of favourable income tax adjustments resulting from
reductions in Canadian federal income tax rates and other legislative
changes. Energy’s net income increased due to a $14 million after-tax ($16
million pre-tax) gain on sale of land previously held for development.
Pipelines’ net income increased as a result of recording incremental
earnings related to the rate case settlement reached for the GTN System,
effective January 1, 2007.
|
·
|
First-quarter
2008, Pipelines’ net income included $152 million after tax ($240 million
pre-tax) from the Calpine bankruptcy settlements received by GTN and
Portland, and proceeds from a lawsuit settlement of $10 million after tax
($17 million pre-tax). Energy’s net income included a writedown of costs
related to the Broadwater LNG project of $27 million after tax ($41
million pre-tax) and net unrealized losses of $12 million after tax ($17
million pre-tax) due to changes in fair value of proprietary natural gas
storage inventory and natural gas forward purchase and sale contracts.
Beginning in first-quarter 2008, the temporary suspension of generation at
the Bécancour facility reduced Eastern Power’s revenues, however, net
income was not materially impacted due to capacity payments received
pursuant to an agreement with
Hydro-Québec.
|
·
|
Second-quarter
2008, Energy’s net income included net unrealized gains of $8 million
after tax ($12 million pre-tax) due to changes in fair value of
proprietary natural gas storage inventory and natural gas forward purchase
and sale contracts. In addition, Western Power’s revenues and operating
income increased due to higher overall realized prices and market heat
rates in Alberta.
|
·
|
Third-quarter
2008, Energy’s net income included contribution from the August 26, 2008
acquisition of Ravenswood. Corporate net income included favourable income
tax adjustments of $26 million from an internal restructuring and
realization of losses.
|
(unaudited)
|
Three
months ended
September
30
|
Nine
months ended
September
30
|
||||||||||||||
(millions
of dollars except per share amounts)
|
2008
|
2007
|
2008
|
2007
|
||||||||||||
Revenues
|
2,137 | 2,187 | 6,287 | 6,639 | ||||||||||||
Operating
Expenses
|
||||||||||||||||
Plant
operating costs and other
|
750 | 739 | 2,181 | 2,232 | ||||||||||||
Commodity
purchases resold
|
339 | 453 | 1,096 | 1,547 | ||||||||||||
Depreciation
|
303 | 298 | 900 | 888 | ||||||||||||
1,392 | 1,490 | 4,177 | 4,667 | |||||||||||||
745 | 697 | 2,110 | 1,972 | |||||||||||||
Other
Expenses/(Income)
|
||||||||||||||||
Financial
charges
|
213 | 247 | 617 | 748 | ||||||||||||
Financial
charges of joint ventures
|
18 | 17 | 51 | 57 | ||||||||||||
Interest
income and other
|
(23 | ) | (45 | ) | (96 | ) | (124 | ) | ||||||||
Calpine
bankruptcy settlements
|
- | - | (279 | ) | - | |||||||||||
Writedown
of Broadwater LNG project costs
|
- | - | 41 | - | ||||||||||||
208 | 219 | 334 | 681 | |||||||||||||
Income
before Income Taxes and
Non-Controlling
Interests
|
537 | 478 | 1,776 | 1,291 | ||||||||||||
Income
Taxes
|
||||||||||||||||
Current
|
127 | 83 | 479 | 347 | ||||||||||||
Future
|
2 | 51 | 28 | 30 | ||||||||||||
129 | 134 | 507 | 377 | |||||||||||||
Non-Controlling
Interests
|
||||||||||||||||
Preferred
share dividends of subsidiary
|
6 | 6 | 17 | 17 | ||||||||||||
Non-controlling
interest in PipeLines LP
|
12 | 13 | 46 | 44 | ||||||||||||
Other
|
- | 1 | 43 | 7 | ||||||||||||
18 | 20 | 106 | 68 | |||||||||||||
Net
Income
|
390 | 324 | 1,163 | 846 | ||||||||||||
Net
Income Per Share
|
||||||||||||||||
Basic
and Diluted
|
$ | 0.67 | $ | 0.60 | $ | 2.07 | $ | 1.60 | ||||||||
Average Shares Outstanding -
Basic (millions)
|
579 | 537 | 560 | 527 | ||||||||||||
Average Shares Outstanding - Diluted (millions)
|
581 | 540 | 562 | 530 | ||||||||||||
See accompanying notes to the consolidated financial statements. |
(unaudited)
|
Three
months ended
September
30
|
Nine
months ended
September
30
|
||||||||||||||
(millions
of dollars)
|
2008
|
2007
|
2008
|
2007
|
||||||||||||
Cash
Generated From Operations
|
||||||||||||||||
Net
income
|
390 | 324 | 1,163 | 846 | ||||||||||||
Depreciation
|
303 | 298 | 900 | 888 | ||||||||||||
Future
income taxes
|
2 | 51 | 28 | 30 | ||||||||||||
Non-controlling
interests
|
18 | 20 | 106 | 68 | ||||||||||||
Employee
future benefits funding lower than expense
|
10 | 3 | 23 | 18 | ||||||||||||
Writedown
of Broadwater LNG project costs
|
- | - | 41 | - | ||||||||||||
Other
|
(12 | ) | 6 | 48 | 30 | |||||||||||
711 | 702 | 2,309 | 1,880 | |||||||||||||
Decrease
in operating working capital
|
114 | 132 | 16 | 261 | ||||||||||||
Net
cash provided by operations
|
825 | 834 | 2,325 | 2,141 | ||||||||||||
Investing
Activities
|
||||||||||||||||
Capital
expenditures
|
(806 | ) | (364 | ) | (1,899 | ) | (1,056 | ) | ||||||||
Acquisitions,
net of cash acquired
|
(3,054 | ) | 2 | (3,058 | ) | (4,222 | ) | |||||||||
Disposition
of assets, net of current income taxes
|
21 | - | 21 | - | ||||||||||||
Deferred
amounts and other
|
42 | (126 | ) | 141 | (274 | ) | ||||||||||
Net
cash used in investing activities
|
(3,797 | ) | (488 | ) | (4,795 | ) | (5,552 | ) | ||||||||
Financing
Activities
|
||||||||||||||||
Dividends
on common shares
|
(143 | ) | (130 | ) | (410 | ) | (417 | ) | ||||||||
Distributions
paid to non-controlling interests
|
(24 | ) | (23 | ) | (110 | ) | (68 | ) | ||||||||
Notes
payable (repaid)/issued, net
|
(258 | ) | 293 | 466 | 554 | |||||||||||
Long-term
debt issued
|
2,101 | 5 | 2,213 | 1,456 | ||||||||||||
Reduction
of long-term debt
|
(15 | ) | (64 | ) | (788 | ) | (859 | ) | ||||||||
Long-term
debt of joint ventures issued
|
123 | 12 | 157 | 122 | ||||||||||||
Reduction
of long-term debt of joint ventures
|
(44 | ) | (20 | ) | (101 | ) | (139 | ) | ||||||||
Common
shares issued, net of issue costs
|
6 | - | 1,252 | 1,697 | ||||||||||||
Junior
subordinated notes issued
|
- | - | - | 1,107 | ||||||||||||
Preferred
securities redeemed
|
- | (488 | ) | - | (488 | ) | ||||||||||
Partnership
units of subsidiary issued
|
- | - | - | 348 | ||||||||||||
Net
cash provided by/(used in) financing activities
|
1,746 | (415 | ) | 2,679 | 3,313 | |||||||||||
Effect
of Foreign Exchange Rate Changes on Cash
|
||||||||||||||||
and
Cash Equivalents
|
19 | (16 | ) | 39 | (46 | ) | ||||||||||
(Decrease)/Increase
in Cash and Cash Equivalents
|
(1,207 | ) | (85 | ) | 248 | (144 | ) | |||||||||
Cash
and Cash Equivalents
|
||||||||||||||||
Beginning
of period
|
1,959 | 340 | 504 | 399 | ||||||||||||
Cash
and Cash Equivalents
|
||||||||||||||||
End
of period
|
752 | 255 | 752 | 255 | ||||||||||||
Supplementary
Cash Flow Information
|
||||||||||||||||
Income
taxes paid
|
106 | 93 | 418 | 305 | ||||||||||||
Interest
paid
|
177 | 290 | 658 | 832 | ||||||||||||
See
accompanying notes to the consolidated financial
statements.
|
(unaudited)
|
September
30,
|
December
31,
|
||||||
(millions
of dollars)
|
2008
|
2007
|
||||||
ASSETS
|
||||||||
Current
Assets
|
||||||||
Cash
and cash equivalents
|
752 | 504 | ||||||
Accounts
receivable
|
1,156 | 1,116 | ||||||
Inventories
|
514 | 497 | ||||||
Other
|
307 | 188 | ||||||
2,729 | 2,305 | |||||||
Plant,
Property and Equipment
|
26,397 | 23,452 | ||||||
Goodwill
|
3,886 | 2,633 | ||||||
Other
Assets
|
2,259 | 1,940 | ||||||
35,271 | 30,330 | |||||||
LIABILITIES
AND SHAREHOLDERS' EQUITY
|
||||||||
Current
Liabilities
|
||||||||
Notes
payable
|
874 | 421 | ||||||
Accounts
payable and accrued liabilities
|
1,740 | 1,767 | ||||||
Accrued
interest
|
318 | 261 | ||||||
Current
portion of long-term debt
|
545 | 556 | ||||||
Current
portion of long-term debt of joint ventures
|
80 | 30 | ||||||
3,557 | 3,035 | |||||||
Deferred
Amounts
|
1,353 | 1,107 | ||||||
Future
Income Taxes
|
1,183 | 1,179 | ||||||
Long-Term
Debt
|
14,287 | 12,377 | ||||||
Long-Term
Debt of Joint Ventures
|
922 | 873 | ||||||
Junior
Subordinated Notes
|
1,048 | 975 | ||||||
22,350 | 19,546 | |||||||
Non-Controlling
Interests
|
||||||||
Non-controlling
interest in PipeLines LP
|
630 | 539 | ||||||
Preferred
shares of subsidiary
|
389 | 389 | ||||||
Other
|
76 | 71 | ||||||
1,095 | 999 | |||||||
Shareholders'
Equity
|
11,826 | 9,785 | ||||||
35,271 | 30,330 | |||||||
See
accompanying notes to the consolidated financial
statements.
|
||||||||
(unaudited)
|
Three
months ended September
30
|
Nine
months ended September 30
|
|||||
(millions
of dollars)
|
2008
|
2007
|
2008
|
2007
|
|||
Net
Income
|
390
|
324
|
1,163
|
846
|
|||
Other
Comprehensive Income/(Loss), Net of Income Taxes
|
|||||||
Change
in foreign currency translation gains and losses on
|
|||||||
investments
in foreign operations
(1)
|
107
|
(121)
|
146
|
(342)
|
|||
Change
in gains and losses on hedges of investments
|
|||||||
in
foreign operations
(2)
|
(79)
|
22
|
(103)
|
77
|
|||
Change
in gains and losses on derivative instruments
|
|||||||
designated
as cash flow hedges (3)
|
7
|
41
|
40
|
4
|
|||
Reclassification
to net income of gains and losses on derivative
|
|||||||
instruments
designated as cash flow hedges pertaining to
|
|||||||
prior
periods (4)
|
(6)
|
16
|
(24)
|
36
|
|||
Other
Comprehensive Income/(Loss)
|
29
|
(42)
|
59
|
(225)
|
|||
Comprehensive
Income
|
419
|
282
|
1,222
|
621
|
|||
(1)
Net of income tax recovery of $23 million and $43
million for the three and nine months ended September 30, 2008,
respectively (2007 - $39 and $95 million expense,
respectively).
|
|||||||
(2)
Net of income tax recovery of $36 million and $50 million
for the three months and nine months ended September 30, 2008,
respectively (2007 - $12 and $40 million expense,
respectively).
|
|||||||
(3)
Net of income tax recovery of $25 million and expense of $24 million
for the three months and nine months ended September 30, 2008,
respectively (2007 - $13 million and $3 million expense,
respectively).
|
|||||||
(4)
Net of income tax recovery of $9 million and $20 million
for the three months and nine months ended September 30, 2008,
respectively (2007 - $14 million and $19 million expense,
respectively).
|
|||||||
See
accompanying notes to the consolidated financial
statements.
|
(unaudited) (millions
of dollars)
|
Currency
Translation Adjustment
|
Cash
Flow Hedges
|
Total
|
|||||||||
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)(5)
|
- | (24 | ) | (24 | ) | |||||||
Balance
at September 30, 2008
|
(318 | ) | 4 | (314 | ) | |||||||
Balance
at December 31, 2006
|
(90 | ) | - | (90 | ) | |||||||
Transition
adjustment resulting from adopting new financial instruments standards
(6)
|
- | (96 | ) | (96 | ) | |||||||
Change
in foreign currency translation gains and losses on investments
in
|
||||||||||||
foreign
operations (1)
|
(342 | ) | - | (342 | ) | |||||||
Change
in gains and losses on hedges of investments in foreign operations
(2)
|
77 | - | 77 | |||||||||
Change
in gains and losses on derivative instruments designated as cash
flow
|
||||||||||||
hedges
(3)
|
- | 4 | 4 | |||||||||
Reclassification
to net income of gains and losses on derivative
instruments
|
||||||||||||
designated
as cash flow hedges pertaining to prior periods (4)
|
- | 36 | 36 | |||||||||
Balance
at September 30, 2007
|
(355 | ) | (56 | ) | (411 | ) | ||||||
(1)
Net of income tax recovery of $43 million for the nine months ended
September 30, 2008 (2007 - $95 million expense).
|
||||||
(2)
Net of income tax recovery of $50 million for the nine months ended
September 30, 2008 (2007 - $40 million expense).
|
||||||
(3)
Net of income tax expense of $24 million for the nine months ended
September 30, 2008 (2007 - $3 million expense).
|
||||||
(4)
Net of income tax recovery of $20 million for the nine months ended
September 30, 2008 (2007 - $19 million expense).
|
||||||
(5)
The amount of gains and losses related to cash flow hedges reported in
accumulated other comprehensive income that will be reclassified to net
income in the next 12 months is estimated to be net losses of $32 million
($22 million net losses, net of tax). These estimates assume constant gas
and power prices, interest rates and foreign exchange rates over time,
however, the actual amounts that will be reclassified will vary based on
changes in these factors.
|
||||||
(6)
Net of income tax recovery of $44 million.
|
||||||
See
accompanying notes to the consolidated financial
statements.
|
||||||
(unaudited)
|
Nine
months ended September 30
|
|||||||
(millions
of dollars)
|
2008
|
2007
|
||||||
Common
Shares
|
||||||||
Balance
at beginning of period
|
6,662 | 4,794 | ||||||
Shares
issued under dividend reinvestment plan
|
177 | 104 | ||||||
Proceeds
from shares issued on exercise of stock options
|
17 | 14 | ||||||
Proceeds
from shares issued under public offering, net of issue
costs
|
1,235 | 1,683 | ||||||
Balance
at end of period
|
8,091 | 6,595 | ||||||
Contributed
Surplus
|
||||||||
Balance
at beginning of period
|
276 | 273 | ||||||
Issuance
of stock options
|
2 | 3 | ||||||
Balance
at end of period
|
278 | 276 | ||||||
Retained
Earnings
|
||||||||
Balance
at beginning of period
|
3,220 | 2,724 | ||||||
Transition
adjustment resulting from adopting new financial
|
||||||||
instruments
accounting standards
|
- | 4 | ||||||
Net
income
|
1,163 | 846 | ||||||
Common
share dividends
|
(612 | ) | (548 | ) | ||||
Balance
at end of period
|
3,771 | 3,026 | ||||||
Accumulated
Other Comprehensive Income
|
||||||||
Balance
at beginning of period
|
(373 | ) | (90 | ) | ||||
Transition
adjustment resulting from adopting new financial instruments
standards
|
- | (96 | ) | |||||
Other
comprehensive income
|
59 | (225 | ) | |||||
Balance
at end of period
|
(314 | ) | (411 | ) | ||||
Total
Shareholders' Equity
|
11,826 | 9,486 | ||||||
See
accompanying notes to the consolidated financial
statements.
|
1.
|
Significant
Accounting Policies
|
2.
|
Changes
in Accounting Policies
|
3.
|
Segmented
Information
|
Three
months ended September 30
|
Pipelines
|
Energy
|
Corporate
|
Total
|
||||||||||||||||||||||||||||
(unaudited
- millions of dollars)
|
2008
|
2007
|
2008
|
2007
|
2008
|
2007
|
2008
|
2007
|
||||||||||||||||||||||||
Revenues
|
1,141 | 1,148 | 996 | 1,039 | - | - | 2,137 | 2,187 | ||||||||||||||||||||||||
Plant
operating costs and other
|
(441 | ) | (422 | ) | (310 | ) | (315 | ) | 1 | (2 | ) | (750 | ) | (739 | ) | |||||||||||||||||
Commodity
purchases resold
|
- | (6 | ) | (339 | ) | (447 | ) | - | - | (339 | ) | (453 | ) | |||||||||||||||||||
Depreciation
|
(254 | ) | (258 | ) | (49 | ) | (40 | ) | - | - | (303 | ) | (298 | ) | ||||||||||||||||||
446 | 462 | 298 | 237 | 1 | (2 | ) | 745 | 697 | ||||||||||||||||||||||||
Financial
charges and non-controlling interests
|
(178 | ) | (205 | ) | - | - | (53 | ) | (62 | ) | (231 | ) | (267 | ) | ||||||||||||||||||
Financial
charges of joint ventures
|
(12 | ) | (11 | ) | (6 | ) | (6 | ) | - | - | (18 | ) | (17 | ) | ||||||||||||||||||
Interest
income and other
|
13 | 16 | (1 | ) | 2 | 11 | 27 | 23 | 45 | |||||||||||||||||||||||
Income
taxes
|
(96 | ) | (99 | ) | (91 | ) | (77 | ) | 58 | 42 | (129 | ) | (134 | ) | ||||||||||||||||||
Net
Income
|
173 | 163 | 200 | 156 | 17 | 5 | 390 | 324 | ||||||||||||||||||||||||
Nine
months ended September 30
|
Pipelines
|
Energy
|
Corporate
|
Total
|
||||||||||||||||||||||||||||
(unaudited
- millions of dollars)
|
2008
|
2007
|
2008
|
2007
|
2008
|
2007
|
2008
|
2007
|
||||||||||||||||||||||||
Revenues
|
3,417 | 3,500 | 2,870 | 3,139 | - | - | 6,287 | 6,639 | ||||||||||||||||||||||||
Plant
operating costs and other
|
(1,255 | ) | (1,222 | ) | (924 | ) | (1,005 | ) | (2 | ) | (5 | ) | (2,181 | ) | (2,232 | ) | ||||||||||||||||
Commodity
purchases resold
|
- | (71 | ) | (1,096 | ) | (1,476 | ) | - | - | (1,096 | ) | (1,547 | ) | |||||||||||||||||||
Depreciation
|
(765 | ) | (769 | ) | (135 | ) | (119 | ) | - | - | (900 | ) | (888 | ) | ||||||||||||||||||
1,397 | 1,438 | 715 | 539 | (2 | ) | (5 | ) | 2,110 | 1,972 | |||||||||||||||||||||||
Financial
charges and non-controlling interests
|
(582 | ) | (628 | ) | - | 1 | (141 | ) | (189 | ) | (723 | ) | (816 | ) | ||||||||||||||||||
Financial
charges of joint ventures
|
(34 | ) | (40 | ) | (17 | ) | (17 | ) | - | - | (51 | ) | (57 | ) | ||||||||||||||||||
Interest
income and other
|
60 | 45 | 3 | 8 | 33 | 71 | 96 | 124 | ||||||||||||||||||||||||
Calpine
bankruptcy settlements
|
279 | - | - | - | - | - | 279 | - | ||||||||||||||||||||||||
Writedown
of Broadwater LNG project costs
|
- | - | (41 | ) | - | - | - | (41 | ) | - | ||||||||||||||||||||||
Income
taxes
|
(428 | ) | (331 | ) | (199 | ) | (175 | ) | 120 | 129 | (507 | ) | (377 | ) | ||||||||||||||||||
Net
Income
|
692 | 484 | 461 | 356 | 10 | 6 | 1,163 | 846 | ||||||||||||||||||||||||
Total
Assets
|
|||||||
(unaudited
- millions of dollars)
|
September
30, 2008
|
December
31, 2007
|
|||||
Pipelines
|
22,846
|
22,024
|
|||||
Energy
|
10,816
|
7,037
|
|||||
Corporate
|
1,609
|
1,269
|
|||||
35,271
|
30,330
|
4.
|
Acquisitions
|
Purchase
Price Allocation
|
||||
(unaudited)
|
||||
(millions
of US dollars)
|
||||
Current
assets
|
169 | |||
Plant,
property and equipment
|
1,421 | |||
Other
non-current assets
|
495 | |||
Goodwill
|
905 | |||
Current
liabilities
|
(19 | ) | ||
Other
non-current liabilities
|
(58 | ) | ||
2,913 |
5.
|
Long-Term
Debt
|
6.
|
Share
Capital
|
7.
|
Financial
Instruments and Risk Management
|
Derivatives
Hedging Net Investment in Foreign Operations
|
||||||||||
Asset/(Liability)
|
||||||||||
(unaudited)
|
||||||||||
(millions
of dollars)
|
September
30, 2008
|
December
31, 2007
|
||||||||
Notional
or
|
Notional
or
|
|||||||||
Fair
|
Principal
|
Fair
|
Principal
|
|||||||
Value(1)
|
Amount
|
Value(1)
|
Amount
|
|||||||
Derivative
financial instruments in hedging relationships
|
||||||||||
U.S.
dollar cross-currency swaps
|
||||||||||
(maturing
2009 to 2014)(2)
|
39 |
U.S.
1,550
|
77 |
U.S.
350
|
||||||
U.S.
dollar forward foreign exchange contracts
|
||||||||||
(maturing
2008 to 2009)(2)
|
(46 | ) |
U.S.
2,780
|
(4 | ) |
U.S.
150
|
||||
U.S.
dollar options
|
||||||||||
(maturing
2008)(2)
|
(2 | ) |
U.S.
500
|
3 |
U.S.
600
|
|||||
(9 | ) |
U.S.
4,830
|
76 |
U.S.
1,100
|
||||||
(1)
Fair values are equal to carrying values.
|
||||||||||
(2)
As at September 30, 2008.
|
||||||||||
September
30, 2008
|
||||||||||||
(all
amounts in millions unless otherwise indicated)
|
Power
|
Natural
Gas
|
Interest
|
|||||||||
Derivative
Financial Instruments Held for Trading
|
||||||||||||
Fair
Values(1)
|
||||||||||||
Assets
|
$ | 62 | $ | 95 | $ | 30 | ||||||
Liabilities
|
$ | (48 | ) | $ | (75 | ) | $ | (25 | ) | |||
Notional
Values
|
||||||||||||
Volumes(2)
|
||||||||||||
Purchases
|
3,170 | 57 | - | |||||||||
Sales
|
3,775 | 62 | - | |||||||||
Canadian
dollars
|
- | - | 1,021 | |||||||||
U.S.
dollars
|
- | - | U.S. 1,400 | |||||||||
Net
unrealized gains/(losses) in the period(3)
|
||||||||||||
Three
months ended September 30, 2008
|
$ | 5 | $ | - | $ | 5 | ||||||
Nine
months ended September 30, 2008
|
$ | - | $ | (12 | ) | $ | 3 | |||||
Net
realized gains/(losses) in the period(3)
|
||||||||||||
Three
months ended September 30, 2008
|
$ | 12 | $ | (12 | ) | $ | 2 | |||||
Nine
months ended September 30, 2008
|
$ | 21 | $ | (6 | ) | $ | 12 | |||||
Maturity
dates
|
2008-2014 | 2008-2011 | 2008-2018 |
Derivative Financial
Instruments in Hedging Relationships(4)(5)
|
||||||||||||
Fair
Values(1)
|
||||||||||||
Assets
|
$ | 156 | $ | 3 | $ | 5 | ||||||
Liabilities
|
$ | (88 | ) | $ | (14 | ) | $ | (20 | ) | |||
Notional
Values
|
||||||||||||
Volumes(2)
|
||||||||||||
Purchases
|
7,024 | 14 | - | |||||||||
Sales
|
15,549 | - | - | |||||||||
Canadian
dollars
|
- | - | 50 | |||||||||
U.S.
dollars
|
- | - | U.S. 1,125 | |||||||||
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
|
2008-2014 | 2008-2011 | 2009-2019 | |||||||||
(1)
Fair value is equal to the carrying value of these
derivatives.
|
|||||||||||||||
(2) Volumes
for power and natural gas derivatives are in gigawatt hours (Gwh) and
billion cubic feet (Bcf), respectively.
|
|||||||||||||||
(3)
All realized and unrealized gains and losses are included in Net Income.
Realized gains and losses are included in Net Income after the financial
instrument has been settled.
|
|||||||||||||||
(4)
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 $3 million.
|
|||||||||||||||
(5)
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.
|
|||||||||||||||
2007
|
||||||||||||
(all
amounts in millions unless otherwise indicated)
|
Power
|
Natural
Gas
|
Interest
|
|||||||||
Derivative
Financial Instruments Held for Trading
|
||||||||||||
Fair
Values(1)(4)
|
||||||||||||
Assets
|
$ | 55 | $ | 43 | $ | 23 | ||||||
Liabilities
|
$ | (44 | ) | $ | (19 | ) | $ | (18 | ) | |||
Notional
Values(4)
|
||||||||||||
Volumes(2)
|
||||||||||||
Purchases
|
3,774 | 47 | - | |||||||||
Sales
|
4,469 | 64 | - | |||||||||
Canadian
dollars
|
- | - | 615 | |||||||||
U.S.
dollars
|
- | - |
U.S.
550
|
|||||||||
Net
unrealized gains/(losses) in the period(3)
|
||||||||||||
Three
months ended September 30, 2007
|
$ | 2 | $ | 23 | $ | - | ||||||
Nine
months ended September 30, 2007
|
$ | 11 | $ | 6 | $ | 1 | ||||||
Net
realized gains/(losses) in the period(3)
|
||||||||||||
Three
months ended September 30, 2007
|
$ | 2 | $ | 18 | $ | 3 | ||||||
Nine
months ended September 30, 2007
|
$ | (7 | ) | $ | 36 | $ | 4 | |||||
Maturity dates (4) | 2008-2016 | 2008-2010 | 2008-2016 |
Derivative Financial
Instruments in Hedging Relationships(5)(6)
|
||||||||||||
Fair
Values(1)(4)
|
||||||||||||
Assets
|
$ | 135 | $ | 19 | $ | 2 | ||||||
Liabilities
|
$ | (104 | ) | $ | (7 | ) | $ | (16 | ) | |||
Notional
Values(4)
|
||||||||||||
Volumes(2)
|
||||||||||||
Purchases
|
7,362 | 28 | - | |||||||||
Sales
|
16,367 | 4 | - | |||||||||
Canadian
dollars
|
- | - | 150 | |||||||||
U.S.
dollars
|
- | - |
U.S. 875
|
|||||||||
Net
realized (losses)/gains in the period(3)
|
||||||||||||
Three
months ended September 30, 2007
|
$ | (51 | ) | $ | 10 | $ | 2 | |||||
Nine
months ended September 30, 2007
|
$ | (37 | ) | $ | 7 | $ | 3 | |||||
Maturity dates (4) | 2008-2013 | 2008-2010 | 2008-2013 |
(1)
Fair value is equal to the carrying value of these
derivatives.
|
|||||||||||||||
(2) Volumes
for power and natural gas derivatives are in Gwh and Bcf,
respectively.
|
|||||||||||||||
(3)
All realized and unrealized gains and losses are included in Net Income.
Realized gains and losses are included in Net Income after the financial
instrument has been settled.
|
|||||||||||||||
(4) As
at December 31, 2007.
|
|||||||||||||||
(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 $2 million at December 31,
2007.
|
|||||||||||||||
(6)
Net Income for the three and nine months ended September 30, 2007 included
losses of $4 million and $7 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. Net Income for the three and nine
months ended September 30, 2007 included nil and a
|
|||||||||||||||
$4
million loss, respectively, for the changes in fair value of an
interest-rate cash flow hedge that was reclassified as a result
of
|
|||||||||||||||
discontinuance
of cash flow hedge accounting when the anticipated transaction was
identified as not probable of occurring by
|
|||||||||||||||
the
end of the originally specified time period.
|
8.
|
Employee
Future Benefits
|
Three
months ended September 30
|
Pension
Benefit Plans
|
Other
Benefit Plans
|
||||||||||
(unaudited
- millions of dollars)
|
2008
|
2007
|
2008
|
2007
|
||||||||
Current
service cost
|
13
|
11
|
-
|
-
|
||||||||
Interest
cost
|
20
|
19
|
2
|
2
|
||||||||
Expected
return on plan assets
|
(23)
|
(23)
|
-
|
-
|
||||||||
Amortization
of net actuarial loss
|
4
|
7
|
1
|
1
|
||||||||
Amortization
of past service costs
|
1
|
1
|
-
|
-
|
||||||||
Net
benefit cost recognized
|
15
|
15
|
3
|
3
|
||||||||
Nine
months ended September 30
|
Pension
Benefit Plans
|
Other
Benefit Plans
|
||||||||||
(unaudited
- millions of dollars)
|
2008
|
2007
|
2008
|
2007
|
||||||||
Current
service cost
|
38
|
33
|
1
|
1
|
||||||||
Interest
cost
|
59
|
54
|
6
|
5
|
||||||||
Expected
return on plan assets
|
(69)
|
(62)
|
(1)
|
(1)
|
||||||||
Amortization
of transitional obligation related to
|
||||||||||||
regulated
business
|
-
|
-
|
1
|
1
|
||||||||
Amortization
of net actuarial loss
|
13
|
19
|
2
|
2
|
||||||||
Amortization
of past service costs
|
3
|
3
|
-
|
(1)
|
||||||||
Net
benefit cost recognized
|
44
|
47
|
9
|
7
|
||||||||
9.
|
Calpine
Bankruptcy Settlements
|
10.
|
Writedown
of Development Costs
|
11.
|
Commitments
and Contingencies
|
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 at (403) 920-7859
or 1-800-608-7859.
Visit
the TransCanada website at: http://www.transcanada.com.
|
(unaudited)
|
Three
months ended
September
30
|
Nine
months ended
September
30
|
|||||||
(millions
of dollars, except per share amounts)
|
2008
|
2007
|
2008
|
2007
|
|||||
Net
Income in Accordance with Canadian GAAP
|
390
|
324
|
1,163
|
846
|
|||||
U.S.
GAAP adjustments:
|
|||||||||
Unrealized loss on natural gas
inventory held in storage, net of tax of $35 and $11
for the three and nine
months ended September 30th,
2008(1)
|
73
|
-
|
21
|
-
|
|||||
Unrealized loss on foreign
exchange and interest rate derivatives,
net of tax(2)
|
-
|
-
|
-
|
(3
|
)
|
||||
Tax recovery due to a change in
tax legislation substantively
enacted in Canada(3)
|
(1
|
)
|
-
|
(2
|
)
|
(11
|
)
|
||
Net
Income in Accordance with U.S. GAAP
|
462
|
324
|
1,182
|
832
|
|||||
Other
Comprehensive Income (Loss) in Accordance withCanadian
GAAP
|
29
|
(42
|
)
|
59
|
(225
|
)
|
|||
U.S.
GAAP adjustments:
|
|||||||||
Change in funded status of
postretirement plan liability, net
of tax(4)
|
2
|
2
|
5
|
5
|
|||||
Change in equity investment
funded status of postretirement
plan liability, net of tax(4)
|
2
|
2
|
6
|
13
|
|||||
Unrealized loss on derivatives,
net of tax(5)
|
-
|
(1
|
)
|
-
|
(6
|
)
|
|||
Comprehensive
Income in Accordance with U.S. GAAP
|
495
|
285
|
1,252
|
619
|
|||||
Net
Earnings Per Share in Accordance with U.S. GAAP
|
|||||||||
Basic and
Diluted
|
$0.79
|
$0.60
|
$2.10
|
$1.57
|
(millions
of dollars)
|
September
30,
2008
(unaudited)
|
December
31,
2007
|
|||
Current
assets(1)
|
2,266
|
1,766
|
|||
Long-term
investments(4)(6)(7)
|
4,444
|
3,568
|
|||
Plant,
property and equipment
|
21,227
|
19,225
|
|||
Goodwill
|
3,766
|
2,521
|
|||
Other
assets(8)(9)
|
3,588
|
3,448
|
|||
35,291
|
30,528
|
||||
Current
liabilities(3)
|
3,227
|
2,774
|
|||
Deferred
amounts(4)(7)
|
1,394
|
1,158
|
|||
Deferred
income taxes(1)(4)(6)(8)
|
2,602
|
2,693
|
|||
Long-term
debt and junior subordinated notes(9)
|
15,419
|
13,423
|
|||
Non-controlling
interests
|
1,095
|
999
|
|||
23,737
|
21,047
|
||||
Shareholders’
equity:
|
|||||
Common
shares
|
8,091
|
6,663
|
|||
Contributed
surplus
|
278
|
276
|
|||
Retained
earnings(1)(2)(3)(6)
|
3,751
|
3,180
|
|||
Accumulated
other comprehensive income(4)(10)
|
(566
|
)
|
(638
|
)
|
|
11,554
|
9,481
|
||||
35,291
|
30,528
|
(1)
|
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.
|
(2)
|
Represents
the amortization of certain hedges that became ineffective at different
times under Canadian and U.S. GAAP.
|
(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 under Statement of Financial
Accounting Standards No.158 “Employers’ Accounting for Defined Benefit
Pension and Other Postretirement Plans” for the Company’s defined benefit
pension and other postretirement
plans.
|
(5)
|
Relates
to gains and losses realized in 2006 on derivative energy contracts for
periods before they were documented as hedges for purposes of U.S. GAAP
and to differences in accounting for physical energy
contracts.
|
(6)
|
Under
Canadian GAAP, pre-operating costs incurred during the commissioning phase
of a new project are deferred until commercial production levels are
achieved. After such time, those costs are amortized over the estimated
life of the project. Under U.S. GAAP, such costs are expensed as incurred.
Certain start-up costs incurred by Bruce Power L.P. (Bruce), an equity
investment, were expensed under U.S. GAAP. Under both Canadian GAAP and
U.S. GAAP, interest is capitalized on expenditures relating to
construction of development projects actively being prepared for their
intended use. Under U.S. GAAP, the carrying value of Bruce’s development
projects against which interest is capitalized is lower due to the
expensing of certain pre-operating
costs.
|
(7)
|
For
U.S. GAAP purposes, the fair value of guarantees recorded as a liability
at September 30, 2008 was $53 million (December 31, 2007 - $27 million)
and relates to the Company’s equity interests in its long-term
investments.
|
(8)
|
Under
U.S. GAAP, the Company is required to record a deferred income tax
liability for its cost-of-service regulated businesses. As these deferred
income taxes are recoverable through future revenues, a corresponding
regulatory asset is recorded for U.S. GAAP
purposes.
|
(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, 2008, Accumulated Other Comprehensive Income in accordance
with U.S. GAAP is $252 million lower than under Canadian
GAAP. The difference relates to the accounting treatment for
defined benefit pension and other postretirement
plans.
|
(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 Held for Trading:
|
||||
Assets
|
39
|
159
|
-
|
198
|
Liabilities
|
(30)
|
(241)
|
-
|
(271)
|
Derivative
Financial Instruments in Hedging Relationships:
|
||||
Assets
|
4
|
223
|
-
|
227
|
Liabilities
|
(65)
|
(173)
|
-
|
(238)
|
Non-Derivative
Financial Instruments Available for Sale:
|
||||
Assets
|
20
|
-
|
-
|
20
|
Liabilities
|
-
|
-
|
-
|
-
|
Total
|
(32)
|
(32)
|
-
|
(64)
|
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
registrant as of, and for, the periods presented in this
report;
|
4.
|
The
registrant’s other certifying officer(s) and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal
control over financial reporting (as defined in Exchange Act Rules
13a-15(f) and 15d-15(f)) for the registrant and
have:
|
|
(a) designed
such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to ensure
that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being
prepared;
|
|
(b) designed
such internal control over financial reporting, or caused such internal
control over financial reporting to be designed under our supervision, to
provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting
principles;
|
|
(c) evaluated
the effectiveness of the registrant’s disclosure controls and procedures
and presented in this report our conclusions about the effectiveness of
the disclosure controls and procedures, as of the end of the period
covered by this report based on such evaluation;
and
|
|
(d) disclosed
in this report any change in the registrant’s internal control over
financial reporting that occurred during the registrant’s most recent
fiscal quarter (the registrant’s fourth fiscal quarter in the case of an
annual report) that has materially affected, or is reasonably likely to
materially affect, the registrant’s internal control over financial
reporting; and
|
5.
|
The
registrant’s other certifying officer(s) and I have disclosed, based on
our most recent evaluation of internal control over financial reporting,
to the registrant’s auditors and the audit committee of the registrant’s
board of directors (or persons performing the equivalent
functions):
|
|
(a) all
significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant’s ability to record,
process, summarize and report financial information;
and
|
|
(b) any
fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant’s internal control
over financial reporting.
|
Dated:
|
October
28, 2008
|
/s/ Harold N.
Kvisle
|
|
Harold
N. Kvisle
|
|||
President
and Chief Executive
Officer
|
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
registrant as of, and for, the periods presented in this
report;
|
||
4.
|
The
registrant’s other certifying officer(s) and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal
control over financial reporting (as defined in Exchange Act Rules
13a-15(f) and 15d-15(f)) for the registrant and have:
|
||
(a)
designed such disclosure controls and procedures, or caused such
disclosure controls and procedures to be designed under our supervision,
to ensure that material information relating to the registrant, including
its consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being
prepared;
|
|||
(b)
designed such internal control over financial reporting, or caused such
internal control over financial reporting to be designed under our
supervision, to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements for
external purposes in accordance with generally accepted accounting
principles;
|
|||
(c)
evaluated the effectiveness of the registrant’s disclosure controls and
procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end of
the period covered by this report based on such evaluation;
and
|
|||
(d)
disclosed in this report any change in the registrant’s internal control
over financial reporting that occurred during the registrant’s most recent
fiscal quarter (the registrant’s fourth fiscal quarter in the case of an
annual report) that has materially affected, or is reasonably likely to
materially affect, the registrant’s internal control over financial
reporting; and
|
|||
5.
|
The
registrant’s other certifying officer(s) and I have disclosed, based on
our most recent evaluation of internal control over financial reporting,
to the registrant’s auditors and the audit committee of the registrant’s
board of directors (or persons performing the equivalent
functions):
|
||
(a)
all significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant’s ability to record,
process, summarize and report financial information; and
|
|||
(b)
any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant’s internal control
over financial reporting.
|
|||
Dated:
|
October
28, 2008
|
/s/ Gregory A.
Lohnes
|
|
Gregory
A. Lohnes
|
|||
Executive
Vice-President
and
Chief Financial Officer
|
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
|
|
October
28, 2008
|
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
|
|
October
28, 2008
|
Media
Inquiries:
|
Cecily
Dobson
|
(403)
920-7859
(800)
608-7859
|
Analyst
Inquiries:
|
David
Moneta/Myles Dougan/Terry Hook
|
(403)
920-7911
(800)
361-6522
|
§
|
Net
income for third quarter 2008 of $390 million ($0.67 per share) compared
to $324 million ($0.60 per share) for the same period in 2007, an increase
of approximately 12 per cent on a per share
basis
|
§
|
Comparable
earnings for third quarter 2008 of $366 million ($0.63 per share) compared
to $309 million ($0.57 per share) for the same period in 2007, an increase
of approximately 11 per cent on a per share
basis
|
§
|
Funds
generated from operations for third quarter 2008 of $711 million compared
to $702 million for the same period in
2007
|
§
|
Dividend
of $0.36 per common share declared by the Board of
Directors
|
§
|
Acquired
the 2,480 megawatt (MW) Ravenswood Generating Station for US$2.9 billion,
subject to certain post-closing
adjustments
|
§
|
Secured
firm, long term contracts for the Keystone Pipeline system expansion to
the U.S. Gulf Coast
|
§
|
Agreed
to increase ownership interest in the Keystone Pipeline
system
|
§
|
During
the third quarter of 2008, Keystone Pipeline system conducted an open
season to solicit interest for an expansion and extension of the crude oil
pipeline system from Hardisty, Alberta to the U.S. Gulf Coast, the largest
refining market in North America.
|
§
|
On
October 10, 2008, TransCanada received approval from the Alberta Utilities
Commission for a permit to construct the approximately $925 million North
Central Corridor expansion, which comprises a 300-kilometre (km) natural
gas pipeline and associated facilities on the northern section of the
Alberta System.
|
§
|
On
August 1, 2008, the Alaska Senate approved TransCanada’s application for a
license to advance the Alaska Pipeline Project under the Alaska Gasline Inducement
Act (AGIA). Governor Palin signed the Bill on August 27, 2008.
TransCanada expects the Alaska Commissioners of Revenue and Natural
Resources to issue the AGIA license in late November 2008 after the 90-day
waiting period for the Bill to become effective. TransCanada has committed
under the AGIA to advance the Alaska Pipeline Project through an open
season and subsequent FERC certification. TransCanada has
commenced the engineering, environmental, field and commercial work and
expects to conclude an open season by July 31,
2010.
|
§
|
On
September 3, 2008, TransCanada acquired Bison Pipeline LLC from Northern
Border for US$20 million. The acquisition included all work completed on
the Bison Pipeline project, a proposed 465-km pipeline from the Powder
River Basin in Wyoming to the Northern Border system in North Dakota. The
Bison Pipeline project has shipping commitments for 405 million cubic feet
per day and is planned to be in service in fourth-quarter
2010. The capital cost of the Bison Pipeline project is
estimated at approximately US$500 million to US$600 million depending on
the diameter of the pipeline. One of the committed shippers has
an option to acquire up to a 25 per cent equity ownership in the
project.
|
§
|
On
August 26, 2008, TransCanada acquired the 2,480 MW Ravenswood Generating
Station for US$2.9 billion, subject to certain post-closing adjustments.
In September 2008, the 972 MW Unit 30 experienced an unplanned outage as a
result of a problem with its high pressure steam turbine. The repair costs
and lost revenues associated with the unplanned outage, which are yet to
be finalized, are anticipated to be recovered through insurance. As a
result of the expected insurance recoveries, the Unit 30 unplanned outage
is not expected to have a significant impact on TransCanada’s
earnings.
|
§
|
On
May 30, 2008, the Portlands Energy Centre natural gas-fired combined-cycle
power plant near downtown Toronto, Ontario went into service in
simple-cycle mode. In September 2008, the power plant returned
to the construction phase and is expected to be fully commissioned in
combined-cycle mode and capable of delivering 550 MW of power in
first-quarter 2009.
|
§
|
In
July 2008, TransCanada commenced construction work on the Kibby Wind Power
project. The capital cost of the project is expected to be approximately
US$320 million with commissioning anticipated in
2009-2010.
|
§
|
During
third-quarter 2008, TransCanada commenced detailed engineering,
geotechnical, and regulatory work for the 575 MW Coolidge power generation
facility in Arizona. When constructed, the output from the plant will be
sold to Salt River Project Agricultural Improvement and Power District
under a 20-year agreement. The facility is expected to cost US$500 million
and is expected to be in service in
2011.
|
§
|
TransCanada’s
financial position and ability to generate cash in the short and long term
from its operations remains sound. TransCanada has conducted a
sizeable funding program in 2008, which consisted of a $1.3 billion common
equity issue in May 2008 and term debt issues of US$1.5 billion and $500
million along with a US$255 million draw on a Ravenswood acquisition
bridge facililty in August 2008. In addition, common shares issued under
TransCanada’s Dividend Reinvestment and Share Purchase Plan are expected
to approach $250 million in 2008. Continued balance sheet strength has
been supported by over $4.7 billion of subordinated capital raised over
the course of 2007 and 2008.
|
§
|
TransCanada’s
liquidity position remains sound, underpinned by highly predictable cash
flow from operations, as well as committed revolving bank lines of $2.0
billion and US$300 million, maturing in December 2012 and February 2013,
respectively, which remain fully available. To date, no draws
have been made on these facilities as TransCanada has continued to have
largely uninterupted access to the Canadian commercial paper market on
competitive terms. An additional $50 million and US$325 million of
capacity remain available on committed bank facilities at
TransCanada-operated affiliates with maturity dates from 2010 through
2012. TransCanada is presently seeking to establish further committed bank
lines in support of its Keystone Pipeline construction efforts and expects
these to be in place in fourth quarter 2008. TransCanada views
its core bank group as high quality and its relationship with these
institutions as excellent. Also in fourth quarter 2008,
TransCanada expects to file a new US$3.0 billion debt shelf to replace the
previous US$2.5 billion debt shelf which was recently
exhausted. This will supplement the $3.0 billion and $1.0
billion of capacity available under its existing equity and Canadian debt
shelves, respectively.
|
Operating
Results
|
Three
months ended
September
30
|
Nine
months ended
September
30
|
||||||||||||||
(millions
of dollars)
|
2008
|
2007
|
2008
|
2007
|
||||||||||||
Revenues
|
2,137 | 2,187 | 6,287 | 6,639 | ||||||||||||
Net
Income
|
390 | 324 | 1,163 | 846 | ||||||||||||
Comparable
Earnings (1)
|
366 | 309 | 1,008 | 800 | ||||||||||||
Cash
Flows
|
||||||||||||||||
Funds
generated from operations (1)
|
711 | 702 | 2,309 | 1,880 | ||||||||||||
Decrease
in operating working capital
|
114 | 132 | 16 | 261 | ||||||||||||
Net
cash provided by operations
|
825 | 834 | 2,325 | 2,141 | ||||||||||||
Capital
Expenditures
|
806 | 364 | 1,899 | 1,056 | ||||||||||||
Acquisitions,
Net of Cash Acquired
|
3,054 | (2 | ) | 3,058 | 4,222 | |||||||||||
Common
Share Statistics
|
Three
months ended
September
30
|
Nine
months ended
September
30
|
||||||||||||||
2008
|
2007
|
2008
|
2007
|
|||||||||||||
Net
Income Per Share - Basic
|
$ | 0.67 | $ | 0.60 | $ | 2.07 | $ | 1.60 | ||||||||
Comparable
Earnings Per Share - Basic (1)
|
$ | 0.63 | $ | 0.57 | $ | 1.80 | $ | 1.51 | ||||||||
Dividends
Declared Per Share
|
$ | 0.36 | $ | 0.34 | $ | 1.08 | $ | 1.02 | ||||||||
Basic Common Shares Outstanding
(millions)
|
||||||||||||||||
Average
for the period
|
579 | 537 | 560 | 527 | ||||||||||||
End
of period
|
580 | 538 | 580 | 538 | ||||||||||||
(1)
For a further discussion on comparable earnings, comparable earnings per
share and funds generated from operations, refer to the Non-GAAP Measures
section in this News Release.
|
||||||||||||||||
|
||||||||||||||||