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 June 30,
2009.
|
13.2
|
Consolidated
comparative interim unaudited financial statements of the registrant for
the period ended June 30, 2009 (included in the registrant's Second
Quarter 2009 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
Second Quarter 2009 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 July 30, 2009.
|
For
the three months ended June 30
|
||||||||||||||||||||||||||||||||
(unaudited)(millions
of dollars except per share amounts)
|
Pipelines
|
Energy
|
Corporate
|
Total
|
||||||||||||||||||||||||||||
|
2009
|
2008
|
2009
|
2008
|
2009
|
2008
|
2009
|
2008
|
||||||||||||||||||||||||
Comparable EBITDA(1)
|
747 | 714 | 301 | 260 | (31 | ) | (26 | ) | 1,017 | 948 | ||||||||||||||||||||||
Depreciation
and amortization
|
(258 | ) | (257 | ) | (87 | ) | (58 | ) | - | - | (345 | ) | (315 | ) | ||||||||||||||||||
Comparable EBIT(1)
|
489 | 457 | 214 | 202 | (31 | ) | (26 | ) | 672 | 633 | ||||||||||||||||||||||
Specific
item:
|
||||||||||||||||||||||||||||||||
Fair value adjustment of
natural
gas inventory and
forward contracts
|
- | - | (7 | ) | 12 | - | - | (7 | ) | 12 | ||||||||||||||||||||||
EBIT(1)
|
489 | 457 | 207 | 214 | (31 | ) | (26 | ) | 665 | 645 | ||||||||||||||||||||||
Interest
expense
|
(259 | ) | (186 | ) | ||||||||||||||||||||||||||||
Financial
charges of joint ventures
|
(16 | ) | (17 | ) | ||||||||||||||||||||||||||||
Interest
income and other
|
34 | 25 | ||||||||||||||||||||||||||||||
Income
taxes
|
(97 | ) | (126 | ) | ||||||||||||||||||||||||||||
Non-controlling
interests
|
(13 | ) | (17 | ) | ||||||||||||||||||||||||||||
Net
Income
|
314 | 324 | ||||||||||||||||||||||||||||||
Specific
item (net of tax):
|
||||||||||||||||||||||||||||||||
Fair value adjustment of
natural gas inventory and forward contracts
|
5 | (8 | ) | |||||||||||||||||||||||||||||
Comparable Earnings(1)
|
319 | 316 | ||||||||||||||||||||||||||||||
Net Income Per Share - Basic
and Diluted(2)
|
$ | 0.50 | $ | 0.58 |
(1)
|
Refer
to the Non-GAAP Measures section in this MD&A for further discussion
of comparable EBITDA, comparable EBIT, EBIT, comparable earnings and
comparable earnings per share.
|
For
the three months ended June 30
|
|||||||||
(2) |
(unaudited)
|
2009
|
2008
|
||||||
Net
Income Per Share
|
$ | 0.50 | $ | 0.58 | |||||
Specific item (net of
tax):
|
|||||||||
Fair value adjustment of
natural gas inventory and forward contracts
|
0.01 | (0.01 | ) | ||||||
Comparable Earnings Per
Share(1)
|
$ | 0.51 | $ | 0.57 |
For
the six months ended June 30
|
||||||||||||||||||||||||||||||||
(unaudited)(millions
of dollars except per
|
Pipelines
|
Energy
|
Corporate
|
Total
|
||||||||||||||||||||||||||||
share
amounts)
|
2009
|
2008
|
2009
|
2008
|
2009
|
2008
|
2009
|
2008
|
||||||||||||||||||||||||
Comparable EBITDA(1)
|
1,618 | 1,516 | 591 | 547 | (61 | ) | (48 | ) | 2,148 | 2,015 | ||||||||||||||||||||||
Depreciation
and amortization
|
(518 | ) | (511 | ) | (173 | ) | (114 | ) | - | - | (691 | ) | (625 | ) | ||||||||||||||||||
Comparable EBIT(1)
|
1,100 | 1,005 | 418 | 433 | (61 | ) | (48 | ) | 1,457 | 1,390 | ||||||||||||||||||||||
Specific
items:
|
||||||||||||||||||||||||||||||||
Fair value adjustment of
natural gas
inventory and forward
contracts
|
- | - | (20 | ) | (5 | ) | - | - | (20 | ) | (5 | ) | ||||||||||||||||||||
Calpine bankruptcy
settlements
|
- | 279 | - | - | - | - | - | 279 | ||||||||||||||||||||||||
GTN lawsuit
settlement
|
- | 17 | - | - | - | - | - | 17 | ||||||||||||||||||||||||
Writedown of Broadwater
LNG
project costs
|
- | - | - | (41 | ) | - | - | - | (41 | ) | ||||||||||||||||||||||
EBIT(1)
|
1,100 | 1,301 | 398 | 387 | (61 | ) | (48 | ) | 1,437 | 1,640 | ||||||||||||||||||||||
Interest
expense
|
(554 | ) | (404 | ) | ||||||||||||||||||||||||||||
Financial
charges of joint ventures
|
(30 | ) | (33 | ) | ||||||||||||||||||||||||||||
Interest
income and other
|
56 | 36 | ||||||||||||||||||||||||||||||
Income
taxes
|
(213 | ) | (378 | ) | ||||||||||||||||||||||||||||
Non-controlling
interests
|
(48 | ) | (88 | ) | ||||||||||||||||||||||||||||
Net
Income
|
648 | 773 | ||||||||||||||||||||||||||||||
Specific
items (net of tax):
|
||||||||||||||||||||||||||||||||
Fair value adjustment of
natural gas inventory and forward contracts
|
14 | 4 | ||||||||||||||||||||||||||||||
Calpine bankruptcy
settlements
|
- | (152 | ) | |||||||||||||||||||||||||||||
GTN lawsuit
settlement
|
- | (10 | ) | |||||||||||||||||||||||||||||
Writedown of Broadwater LNG
project costs
|
- | 27 | ||||||||||||||||||||||||||||||
Comparable Earnings(1)
|
662 | 642 | ||||||||||||||||||||||||||||||
Net Income Per Share - Basic
and Diluted
(2)
|
$ | 1.04 | $ | 1.40 |
(1)
|
Refer
to the Non-GAAP Measures section in this MD&A for further discussion
of comparable EBITDA, comparable EBIT, EBIT, comparable earnings and
comparable earnings per share.
|
For
the six months ended June 30
|
|||||||||
(2) |
(unaudited)
|
2009
|
2008
|
||||||
Net
Income Per Share
|
$ | 1.04 | $ | 1.40 | |||||
Specific items (net of
tax):
|
|||||||||
Fair value adjustment of
natural gas inventory and forward contracts
|
0.02 | 0.01 | |||||||
Calpine bankruptcy
settlements
|
- | (0.27 | ) | ||||||
GTN lawsuit
settlement
|
- | (0.02 | ) | ||||||
Writedown of Broadwater LNG
project costs
|
- | 0.05 | |||||||
Comparable Earnings Per
Share(1)
|
$ | 1.06 | $ | 1.17 |
•
|
increased
EBIT from Pipelines, primarily due to the positive impact of a stronger
U.S. dollar on Pipelines’ U.S.
operations;
|
•
|
decreased
EBIT from Energy primarily due to lower power prices in Western Power and
a $13 million year-over-year change in the after tax fair value adjustment
of natural gas inventory and forward contracts. These decreases were
partially offset by increased earnings in Bruce Power due to higher
realized prices and in Eastern Power from the start up of Portlands Energy
and the Carleton wind farm, and in the Natural Gas Storage business due to
a lower cost of proprietary natural gas
sold;
|
•
|
increased
EBIT losses from Corporate due to higher support services costs as a
result of a growing asset base; and
|
•
|
increased
interest expense due to debt issuances throughout 2008 and first quarter
2009 offset by decreased income tax expense primarily due to reduced
earnings and positive income tax adjustments in
2009.
|
•
|
decreased
EBIT from Pipelines due to $152 million of after tax gains ($279 million
pre-tax) on the sale of shares received by GTN and Portland for Calpine
bankruptcy settlements and proceeds from a GTN lawsuit settlement of $10
million after tax ($17 million pre-tax) received in first quarter 2008.
The impact of these items on the Pipelines segment was partially offset by
the positive impact of a stronger U.S. dollar on Pipelines’ U.S.
operations.
|
•
|
increased
EBIT from Energy due to increased contribution from Bruce Power as a
result of higher realized prices and output, Eastern Power from the start
up of Portlands Energy and the Carleton wind farm, and the impact of a $27
million after tax ($41 million pre-tax) writedown of costs capitalized for
the Broadwater liquefied natural gas (LNG) project in first quarter 2008.
These positive impacts in Energy were partially offset by decreased
contributions from Western Power due to lower overall realized prices and
lower volumes of power sold.
|
•
|
increased
EBIT losses from Corporate due to higher support services costs as a
result of a growing asset base; and
|
•
|
increased
interest expense due to debt issuances throughout 2008 and first quarter
2009, and the negative impact of a stronger U.S. dollar, partially offset
by decreased income tax expense due to lower earnings and positive income
tax adjustments in 2009.
|
(unaudited)
|
Three
months ended June 30
|
Six
months ended June 30
|
||||||||||||||
(millions
of dollars)
|
2009
|
2008
|
2009
|
2008
|
||||||||||||
Canadian
Pipelines
|
||||||||||||||||
Canadian
Mainline
|
288 | 283 | 572 | 573 | ||||||||||||
Alberta
System
|
177 | 179 | 345 | 358 | ||||||||||||
Foothills
|
34 | 34 | 68 | 69 | ||||||||||||
Other
(TQM, Ventures LP)
|
12 | 13 | 31 | 26 | ||||||||||||
Canadian Pipelines Comparable
EBITDA(1)
|
511 | 509 | 1,016 | 1,026 | ||||||||||||
U.S.
Pipelines
|
||||||||||||||||
ANR
|
73 | 72 | 206 | 174 | ||||||||||||
GTN
|
49 | 46 | 110 | 98 | ||||||||||||
Great
Lakes
|
33 | 29 | 77 | 65 | ||||||||||||
Iroquois
|
21 | 12 | 44 | 27 | ||||||||||||
PipeLines
LP(2)
|
16 | 15 | 40 | 34 | ||||||||||||
Portland(2)
|
2 | 2 | 16 | 14 | ||||||||||||
International
(Tamazunchale, TransGas, INNERGY/Gas
Pacifico)
|
15 | 12 | 28 | 22 | ||||||||||||
General,
administrative and support costs(3)
|
(3 | ) | (5 | ) | (6 | ) | (10 | ) | ||||||||
Non-controlling
interests(2)
|
38 | 39 | 103 | 93 | ||||||||||||
U.S. Pipelines Comparable
EBITDA(1)
|
244 | 222 | 618 | 517 | ||||||||||||
Business Development Comparable
EBITDA(1)
|
(8 | ) | (17 | ) | (16 | ) | (27 | ) | ||||||||
Pipelines Comparable
EBITDA(1)
|
747 | 714 | 1,618 | 1,516 | ||||||||||||
Depreciation
and amortization
|
(258 | ) | (257 | ) | (518 | ) | (511 | ) | ||||||||
Pipelines Comparable
EBIT(1)
|
489 | 457 | 1,100 | 1,005 | ||||||||||||
Specific
items:
|
||||||||||||||||
Calpine bankruptcy
settlements(4)
|
- | - | - | 279 | ||||||||||||
GTN lawsuit
settlement
|
- | - | - | 17 | ||||||||||||
Pipelines EBIT(1)
|
489 | 457 | 1,100 | 1,301 |
(1)
|
Refer
to the Non-GAAP Measures section in this MD&A for further discussion
of comparable EBITDA, comparable EBIT and
EBIT.
|
(2)
|
PipeLines
LP and Portland results reflect TransCanada’s 32.1 per cent and 61.7 per
cent ownership interests, respectively. The non-controlling interests
reflect amounts not owned by
TransCanada.
|
(3)
|
Represents
costs associated with the Company’s Canadian and foreign non-wholly owned
pipelines.
|
(4)
|
GTN
and Portland received shares of Calpine with an initial value of $154
million and $103 million, respectively, from the bankruptcy settlements
with Calpine. These shares were subsequently sold for an additional gain
of $22 million.
|
(unaudited)
|
Three
months ended June 30
|
Six
months ended June 30
|
||||||||
(millions
of dollars)
|
2009
|
2008
|
2009
|
2008
|
||||||
Canadian
Mainline
|
67
|
70
|
133
|
138
|
||||||
Alberta
System
|
40
|
33
|
79
|
65
|
||||||
Foothills
|
6
|
6
|
12
|
13
|
Six
months
ended
June 30
|
Canadian
Mainline(1)
|
Alberta
System(2)
|
Foothills
|
ANR(3)
|
GTN
System(3)
|
||||||||||||||||||||||||||||||||||
(unaudited)
|
2009
|
2008
|
2009
|
2008
|
2009
|
2008
|
2009
|
2008
|
2009 |
20088
|
|||||||||||||||||||||||||||||
Average
investment base
($
millions)
|
6,566 | 7,123 | 4,671 | 4,286 | 717 | 760 | n/a | n/a | n/a | n/a | |||||||||||||||||||||||||||||
Delivery
volumes (Bcf)
|
|||||||||||||||||||||||||||||||||||||||
Total
|
1,859 | 1,762 | 1,827 | 1,930 | 562 | 660 | 867 | 861 | 344 | 394 | |||||||||||||||||||||||||||||
Average per day
|
10.3 | 9.7 | 10.1 | 10.6 | 3.1 | 3.6 | 4.8 | 4.7 | 1.9 | 2.2 |
(1)
|
Canadian
Mainline’s physical receipts originating at the Alberta border and in
Saskatchewan for the six months ended June 30, 2009 were 883 billion cubic
feet (Bcf) (2008 – 971 Bcf); average per day was 4.9 Bcf (2008 – 5.3
Bcf).
|
(2)
|
Field
receipt volumes for the Alberta System for the six months ended June 30,
2009 were 1,848 Bcf (2008 – 1,919 Bcf); average per day was 10.2 Bcf (2008
– 10.5 Bcf).
|
(3)
|
ANR’s
and the GTN System’s results are not impacted by average investment base
as these systems operate under fixed rate models approved by the U.S.
Federal Energy Regulatory
Commission.
|
(unaudited)
|
Three
months ended June 30
|
Six
months ended June 30
|
||||||||||||||
(millions
of dollars)
|
2009
|
2008
|
2009
|
2008
|
||||||||||||
Canadian
Power
|
||||||||||||||||
Western
Power
|
59 | 138 | 152 | 237 | ||||||||||||
Eastern
Power
|
60 | 34 | 112 | 69 | ||||||||||||
Bruce
Power
|
102 | 49 | 201 | 103 | ||||||||||||
General,
administrative and support costs
|
(11 | ) | (9 | ) | (19 | ) | (16 |
)
|
||||||||
Canadian Power Comparable
EBITDA(1)
|
210 | 212 | 446 | 393 | ||||||||||||
U.S. Power(2)
|
||||||||||||||||
Northeast
Power
|
76 | 60 | 118 | 124 | ||||||||||||
General,
administrative and support costs
|
(11 | ) | (10 | ) | (23 | ) | (19 |
)
|
||||||||
U.S. Power Comparable
EBITDA(1)
|
65 | 50 | 95 | 105 | ||||||||||||
Natural
Gas Storage
|
||||||||||||||||
Alberta
Storage
|
36 | 10 | 75 | 79 | ||||||||||||
General,
administrative and support costs
|
(2 | ) | (4 | ) | (5 | ) | (6 |
)
|
||||||||
Natural Gas Storage Comparable
EBITDA(1)
|
34 | 6 | 70 | 73 | ||||||||||||
Business Development Comparable
EBITDA(1)
|
(8 | ) | (8 | ) | (20 | ) | (24 |
)
|
||||||||
Energy Comparable
EBITDA(1)
|
301 | 260 | 591 | 547 | ||||||||||||
Depreciation
and amortization
|
(87 | ) | (58 | ) | (173 | ) | (114 |
)
|
||||||||
Energy Comparable
EBIT(1)
|
214 | 202 | 418 | 433 | ||||||||||||
Specific
items:
|
||||||||||||||||
Fair value
adjustments of natural gas inventory
and forward
contracts
|
(7 | ) | 12 | (20 | ) |
(5
|
)
|
|||||||||
Writedown of
Broadwater LNG project costs
|
- | - | - | (41 |
)
|
|||||||||||
Energy EBIT(1)
|
207 | 214 | 398 | 387 |
(1)
|
Refer
to the Non-GAAP Measures section in this MD&A for further discussion
of comparable EBITDA, comparable EBIT and
EBIT.
|
(2)
|
Includes
Ravenswood effective August 2008.
|
(unaudited)
|
Three
months ended June 30
|
Six
months ended June 30
|
|||||||||||||||
(millions
of dollars)
|
2009
|
2008
|
2009
|
2008
|
|||||||||||||
Revenues
|
|||||||||||||||||
Western power
|
174 | 283 | 389 | 578 | |||||||||||||
Eastern power
|
71 | 48 | 140 | 100 | |||||||||||||
Other(3)
|
41 | 35 | 90 | 52 | |||||||||||||
286 | 366 | 619 | 730 | ||||||||||||||
Commodity
Purchases Resold
|
|||||||||||||||||
Western power
|
(109 | ) | (110 | ) | (207 | ) | (266 | ) | |||||||||
Eastern power
|
- | - | - | (2 | ) | ||||||||||||
Other(4)
|
(17 | ) | (21 | ) | (63 | ) | (34 | ) | |||||||||
(126 | ) | (131 | ) | (270 | ) | (302 | ) | ||||||||||
Plant
operating costs and other
|
(43 | ) | (64 | ) | (87 | ) | (123 | ) | |||||||||
General,
administrative and support costs
|
(11 | ) | (9 | ) | (19 | ) | (16 | ) | |||||||||
Other
income
|
2 | 1 | 2 | 1 | |||||||||||||
Comparable EBITDA(2)
|
108 | 163 | 245 | 290 |
(1)
|
Includes
Portlands Energy and Carleton effective April 2009 and November 2008,
respectively.
|
(2)
|
Refer
to the Non-GAAP Measures section in this MD&A for further discussion
of comparable EBITDA.
|
(3)
|
Other
revenue includes sales of natural gas and thermal carbon
black.
|
(4)
|
Other
commodity purchases resold includes the cost of natural gas
sold.
|
Three
months ended June 30
|
Six
months ended June 30
|
|||||||||
(unaudited)
|
2009
|
2008
|
2009
|
2008
|
||||||
Sales
Volumes (GWh)
|
||||||||||
Supply
|
||||||||||
Generation
|
||||||||||
Western Power
|
572
|
506
|
1,177
|
1,135
|
||||||
Eastern Power
|
421
|
226
|
776
|
512
|
||||||
Purchased
|
||||||||||
Sundance A & B and
Sheerness PPAs
|
2,725
|
2,835
|
5,165
|
6,194
|
||||||
Other
purchases
|
122
|
222
|
307
|
537
|
||||||
3,840
|
3,789
|
7,425
|
8,378
|
|||||||
Sales
|
||||||||||
Contracted
|
||||||||||
Western Power
|
2,597
|
2,819
|
4,650
|
5,893
|
||||||
Eastern Power
|
419
|
270
|
810
|
602
|
||||||
Spot
|
||||||||||
Western Power
|
824
|
700
|
1,965
|
1,883
|
||||||
3,840
|
3,789
|
7,425
|
8,378
|
|||||||
Plant
Availablity
|
||||||||||
Western
Power(2)(3)
|
93%
|
78%
|
92%
|
85%
|
||||||
Eastern
Power
|
98%
|
96%
|
98%
|
97%
|
(1)
|
Includes
Portlands Energy and Carleton effective April 2009 and November 2008,
respectively.
|
(2)
|
Excludes
facilities that provide power to TransCanada under
PPAs.
|
(3)
|
Western
Power plant availability increased in the three and six months ended June
30, 2009 due to outages at the MacKay River and Cancarb power facilities
in 2008.
|
(TransCanada’s proportionate
share)
(unaudited)
|
Three
months ended
June
30
|
Six
months ended
June
30
|
||||||||
(millions
of dollars unless otherwise indicated)
|
2009
|
2008
|
2009
|
2008
|
||||||
Revenues(1)(2)
|
240
|
191
|
461
|
376
|
||||||
Operating
Expenses(2)
|
(138
|
)
|
(142
|
)
|
(260
|
)
|
(273
|
)
|
||
Comparable EBITDA(3)
|
102
|
49
|
201
|
103
|
||||||
Bruce A Comparable
EBITDA(3)
|
47
|
22
|
88
|
57
|
||||||
Bruce B Comparable
EBITDA(3)
|
55
|
27
|
113
|
46
|
||||||
Comparable EBITDA(3)
|
102
|
49
|
201
|
103
|
||||||
Bruce
Power – Other Information
|
||||||||||
Plant
availability
|
||||||||||
Bruce A
|
100%
|
85%
|
99%
|
91%
|
||||||
Bruce B
|
75%
|
81%
|
86%
|
77%
|
||||||
Combined Bruce
Power
|
83%
|
82%
|
90%
|
81%
|
||||||
Planned
outage days
|
||||||||||
Bruce A
|
-
|
26
|
-
|
33
|
||||||
Bruce B
|
45
|
50
|
45
|
100
|
||||||
Unplanned
outage days
|
||||||||||
Bruce A
|
-
|
1
|
5
|
2
|
||||||
Bruce B
|
33
|
15
|
41
|
48
|
||||||
Sales
volumes (GWh)
|
||||||||||
Bruce A
|
1,563
|
1,330
|
3,058
|
2,826
|
||||||
Bruce B
|
1,662
|
1,804
|
3,801
|
3,428
|
||||||
3,225
|
3,134
|
6,859
|
6,254
|
|||||||
Results
per MWh
|
||||||||||
Bruce A power
revenues
|
$64
|
$63
|
$64
|
$61
|
||||||
Bruce B power
revenues
|
$70
|
$56
|
$63
|
$56
|
||||||
Combined Bruce Power
revenues
|
$68
|
$58
|
$63
|
$58
|
||||||
Combined
Bruce Power operating expenses(4)
|
$42
|
$44
|
$36
|
$36
|
||||||
Percentage
of Bruce B output sold to spot market
|
40%
|
33%
|
38%
|
39%
|
(1)
|
Revenues
include Bruce A’s fuel cost recoveries of $11 million and $21 million for
the three and six months ended June 30, 2009, respectively (2008 - $7
million and $13 million). It also includes gains of nil and $2 million as
a result of changes in fair value of held-for-trading derivatives for the
three and six months ended June 30, 2009, respectively (2008 - losses of
$3 million and $6 million).
|
(2)
|
Includes
adjustments to eliminate the effects of inter-partnership transactions
between Bruce A and Bruce B.
|
(3)
|
Refer
to the Non-GAAP Measures section in this MD&A for further discussion
of comparable EBITDA.
|
(4)
|
Net
of fuel cost recoveries and excluding
depreciation.
|
(unaudited)
|
Three
months ended June 30
|
Six
months ended June 30
|
|||||||||||||||
(millions
of dollars)
|
2009
|
2008
|
2009
|
2008 |
|
||||||||||||
Revenues
|
|||||||||||||||||
Power
|
321 | 215 | 661 | 441 | |||||||||||||
Other(3)(4)
|
78 | 95 | 250 | 177 | |||||||||||||
399 | 310 | 911 | 618 | ||||||||||||||
Commodity
Purchases Resold
|
|||||||||||||||||
Power
|
(117 | ) | (105 | ) | (272 | ) | (239 | ) | |||||||||
Other(5)
|
(56 | ) | (96 | ) | (187 | ) | (162 | ) | |||||||||
(173 | ) | (201 | ) | (459 | ) | (401 | ) | ||||||||||
Plant
operating costs and other(4)
|
(150 | ) | (49 | ) | (334 | ) | (93 | ) | |||||||||
General,
administrative and support costs
|
(11 | ) | (10 | ) | (23 | ) | (19 | ) | |||||||||
Comparable EBITDA(2)
|
65 | 50 | 95 | 105 |
(1)
|
Includes
Ravenswood effective August 2008.
|
(2)
|
Refer
to the Non-GAAP Measures section in this MD&A for further discussion
of comparable EBITDA.
|
(3)
|
Other
revenue includes sales of natural
gas.
|
(4)
|
Includes
activity at Ravenswood related to a third-party owned steam production
facility operated by TransCanada on behalf of the plant
owner.
|
(5)
|
Other
commodity purchases resold includes the cost of natural gas
sold.
|
Three
months ended June 30
|
Six
months ended June 30
|
|||||||||
(unaudited)
|
2009
|
2008
|
2009
|
2008
|
||||||
Sales
Volumes (GWh)
|
||||||||||
Supply
|
||||||||||
Generation
|
1,404
|
830
|
2,572
|
1,630
|
||||||
Purchased
|
1,135
|
1,339
|
2,394
|
2,817
|
||||||
2,539
|
2,169
|
4,966
|
4,447
|
|||||||
Sales
|
||||||||||
Contracted
|
1,791
|
2,101
|
3,577
|
4,281
|
||||||
Spot
|
748
|
68
|
1,389
|
166
|
||||||
2,539
|
2,169
|
4,966
|
4,447
|
|||||||
Plant
Availability
|
78%
|
96%
|
68%
|
94%
|
(1)
|
Includes
Ravenswood effective August 2008.
|
(unaudited)
|
Three
months ended June 30
|
Six
months ended June 30
|
||||||||||||||
(million
of dollars)
|
2009
|
2008
|
2009
|
2008
|
||||||||||||
Interest
on long-term debt(1)
|
329 | 235 | 664 | 483 | ||||||||||||
Other
interest and amortization
|
(7 | ) | (17 | ) | 7 | (20 |
)
|
|||||||||
Capitalized
interest
|
(63 | ) | (32 | ) | (117 |
)
|
(59 |
)
|
||||||||
259 | 186 | 554 | 404 |
(1)
|
Includes
interest for Junior Subordinated
Notes.
|
(unaudited)
|
Three
months ended June 30
|
Six
months ended June 30
|
||||||||||||||
(millions
of dollars)
|
2009
|
2008
|
2009
|
2008
|
||||||||||||
Cash
Flows
|
||||||||||||||||
Funds generated from
operations(1)
|
692 | 676 | 1,458 | 1,598 | ||||||||||||
Decrease/(increase) in
operating working capital
|
315 | (104 | ) | 393 | (98 | ) | ||||||||||
Net cash provided by
operations
|
1,007 | 572 | 1,851 | 1,500 |
(1)
|
Refer
to the Non-GAAP Measures section in this MD&A for further discussion
of funds generated from operations.
|
June
30, 2009
|
December
31, 2008
|
|||||||||
Asset/(Liability)
(unaudited)
(millions
of dollars)
|
Fair
Value(1)
|
Notional
or
Principal
Amount
|
Fair
Value(1)
|
Notional
or
Principal
Amount
|
||||||
U.S.
dollar cross-currency swaps
|
||||||||||
(maturing 2009 to 2014)(2)
|
(116 | ) |
U.S.
1,450
|
(218 | ) |
U.S.
1,650
|
||||
U.S.
dollar forward foreign exchange contracts
|
||||||||||
(maturing 2009)(2)
|
(3 | ) |
U.S.
100
|
(42 | ) |
U.S.
2,152
|
||||
U.S.
dollar options
|
||||||||||
(maturing 2009)(2)
|
(5 | ) |
U.S.
300
|
6 |
U.S.
300
|
|||||
(124 | ) |
U.S.
1,850
|
(254 | ) |
U.S.
4,102
|
(1)
|
Fair
values equal carrying values.
|
(2)
|
As
at June 30, 2009.
|
June
30, 2009
|
December
31, 2008
|
|||||||||||||||
(unaudited)
(millions
of dollars)
|
Carrying
Amount
|
Fair
Value
|
Carrying
Amount
|
Fair
Value
|
||||||||||||
Financial Assets(1)
|
||||||||||||||||
Cash
and cash equivalents
|
3,482 | 3,482 | 1,308 | 1,308 | ||||||||||||
Accounts
receivable and other assets(2)(3)
|
1,036 | 1,036 | 1,404 | 1,404 | ||||||||||||
Available-for-sale
assets(2)
|
23 | 23 | 27 | 27 | ||||||||||||
4,541 | 4,541 | 2,739 | 2,739 | |||||||||||||
Financial
Liabilities(1)(3)
|
||||||||||||||||
Notes
payable
|
1,041 | 1,041 | 1,702 | 1,702 | ||||||||||||
Accounts
payable and deferred amounts(4)
|
1,592 | 1,592 | 1,372 | 1,372 | ||||||||||||
Accrued
interest
|
415 | 415 | 359 | 359 | ||||||||||||
Long-term
debt and junior subordinated notes
|
19,266 | 21,174 | 17,367 | 16,152 | ||||||||||||
Long-term
debt of joint ventures
|
1,099 | 1,122 | 1,076 | 1,052 | ||||||||||||
23,413 | 25,344 | 21,876 | 20,637 |
(1)
|
Consolidated
Net Income in 2009 and 2008 included unrealized gains or losses of nil for
the fair value adjustments to each of these financial
instruments.
|
(2)
|
At
June 30, 2009, the Consolidated Balance Sheet included financial assets of
$889 million (December 31, 2008 – $1,257 million) in Accounts Receivable
and $170 million (December 31, 2008 - $174 million) in Other
Assets.
|
(3)
|
Recorded
at amortized cost.
|
(4)
|
At
June 30, 2009, the Consolidated Balance Sheet included financial
liabilities of $1,574 million (December 31, 2008 – $1,350 million) in
Accounts Payable and $18 million (December 31, 2008 - $22 million) in
Deferred Amounts.
|
June
30, 2009
|
||||||||||||||||||||
(unaudited)
(all
amounts in millions unless otherwise indicated)
|
Power
|
Natural
Gas
|
Oil
Products
|
Foreign
Exchange
|
Interest
|
|||||||||||||||
Derivative Financial
Instruments Held for Trading(1)
|
||||||||||||||||||||
Fair
Values(2)
|
||||||||||||||||||||
Assets
|
$ | 155 | $ | 174 | $ | 6 | $ | 16 | $ | 38 | ||||||||||
Liabilities
|
$ | (90 | ) | $ | (206 | ) | $ | (4 | ) | $ | (50 | ) | $ | (77 | ) | |||||
Notional
Values
|
||||||||||||||||||||
Volumes(3)
|
||||||||||||||||||||
Purchases
|
5,787 | 262 | 180 | - | - | |||||||||||||||
Sales
|
7,539 | 217 | 276 | - | - | |||||||||||||||
Canadian dollars
|
- | - | - | - | 899 | |||||||||||||||
U.S. dollars
|
- | - | - |
U.S.
469
|
U.S.
1,4755
|
|||||||||||||||
Japanese yen (in
billions)
|
- | - | - | - | - | |||||||||||||||
Cross-currency
|
- | - | - |
227/U.S.
157
|
- | |||||||||||||||
Net
unrealized (losses)/gains in the period(4)
|
||||||||||||||||||||
Three months ended June 30,
2009
|
$ | (2 | ) | $ | 10 | $ | (5 | ) | $ | 1 | $ | 27 | ||||||||
Six months ended June 30,
2009
|
$ | 19 | $ | (25 | ) | $ | 2 | $ | 2 | $ | 27 | |||||||||
Net
realized gains/(losses) in the period(4)
|
||||||||||||||||||||
Three months ended June 30,
2009
|
$ | 20 | $ | (39 | ) | $ | 2 | $ | 11 | $ | (5 | ) | ||||||||
Six months ended June 30,
2009
|
$ | 30 | $ | (13 | ) | $ | (1 | ) | $ | 17 | $ | (9 | ) | |||||||
Maturity
dates
|
2009-2014 | 2009-2014 | 2009-2010 | 2009-2012 | 2009-2018 | |||||||||||||||
Derivative Financial
Instruments in Hedging Relationships(5)(6)
|
||||||||||||||||||||
Fair
Values(2)
|
||||||||||||||||||||
Assets
|
$ | 213 | $ | 2 | - | - | $ | 6 | ||||||||||||
Liabilities
|
$ | (173 | ) | $ | (25 | ) | - | $ | (28 | ) | $ | (64 | ) | |||||||
Notional
Values
|
||||||||||||||||||||
Volumes(3)
|
||||||||||||||||||||
Purchases
|
13,159 | 22 | - | - | - | |||||||||||||||
Sales
|
14,520 | - | - | - | - | |||||||||||||||
Canadian dollars
|
- | - | - | - | - | |||||||||||||||
U.S. dollars
|
- | - | - | - | 1,325 | |||||||||||||||
Cross-currency
|
- | - | - |
136/U.S.
100
|
- | |||||||||||||||
Net
realized gains/(losses) in the period(4)
|
||||||||||||||||||||
Three months ended June 30,
2009
|
$ | 52 | $ | (10 | ) | - | - | $ | (10 | ) | ||||||||||
Six months ended June 30,
2009
|
$ | 78 | $ | (20 | ) | - | - | $ | (17 | ) | ||||||||||
Maturity
dates
|
2009-2015 | 2009-2012 | n/a | 2009-2013 | 2010-2013 |
(1)
|
All
derivative financial instruments in the held-for-trading classification
have been entered into for risk management purposes and are subject to the
Company’s risk management strategies, policies and limits. These include
derivatives that have not been designated as hedges or do not qualify for
hedge accounting treatment but have been entered into as economic hedges
to manage the Company’s exposures to market
risk.
|
(2)
|
Fair
values equal carrying values.
|
(3)
|
Volumes
for power, natural gas and oil products derivatives are in GWh, Bcf and
thousands of barrels, respectively.
|
(4)
|
Realized
and unrealized gains and losses on power, natural gas and oil products
derivative financial instruments held for trading are included in
Revenues. Realized and unrealized gains and losses on interest rate and
foreign exchange derivative financial instruments held for trading are
included in Interest Expense and Interest Income and Other, respectively.
The effective portion of unrealized gains and losses on derivative
financial instruments in hedging relationships are initially recognized in
Other Comprehensive Income, and are reclassified to Revenues, Interest
Expense
and Interest Income and Other, as appropriate, as the original hedged item
settles.
|
(5)
|
All
hedging relationships are designated as cash flow hedges except for
interest-rate derivative financial instruments designated as fair value
hedges with a fair value of $4 million and a notional amount of US$150
million. Net realized gains on fair value hedges for the three and six
months ended June 30, 2009 were $1 million and $2 million, respectively,
and were included in Interest Expense. In second quarter 2009, the Company
did not record any amounts in Net Income related to ineffectiveness for
fair value hedges.
|
(6)
|
Net
Income for the three and six months ended June 30, 2009 included losses of
$4 million and gains of $1 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 six
months ended June 30, 2009 for discontinued cash flow hedges. No amounts
have been excluded from the assessment of hedge
effectiveness.
|
2008
|
||||||||||||||||||||
(unaudited)
(all
amounts in millions unless otherwise indicated)
|
Power
|
Natural
Gas
|
Oil
Products
|
Foreign
Exchange
|
Interest
|
|||||||||||||||
Derivative
Financial Instruments Held for Trading
|
||||||||||||||||||||
Fair
Values(1)(4)
|
||||||||||||||||||||
Assets
|
$ | 132 | $ | 144 | $ | 10 | $ | 41 | $ | 57 | ||||||||||
Liabilities
|
$ | (82 | ) | $ | (150 | ) | $ | (10 | ) | $ | (55 | ) | $ | (117 | ) | |||||
Notional
Values(4)
|
||||||||||||||||||||
Volumes(2)
|
||||||||||||||||||||
Purchases
|
4,035 | 172 | 410 | - | - | |||||||||||||||
Sales
|
5,491 | 162 | 252 | - | - | |||||||||||||||
Canadian dollars
|
- | - | - | - | 1,016 | |||||||||||||||
U.S. dollars
|
- | - | - |
U.S.
479
|
U.S.
1,575
|
|||||||||||||||
Japanese Yen (in
billions)
|
- | - | - |
JPY
4.3
|
- | |||||||||||||||
Cross-currency
|
- | - | - |
227/U.S.
157
|
- | |||||||||||||||
Net
unrealized (losses)/gains in the period(3)
|
||||||||||||||||||||
Three months ended June 30,
2008
|
$ | (2 | ) | $ | 7 | - | $ | 2 | $ | 2 | ||||||||||
Six months ended June 30,
2008
|
$ | (5 | ) | $ | (11 | ) | - | $ | (7 | ) | $ | (2 | ) | |||||||
Net
realized gains/(losses) in the period(3)
|
||||||||||||||||||||
Three months ended June 30,
2008
|
$ | 8 | $ | (20 | ) | - | $ | 5 | $ | 7 | ||||||||||
Six months ended June 30,
2008
|
$ | 9 | $ | 5 | - | $ | 10 | $ | 10 | |||||||||||
Maturity
dates(4)
|
2009-2014 | 2009-2011 |
2009
|
2009-2012 | 2009-2018 | |||||||||||||||
Derivative Financial
Instruments in Hedging Relationships(5)(6)
|
||||||||||||||||||||
Fair
Values(1)(4)
|
||||||||||||||||||||
Assets
|
$ | 115 | - | - | $ | 2 | $ | 8 | ||||||||||||
Liabilities
|
$ | (160 | ) | $ | (18 | ) | - | $ | (24 | ) | $ | (122 | ) | |||||||
Notional
Values (4)
|
||||||||||||||||||||
Volumes(2)
|
||||||||||||||||||||
Purchases
|
8,926 | 9 | - | - | - | |||||||||||||||
Sales
|
13,113 | - | - | - | - | |||||||||||||||
Canadian dollars
|
- | - | - | - | 50 | |||||||||||||||
U.S. dollars
|
- | - | - |
U.S.
15
|
U.S.
1,475
|
|||||||||||||||
Cross-currency
|
- | - | - |
136/U.S.
100
|
- | |||||||||||||||
Net
realized (losses)/gains in the period(3)
|
||||||||||||||||||||
Three months ended June 30,
2008
|
$ | (37 | ) | $ | 11 | - | - | $ | (3 | ) | ||||||||||
Six months ended June 30,
2008
|
$ | (38 | ) | $ | 19 | - | - | $ | (2 | ) | ||||||||||
Maturity
dates(4)
|
2009-2014 | 2009-2011 | n/a | 2009-2013 | 2009-2019 |
(1)
|
Fair
values equal carrying values.
|
(2)
|
Volumes
for power, natural gas and oil products derivatives are in GWh, Bcf and
thousands of barrels, respectively.
|
(3)
|
Realized
and unrealized gains and losses on power, natural gas and oil products
derivative financial instruments held for trading are included in
Revenues. Realized and unrealized gains and losses on interest rate and
foreign exchange derivative
financial instruments held for trading are included in Interest Expense
and Interest Income and Other, respectively. The effective portion of
unrealized gains and losses on derivative financial instruments in hedging
relationships are initially recognized in Other Comprehensive Income, and
are reclassified to Revenues, Interest Expense and Interest Income and
Other, as appropriate, as the original hedged item
settles.
|
(4)
|
As
at December 31, 2008.
|
(5)
|
All
hedging relationships are designated as cash flow hedges except for
interest-rate derivative financial instruments designated as fair value
hedges with a fair value of $8 million and notional amounts of $50 million
and US$50 million at December 31, 2008. There were no net realized gains
or losses on fair value hedges for the three and six months ended June 30,
2008. In second quarter 2008, the Company did not record any amounts in
Net Income related to ineffectiveness for fair value
hedges.
|
(6)
|
Net
Income for the three and six months ended June 30, 2008 included losses of
$5 million and $3 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 six months
ended June 30, 2008 for discontinued cash flow hedges. No amounts have
been excluded from the assessment of hedge
effectiveness.
|
(unaudited)
|
||||||
(millions
of dollars)
|
June
30, 2009
|
December
31, 2008
|
||||
Current
|
||||||
Other current
assets
|
445
|
318
|
||||
Accounts
payable
|
(445
|
)
|
(298
|
)
|
||
Long-term
|
||||||
Other assets
|
165
|
191
|
||||
Deferred
amounts
|
(396
|
)
|
(694
|
)
|
(unaudited)
|
2009
|
2008
|
2007
|
|||||||||||||||||||||||||||||
(millions
of dollars except per share amounts)
|
Second
|
First
|
Fourth
|
Third
|
Second
|
First
|
Fourth
|
Third
|
||||||||||||||||||||||||
Revenues
|
2,127 | 2,380 | 2,332 | 2,137 | 2,017 | 2,133 | 2,189 | 2,187 | ||||||||||||||||||||||||
Net
Income
|
314 | 334 | 277 | 390 | 324 | 449 | 377 | 324 | ||||||||||||||||||||||||
Share
Statistics
|
||||||||||||||||||||||||||||||||
Net
income per share – Basic
|
$ | 0.50 | $ | 0.54 | $ | 0.47 | $ | 0.67 | $ | 0.58 | $ | 0.83 | $ | 0.70 | $ | 0.60 | ||||||||||||||||
Net
income per share – Diluted
|
$ | 0.50 | $ | 0.54 | $ | 0.46 | $ | 0.67 | $ | 0.58 | $ | 0.83 | $ | 0.70 | $ | 0.60 | ||||||||||||||||
Dividend
declared per common share
|
$ | 0.38 | $ | 0.38 | $ | 0.36 | $ | 0.36 | $ | 0.36 | $ | 0.36 | $ | 0.34 | $ | 0.34 |
(1)
|
The
selected quarterly consolidated financial data has been prepared in
accordance with Canadian GAAP. Certain comparative figures have been
reclassified to conform with the current year’s
presentation.
|
•
|
Second
quarter 2009, Energy’s EBIT included net unrealized losses of $7 million
pre-tax ($5 million after tax) due to changes in the fair value of
proprietary natural gas storage inventory and natural gas forward purchase
and sale contracts. Energy’s EBIT also included contributions from
Portlands Energy, which was placed in service in April
2009.
|
•
|
First
quarter 2009, Energy’s EBIT included net unrealized losses of $13 million
pre-tax ($9 million after tax) due to changes in the fair value of
proprietary natural gas storage inventory and natural gas forward purchase
and sale contracts.
|
•
|
Fourth
quarter 2008, Energy’s EBIT included net unrealized gains of $7 million
pre-tax ($6 million after tax) due to changes in the fair value of
proprietary natural gas storage inventory and natural gas forward purchase
and sale contracts. Corporate’s EBIT included net unrealized losses of $57
million pre-tax ($39 million after tax) for changes in the fair value of
derivatives used to manage the Company’s exposure to rising interest rates
but which do not qualify as hedges for accounting
purposes.
|
•
|
Third
quarter 2008, Energy’s EBIT included contributions from the August 26,
2008 acquisition of Ravenswood. Net Income included favourable income tax
adjustments of $26 million from an internal restructuring and realization
of losses.
|
•
|
First
quarter 2008, Pipelines’ EBIT included $279 million pre-tax ($152 million
after tax) from the Calpine bankruptcy settlements received by GTN and
Portland, and proceeds of $17 million pre-tax ($10 million after tax) from
a lawsuit settlement. Energy’s EBIT included a writedown of $41 million
pre-tax ($27 million after tax) of costs related to the Broadwater LNG
project and net unrealized losses of $17 million pre-tax ($12 million
after tax) due to changes in the fair value of proprietary natural gas
storage inventory and natural gas forward purchase and sale
contracts.
|
•
|
Fourth
quarter 2007, Net Income included $56 million of favourable income tax
adjustments resulting from reductions in Canadian federal income tax rates
and other legislative changes. Energy’s EBIT increased due to a $16
million pre-tax ($14 million after tax) gain on sale of land previously
held for development. Pipelines’ EBIT increased as a result of recording
incremental earnings related to a rate case settlement reached for the GTN
System, effective January 1, 2007. Energy’s EBIT included net unrealized
gains of $15 million pre-tax ($10 million after tax) due to changes in the
fair value of proprietary natural gas storage inventory and natural gas
forward purchase and sale
contracts.
|
•
|
Third
quarter 2007, Net Income included $15 million of favourable income tax
reassessments and associated interest income relating to prior
years.
|
(unaudited)
|
Three
months ended June 30
|
Six
months ended June 30
|
||||||||||||||
(millions
of dollars except per share amounts)
|
2009
|
2008
|
2009
|
2008
|
||||||||||||
Revenues
|
2,127 | 2,017 | 4,507 | 4,150 | ||||||||||||
Operating
and Other Expenses/(Income)
|
||||||||||||||||
Plant
operating costs and other
|
828 | 733 | 1,665 | 1,431 | ||||||||||||
Commodity
purchases resold
|
299 | 333 | 729 | 729 | ||||||||||||
Other
income
|
(10 | ) | (9 | ) | (15 | ) | (37 | ) | ||||||||
Calpine
bankruptcy settlements
|
- | - | - | (279 | ) | |||||||||||
Writedown
of Broadwater LNG project costs
|
- | - | - | 41 | ||||||||||||
1,117 | 1,057 | 2,379 | 1,885 | |||||||||||||
1,010 | 960 | 2,128 | 2,265 | |||||||||||||
Depreciation
and amortization
|
345 | 315 | 691 | 625 | ||||||||||||
665 | 645 | 1,437 | 1,640 | |||||||||||||
Financial
Charges/(Income)
|
||||||||||||||||
Interest
expense
|
259 | 186 | 554 | 404 | ||||||||||||
Financial
charges of joint ventures
|
16 | 17 | 30 | 33 | ||||||||||||
Interest
income and other
|
(34 | ) | (25 | ) | (56 | ) | (36 | ) | ||||||||
241 | 178 | 528 | 401 | |||||||||||||
Income
before Income Taxes and Non-Controlling Interests
|
424 | 467 | 909 | 1,239 | ||||||||||||
Income
Taxes
|
||||||||||||||||
Current
|
35 | 105 | 89 | 352 | ||||||||||||
Future
|
62 | 21 | 124 | 26 | ||||||||||||
97 | 126 | 213 | 378 | |||||||||||||
Non-Controlling
Interests
|
||||||||||||||||
Preferred
share dividends of subsidiary
|
5 | 5 | 11 | 11 | ||||||||||||
Non-controlling
interest in PipeLines LP
|
8 | 13 | 32 | 34 | ||||||||||||
Non-controlling
interest in Portland
|
- | (1 | ) | 5 | 43 | |||||||||||
13 | 17 | 48 | 88 | |||||||||||||
Net
Income
|
314 | 324 | 648 | 773 | ||||||||||||
Net
Income Per Share - Basic and Diluted
|
$ | 0.50 | $ | 0.58 | $ | 1.04 | $ | 1.40 | ||||||||
Average Shares Outstanding –
Basic (millions)
|
624 | 561 | 621 | 551 | ||||||||||||
Average Shares Outstanding –
Diluted (millions)
|
625 | 563 | 622 | 553 |
Three
months ended June 30
|
Six
months ended June 30
|
|||||||||||||||
(unaudited)(millions
of dollars)
|
2009
|
2008
|
2009
|
2008
|
||||||||||||
Cash
Generated From Operations
|
||||||||||||||||
Net
income
|
314 | 324 | 648 | 773 | ||||||||||||
Depreciation
and amortization
|
345 | 315 | 691 | 625 | ||||||||||||
Future
income taxes
|
62 | 21 | 124 | 26 | ||||||||||||
Non-controlling
interests
|
13 | 17 | 48 | 88 | ||||||||||||
Employee
future benefits funding (in excess of)/lower than expense
|
(23 | ) | (7 | ) | (57 | ) | 13 | |||||||||
Writedown
of Broadwater LNG project costs
|
- | - | - | 41 | ||||||||||||
Other
|
(19 | ) | 6 | 4 | 32 | |||||||||||
692 | 676 | 1,458 | 1,598 | |||||||||||||
Decrease/(increase)
in operating working capital
|
315 | (104 | ) | 393 | (98 | ) | ||||||||||
Net
cash provided by operations
|
1,007 | 572 | 1,851 | 1,500 | ||||||||||||
Investing
Activities
|
||||||||||||||||
Capital
expenditures
|
(1,263 | ) | (633 | ) | (2,386 | ) | (1,093 | ) | ||||||||
Acquisitions,
net of cash acquired
|
(115 | ) | (2 | ) | (249 | ) | (4 | ) | ||||||||
Deferred
amounts and other
|
(168 | ) | (13 | ) | (339 | ) | 99 | |||||||||
Net
cash used in investing activities
|
(1,546 | ) | (648 | ) | (2,974 | ) | (998 | ) | ||||||||
Financing
Activities
|
||||||||||||||||
Dividends
on common shares
|
(193 | ) | (137 | ) | (349 | ) | (267 | ) | ||||||||
Distributions
paid to non-controlling interests
|
(24 | ) | (65 | ) | (51 | ) | (86 | ) | ||||||||
Notes
payable issued/(repaid), net
|
233 | 754 | (684 | ) | 724 | |||||||||||
Long-term
debt issued, net of issue costs
|
- | - | 3,060 | 112 | ||||||||||||
Reduction
of long-term debt
|
(18 | ) | (379 | ) | (500 | ) | (773 | ) | ||||||||
Long-term
debt of joint ventures issued
|
92 | 17 | 108 | 34 | ||||||||||||
Reduction
of long-term debt of joint ventures
|
(33 | ) | (28 | ) | (56 | ) | (57 | ) | ||||||||
Common
shares issued, net of issue costs
|
1,792 | 1,237 | 1,803 | 1,246 | ||||||||||||
Net
cash provided by financing activities
|
1,849 | 1,399 | 3,331 | 933 | ||||||||||||
Effect
of Foreign Exchange Rate Changes on Cash and Cash
Equivalents
|
(60 | ) | (3 | ) | (34 | ) | 20 | |||||||||
Increase
in Cash and Cash Equivalents
|
1,250 | 1,320 | 2,174 | 1,455 | ||||||||||||
Cash
and Cash Equivalents
|
||||||||||||||||
Beginning
of period
|
2,232 | 639 | 1,308 | 504 | ||||||||||||
Cash
and Cash Equivalents
|
||||||||||||||||
End
of period
|
3,482 | 1,959 | 3,482 | 1,959 | ||||||||||||
Supplementary
Cash Flow Information
|
||||||||||||||||
Income
taxes paid
|
56 | 312 | 113 | 479 | ||||||||||||
Interest
paid
|
274 | 277 | 537 | 481 |
June
30,
|
December
31,
|
||||
(unaudited)(millions
of dollars)
|
2009
|
2008
|
|||
ASSETS
|
|||||
Current
Assets
|
|||||
Cash
and cash equivalents
|
3,482
|
1,308
|
|||
Accounts
receivable
|
889
|
1,280
|
|||
Inventories
|
488
|
489
|
|||
Other
|
858
|
523
|
|||
5,717
|
3,600
|
||||
Plant,
Property and Equipment
|
30,587
|
29,189
|
|||
Goodwill
|
4,169
|
4,397
|
|||
Regulatory
Assets
|
1,594
|
201
|
|||
Other
Assets
|
2,206
|
2,027
|
|||
44,273
|
39,414
|
||||
LIABILITIES
AND SHAREHOLDERS’ EQUITY
|
|||||
Current
Liabilities
|
|||||
Notes
payable
|
1,041
|
1,702
|
|||
Accounts
payable
|
2,298
|
1,876
|
|||
Accrued
interest
|
415
|
359
|
|||
Current
portion of long-term debt
|
570
|
786
|
|||
Current
portion of long-term debt of joint ventures
|
303
|
207
|
|||
4,627
|
4,930
|
||||
Regulatory
Liabilities
|
490
|
551
|
|||
Deferred
Amounts
|
860
|
1,168
|
|||
Future
Income Taxes
|
2,682
|
1,223
|
|||
Long-Term
Debt
|
17,545
|
15,368
|
|||
Long-Term
Debt of Joint Ventures
|
796
|
869
|
|||
Junior
Subordinated Notes
|
1,151
|
1,213
|
|||
28,151
|
25,322
|
||||
Non-Controlling
Interests
|
|||||
Non-controlling
interest in PipeLines LP
|
679
|
721
|
|||
Preferred
shares of subsidiary
|
389
|
389
|
|||
Non-controlling
interest in Portland
|
85
|
84
|
|||
1,153
|
1,194
|
||||
Shareholders’
Equity
|
14,969
|
12,898
|
|||
44,273
|
39,414
|
Three
months ended June 30
|
Six
months ended June 30
|
|||||||||
(unaudited)(millions
of dollars)
|
2009
|
2008
|
2009
|
2008
|
||||||
Net
Income
|
314
|
324
|
648
|
773
|
||||||
Other
Comprehensive Income/(Loss), Net of Income
Taxes
|
||||||||||
Change in foreign
currency translation gains and losses
on
investments in
foreign operations(1)
|
(113
|
)
|
(14
|
)
|
(151
|
)
|
39
|
|||
Change in gains and
losses on hedges of investments
in foreign
operations(2)
|
96
|
17
|
96
|
(24
|
)
|
|||||
Change in gains and
losses on derivative instruments
designated as
cash flow
hedges(3)
|
37
|
29
|
64
|
33
|
||||||
Reclassification to
net income of gains and losses on
derivative
instruments
designated as cash flow hedges pertaining
to prior
periods(4)
|
(9
|
)
|
1
|
(5
|
)
|
(18
|
)
|
|||
Other Comprehensive
Income/(Loss)
|
11
|
33
|
4
|
30
|
||||||
Comprehensive
Income
|
325
|
357
|
652
|
803
|
(1)
|
Net
of income tax expense of $6 million and nil for the three and six months
ended June 30, 2009, respectively (2008 - $5 million expense and $20
million recovery, respectively).
|
(2)
|
Net
of income tax expense of $48 million and $52 million for the three and six
months ended June 30, 2009, respectively (2008 - $8 million expense and
$14 million recovery,
respectively).
|
(3)
|
Net
of income tax expense of $19 million and $16 million for the three and six
months ended June 30, 2009, respectively (2008 – expense of $37 million
and $49 million, respectively).
|
(4)
|
Net
of income tax recovery of $1 million and nil for the three and six months
ended June 30, 2009, respectively (2008 – recovery of $2 million and $11
million, respectively).
|
Currency
|
Cash
Flow
|
|||||||||||
Translation
|
Hedges
and
|
|||||||||||
(unaudited)(millions
of dollars)
|
Adjustments
|
Other
|
Total
|
|||||||||
Balance
at December 31, 2008
|
(379 | ) | (93 | ) | (472 | ) | ||||||
Change
in foreign currency translation gains and losses on investments in
foreign
operations(1)
|
(151 | ) | - | (151 | ) | |||||||
Change
in gains and losses on hedges of investments in foreign operations(2)
|
96 | - | 96 | |||||||||
Changes
in gains and losses on derivative instruments designated as cash flow
hedges(3)
|
- | 64 | 64 | |||||||||
Reclassification
to net income of gains and losses on derivative instruments designated
as
cash flow hedges
pertaining to prior periods(4)(5)
|
- | (5 | ) | (5 | ) | |||||||
Balance
at June 30, 2009
|
(434 | ) | (34 | ) | (468 | ) | ||||||
Balance
at December 31, 2007
|
(361 | ) | (12 | ) | (373 | ) | ||||||
Change
in foreign currency translation gains and losses on investments
in
foreign
operations(1)
|
39 | - | 39 | |||||||||
Change
in gains and losses on hedges of investments in foreign operations(2)
|
(24 | ) | - | (24 | ) | |||||||
Changes
in gains and losses on derivative instruments designated as cash flow
hedges(3)
|
- | 33 | 33 | |||||||||
Reclassification
to net income of gains and losses on derivative instruments designated
as
cash flow hedges
pertaining to prior periods(4)
|
- | (18 | ) | (18 | ) | |||||||
Balance
at June 30, 2008
|
(346 | ) | 3 | (343 | ) |
(1)
|
Net
of income tax of nil for the six months ended June 30, 2009 (2008 - $20
million recovery).
|
(2)
|
Net
of income tax expense of $52 million for the six months ended June 30,
2009 (2008 - $14 million recovery).
|
(3)
|
Net
of income tax expense of $16 million for the six months ended June 30,
2009 (2008 - $49 million expense).
|
(4)
|
Net
of income tax of nil for the six months ended June 30, 2009 (2008 - $11
million recovery).
|
(5)
|
The
amount of gains related to cash flow hedges reported in accumulated other
comprehensive income that is expected to be reclassified to net income in
the next 12 months is estimated to be $4 million ($10 million, net of
tax). These estimates assume constant commodity prices, interest rates and
foreign exchange rates over time, however, the amounts reclassified will
vary based on the actual value of these factors at the date of
settlement.
|
Six
months ended June 30
|
||||||
(unaudited)(millions
of dollars)
|
2009
|
2008
|
||||
Common
Shares
|
||||||
Balance at beginning of
period
|
9,264
|
6,662
|
||||
Shares issued under dividend
reinvestment plan
|
109
|
112
|
||||
Proceeds from shares issued on
exercise of stock options
|
11
|
11
|
||||
Proceeds from shares issued
under public offering, net of issue costs
|
1,792
|
1,235
|
||||
Balance at end of
period
|
11,176
|
8,020
|
||||
Contributed
Surplus
|
||||||
Balance at beginning of
period
|
279
|
276
|
||||
Issuance of stock
options
|
1
|
2
|
||||
Balance at end of
period
|
280
|
278
|
||||
Retained
Earnings
|
||||||
Balance at beginning of
period
|
3,827
|
3,220
|
||||
Net income
|
648
|
773
|
||||
Common share
dividends
|
(494
|
)
|
(403
|
)
|
||
Balance at end of
period
|
3,981
|
3,590
|
||||
Accumulated
Other Comprehensive Income
|
||||||
Balance at beginning of
period
|
(472
|
)
|
(373
|
)
|
||
Other comprehensive
income
|
4
|
30
|
||||
Balance at end of
period
|
(468
|
)
|
(343
|
)
|
||
3,513
|
3,247
|
|||||
Total
Shareholders’ Equity
|
14,969
|
11,545
|
1.
|
Significant
Accounting Policies
|
2.
|
Changes
in Accounting Policies
|
3. | Segmented Information |
Three
months ended June 30
|
Pipelines
|
Energy
|
Corporate
|
Total
|
||||||||||||||||||||||||||||
(unaudited)(millions
of dollars)
|
2009
|
2008
|
2009
|
2008
|
2009
|
2008
|
2009
|
2008
|
||||||||||||||||||||||||
Revenues
|
1,142 | 1,100 | 985 | 917 | - | - | 2,127 | 2,017 | ||||||||||||||||||||||||
Plant
operating costs and other
|
(403 | ) | (393 | ) | (394 | ) | (313 | ) | (31 | ) | (27 | ) | (828 | ) | (733 | ) | ||||||||||||||||
Commodity
purchases resold
|
- | - | (299 | ) | (333 | ) | - | - | (299 | ) | (333 | ) | ||||||||||||||||||||
Other
income
|
8 | 7 | 2 | 1 | - | 1 | 10 | 9 | ||||||||||||||||||||||||
747 | 714 | 294 | 272 | (31 | ) | (26 | ) | 1,010 | 960 | |||||||||||||||||||||||
Depreciation
and amortization
|
(258 | ) | (257 | ) | (87 | ) | (58 | ) | - | - | (345 | ) | (315 | ) | ||||||||||||||||||
489 | 457 | 207 | 214 | (31 | ) | (26 | ) | 665 | 645 | |||||||||||||||||||||||
Interest
expense
|
(259 | ) | (186 | ) | ||||||||||||||||||||||||||||
Financial
charges of joint ventures
|
(16 | ) | (17 | ) | ||||||||||||||||||||||||||||
Interest
income and other
|
34 | 25 | ||||||||||||||||||||||||||||||
Income
taxes
|
(97 | ) | (126 | ) | ||||||||||||||||||||||||||||
Non-controlling
interests
|
(13 | ) | (17 | ) | ||||||||||||||||||||||||||||
Net
Income
|
314 | 324 |
Six
months ended June 30
|
Pipelines
|
Energy
|
Corporate
|
Total
|
||||||||||||||||||||||||||||
(unaudited)(millions
of dollars)
|
2009
|
2008
|
2009
|
2008
|
2009
|
2008
|
2009
|
2008
|
||||||||||||||||||||||||
Revenues
|
2,406 | 2,276 | 2,101 | 1,874 | - | - | 4,507 | 4,150 | ||||||||||||||||||||||||
Plant
operating costs and other
|
(800 | ) | (773 | ) | (803 | ) | (604 | ) | (62 | ) | (54 | ) | (1,665 | ) | (1,431 | ) | ||||||||||||||||
Commodity
purchases resold
|
- | - | (729 | ) | (729 | ) | - | - | (729 | ) | (729 | ) | ||||||||||||||||||||
Other
income
|
12 | 30 | 2 | 1 | 1 | 6 | 15 | 37 | ||||||||||||||||||||||||
Calpine
bankruptcy settlements
|
- | 279 | - | - | - | - | - | 279 | ||||||||||||||||||||||||
Writedown
of Broadwater LNG project costs
|
- | - | - | (41 | ) | - | - | - | (41 | ) | ||||||||||||||||||||||
1,618 | 1,812 | 571 | 501 | (61 | ) | (48 | ) | 2,128 | 2,265 | |||||||||||||||||||||||
Depreciation
and amortization
|
(518 | ) | (511 | ) | (173 | ) | (114 | ) | - | - | (691 | ) | (625 | ) | ||||||||||||||||||
1,100 | 1,301 | 398 | 387 | (61 | ) | (48 | ) | 1,437 | 1,640 | |||||||||||||||||||||||
Interest
expense
|
(554 | ) | (404 | ) | ||||||||||||||||||||||||||||
Financial
charges of joint ventures
|
(30 | ) | (33 | ) | ||||||||||||||||||||||||||||
Interest
income and other
|
56 | 36 | ||||||||||||||||||||||||||||||
Income
taxes
|
(213 | ) | (378 | ) | ||||||||||||||||||||||||||||
Non-controlling
interests
|
(48 | ) | (88 | ) | ||||||||||||||||||||||||||||
Net
Income
|
648 | 773 |
For
the year ended December 31
|
Pipelines
|
Energy
|
Corporate
|
Total
|
||||||||||||||||||||||||||||
(unaudited)(millions
of dollars)
|
2008
|
2007
|
2008
|
2007
|
2008
|
2007
|
2008
|
2007
|
||||||||||||||||||||||||
Revenues
|
4,650 | 4,712 | 3,969 | 4,116 | - | - | 8,619 | 8,828 | ||||||||||||||||||||||||
Plant
operating costs and other
|
(1,645 | ) | (1,590 | ) | (1,307 | ) | (1,336 | ) | (110 | ) | (104 | ) | (3,062 | ) | (3,030 | ) | ||||||||||||||||
Commodity
purchases resold
|
- | (72 | ) | (1,453 | ) | (1,829 | ) | - | - | (1,453 | ) | (1,901 | ) | |||||||||||||||||||
Calpine
bankruptcy settlements
|
279 | - | - | 16 | - | - | 279 | 16 | ||||||||||||||||||||||||
Writedown
of Broadwater LNG project costs
|
- | - | (41 | ) | - | - | - | (41 | ) | - | ||||||||||||||||||||||
Other
income
|
31 | 27 | 1 | 3 | 6 | 2 | 38 | 32 | ||||||||||||||||||||||||
3,315 | 3,077 | 1,169 | 970 | (104 | ) | (102 | ) | 4,380 | 3,945 | |||||||||||||||||||||||
Depreciation
and amortization
|
(989 | ) | (1,021 | ) | (258 | ) | (216 | ) | - | - | (1,247 | ) | (1,237 | ) | ||||||||||||||||||
2,326 | 2,056 | 911 | 754 | (104 | ) | (102 | ) | 3,133 | 2,708 | |||||||||||||||||||||||
Interest
expense
|
(943 | ) | (943 | ) | ||||||||||||||||||||||||||||
Financial
charges of joint ventures
|
(72 | ) | (75 | ) | ||||||||||||||||||||||||||||
Interest
income and other
|
54 | 120 | ||||||||||||||||||||||||||||||
Income
taxes
|
(602 | ) | (490 | ) | ||||||||||||||||||||||||||||
Non-controlling
interests
|
(130 | ) | (97 | ) | ||||||||||||||||||||||||||||
Net
Income
|
1,440 | 1,223 |
(unaudited)(millions
of dollars)
|
June
30, 2009
|
December
31, 2008
|
|||
Pipelines
|
27,813
|
25,020
|
|||
Energy
|
12,259
|
12,006
|
|||
Corporate
|
4,201
|
2,388
|
|||
44,273
|
39,414
|
4.
|
Long-Term
Debt
|
5.
|
Share
Capital
|
6.
|
Financial
Instruments and Risk Management
|
June
30, 2009
|
December
31, 2008
|
|||||||||
Asset/(Liability)
(unaudited)
(millions
of dollars)
|
Fair
Value(1)
|
Notional
or
Principal
Amount
|
Fair
Value(1)
|
Notional
or
Principal
Amount
|
||||||
U.S.
dollar cross-currency swaps
|
||||||||||
(maturing 2009 to 2014)(2)
|
(116 | ) |
U.S.
1,450
|
(218 | ) |
U.S.
1,650
|
||||
U.S.
dollar forward foreign exchange contracts
|
||||||||||
(maturing 2009)(2)
|
(3 | ) |
U.S.
100
|
(42 | ) |
U.S.
2,152
|
||||
U.S.
dollar options
|
||||||||||
(maturing 2009)(2)
|
(5 | ) |
U.S.
300
|
6 |
U.S.
300
|
|||||
(124 | ) |
U.S.
1,850
|
(254 | ) |
U.S.
4,102
|
(1)
|
Fair
values equal carrying values.
|
(2)
|
As
at June 30, 2009.
|
Non-Derivative Financial
Instruments Summary
|
June
30, 2009
|
December
31, 2008
|
|||||||||||||||
(unaudited)
(millions
of dollars)
|
Carrying
Amount
|
Fair
Value
|
Carrying
Amount
|
Fair
Value
|
||||||||||||
Financial Assets(1)
|
||||||||||||||||
Cash
and cash equivalents
|
3,482 | 3,482 | 1,308 | 1,308 | ||||||||||||
Accounts
receivable and other assets(2)(3)
|
1,036 | 1,036 | 1,404 | 1,404 | ||||||||||||
Available-for-sale
assets(2)
|
23 | 23 | 27 | 27 | ||||||||||||
4,541 | 4,541 | 2,739 | 2,739 | |||||||||||||
Financial
Liabilities(1)(3)
|
||||||||||||||||
Notes
payable
|
1,041 | 1,041 | 1,702 | 1,702 | ||||||||||||
Accounts
payable and deferred amounts(4)
|
1,592 | 1,592 | 1,372 | 1,372 | ||||||||||||
Accrued
interest
|
415 | 415 | 359 | 359 | ||||||||||||
Long-term
debt and junior subordinated notes
|
19,266 | 21,174 | 17,367 | 16,152 | ||||||||||||
Long-term
debt of joint ventures
|
1,099 | 1,122 | 1,076 | 1,052 | ||||||||||||
23,413 | 25,344 | 21,876 | 20,637 |
(1)
|
Consolidated
Net Income in 2009 and 2008 included unrealized gains or losses of nil for
the fair value adjustments to each of these financial
instruments.
|
(2)
|
At
June 30, 2009, the Consolidated Balance Sheet included financial assets of
$889 million (December 31, 2008 – $1,257 million) in Accounts Receivable
and $170 million (December 31, 2008 - $174 million) in Other
Assets.
|
(3)
|
Recorded
at amortized cost.
|
(4)
|
At
June 30, 2009, the Consolidated Balance Sheet included financial
liabilities of $1,574 million (December 31, 2008 – $1,350 million) in
Accounts Payable and $18 million (December 31, 2008 - $22 million) in
Deferred Amounts.
|
Derivative Financial
Instruments Summary
|
June
30, 2009
|
||||||||||||||||||||
(unaudited)
(all
amounts in millions unless otherwise indicated)
|
Power
|
Natural
Gas
|
Oil
Products
|
Foreign
Exchange
|
Interest
|
|||||||||||||||
Derivative Financial
Instruments Held for Trading(1)
|
||||||||||||||||||||
Fair
Values(2)
|
||||||||||||||||||||
Assets
|
$ | 155 | $ | 174 | $ | 6 | $ | 16 | $ | 38 | ||||||||||
Liabilities
|
$ | (90 | ) | $ | (206 | ) | $ | (4 | ) | $ | (50 | ) | $ | (77 | ) | |||||
Notional
Values
|
||||||||||||||||||||
Volumes(3)
|
||||||||||||||||||||
Purchases
|
5,787 | 262 | 180 | - | - | |||||||||||||||
Sales
|
7,539 | 217 | 276 | - | - | |||||||||||||||
Canadian dollars
|
- | - | - | - | 899 | |||||||||||||||
U.S. dollars
|
- | - | - |
U.S.
469
|
U.S.
1,475
|
|||||||||||||||
Japanese yen (in
billions)
|
- | - | - | - | - | |||||||||||||||
Cross-currency
|
- | - | - |
227/U.S.
157
|
- | |||||||||||||||
Net
unrealized (losses)/gains in the period(4)
|
||||||||||||||||||||
Three months ended June 30,
2009
|
$ | (2 | ) | $ | 10 | $ | (5 | ) | $ | 1 | $ | 27 | ||||||||
Six months ended June 30,
2009
|
$ | 19 | $ | (25 | ) | $ | 2 | $ | 2 | $ | 27 | |||||||||
Net
realized gains/(losses) in the period(4)
|
||||||||||||||||||||
Three months ended June 30,
2009
|
$ | 20 | $ | (39 | ) | $ | 2 | $ | 11 | $ | (5 | ) | ||||||||
Six months ended June 30,
2009
|
$ | 30 | $ | (13 | ) | $ | (1 | ) | $ | 17 | $ | (9 | ) | |||||||
Maturity
dates
|
2009-2014 | 2009-2014 | 2009-2010 | 2009-2012 | 2009-2018 | |||||||||||||||
Derivative Financial
Instruments in Hedging Relationships(5)(6)
|
||||||||||||||||||||
Fair
Values(2)
|
||||||||||||||||||||
Assets
|
$ | 213 | $ | 2 | - | - | $ | 6 | ||||||||||||
Liabilities
|
$ | (173 | ) | $ | (25 | ) | - | $ | (28 | ) | $ | (64 | ) | |||||||
Notional
Values
|
||||||||||||||||||||
Volumes(3)
|
||||||||||||||||||||
Purchases
|
13,159 | 22 | - | - | - | |||||||||||||||
Sales
|
14,520 | - | - | - | - | |||||||||||||||
Canadian dollars
|
- | - | - | - | - | |||||||||||||||
U.S. dollars
|
- | - | - | - | 1,325 | |||||||||||||||
Cross-currency
|
- | - | - |
136/U.S.
100
|
- | |||||||||||||||
Net
realized gains/(losses) in the period(4)
|
||||||||||||||||||||
Three months ended June 30,
2009
|
$ | 52 | $ | (10 | ) | - | - | $ | (10 | ) | ||||||||||
Six months ended June 30,
2009
|
$ | 78 | $ | (20 | ) | - | - | $ | (17 | ) | ||||||||||
Maturity
dates
|
2009-2015 | 2009-2012 | n/a | 2009-2013 | 2010-2013 |
(1)
|
All
derivative financial instruments in the held-for-trading classification
have been entered into for risk management purposes and are subject to the
Company’s risk management strategies, policies and limits. These include
derivatives that have not been designated as hedges or do not qualify for
hedge accounting treatment but have been entered into as economic hedges
to manage the Company’s exposures to market
risk.
|
(2)
|
Fair
values equal carrying values.
|
(3)
|
Volumes
for power, natural gas and oil products derivatives are in GWh, Bcf and
thousands of barrels, respectively.
|
(4)
|
Realized
and unrealized gains and losses on power, natural gas and oil products
derivative financial instruments held for trading are included in
Revenues. Realized and unrealized gains and losses on interest rate and
foreign exchange derivative financial instruments held for trading are
included in Interest Expense and Interest Income and Other, respectively.
The effective portion of unrealized gains and losses on derivative
financial instruments in hedging relationships are initially recognized in
Other Comprehensive Income, and are reclassified to Revenues, Interest
Expense and Interest Income and Other, as appropriate, as the original
hedged item settles.
|
(5)
|
All
hedging relationships are designated as cash flow hedges except for
interest-rate derivative financial instruments designated as fair value
hedges with a fair value of $4 million and a notional amount of US$150
million. Net realized gains on fair value hedges for the three and six
months ended June 30, 2009 were $1 million and $2 million, respectively,
and were included in Interest Expense. In second quarter 2009, the Company
did not record any amounts in Net Income related to ineffectiveness for
fair value hedges.
|
(6)
|
Net
Income for the three and six months ended June 30, 2009 included losses of
$4 million and gains of $1 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 six
months ended June 30, 2009 for discontinued cash flow hedges. No amounts
have been excluded from the assessment of hedge
effectiveness.
|
2008
|
||||||||||||||||||||
(unaudited)
(all
amounts in millions unless otherwise indicated)
|
Power
|
Natural
Gas
|
Oil
Products
|
Foreign
Exchange
|
Interest
|
|||||||||||||||
Derivative
Financial Instruments Held for Trading
|
||||||||||||||||||||
Fair
Values(1)(4)
|
||||||||||||||||||||
Assets
|
$ | 132 | $ | 144 | $ | 10 | $ | 41 | $ | 57 | ||||||||||
Liabilities
|
$ | (82 | ) | $ | (150 | ) | $ | (10 | ) | $ | (55 | ) | $ | (117 | ) | |||||
Notional
Values(4)
|
||||||||||||||||||||
Volumes(2)
|
||||||||||||||||||||
Purchases
|
4,035 | 172 | 410 | - | - | |||||||||||||||
Sales
|
5,491 | 162 | 252 | - | - | |||||||||||||||
Canadian dollars
|
- | - | - | - | 1,016 | |||||||||||||||
U.S. dollars
|
- | - | - |
U.S.
479
|
U.S.
1,575
|
|||||||||||||||
Japanese Yen (in
billions)
|
- | - | - |
JPY
4.3
|
- | |||||||||||||||
Cross-currency
|
- | - | - |
227/U.S.
157
|
- | |||||||||||||||
Net
unrealized (losses)/gains in the period(3)
|
||||||||||||||||||||
Three months ended June 30,
2008
|
$ | (2 | ) | $ | 7 | - | $ | 2 | $ | 2 | ||||||||||
Six months ended June 30,
2008
|
$ | (5 | ) | $ | (11 | ) | - | $ | (7 | ) | $ | (2 | ) | |||||||
Net
realized gains/(losses) in the period(3)
|
||||||||||||||||||||
Three months ended June 30,
2008
|
$ | 8 | $ | (20 | ) | - | $ | 5 | $ | 7 | ||||||||||
Six months ended June 30,
2008
|
$ | 9 | $ | 5 | - | $ | 10 | $ | 10 | |||||||||||
Maturity
dates(4)
|
2009-2014 | 2009-2011 |
2009
|
2009-2012 | 2009-2018 | |||||||||||||||
Derivative Financial
Instruments in Hedging Relationships(5)(6)
|
||||||||||||||||||||
Fair
Values(1)(4)
|
||||||||||||||||||||
Assets
|
$ | 115 | - | - | $ | 2 | $ | 8 | ||||||||||||
Liabilities
|
$ | (160 | ) | $ | (18 | ) | - | $ | (24 | ) | $ | (122 | ) | |||||||
Notional
Values (4)
|
||||||||||||||||||||
Volumes(2)
|
||||||||||||||||||||
Purchases
|
8,926 | 9 | - | - | - | |||||||||||||||
Sales
|
13,113 | - | - | - | - | |||||||||||||||
Canadian dollars
|
- | - | - | - | 50 | |||||||||||||||
U.S. dollars
|
- | - | - |
U.S.
15
|
U.S.
1,475
|
|||||||||||||||
Cross-currency
|
- | - | - |
136/U.S.
100
|
- | |||||||||||||||
Net
realized (losses)/ gains in the period(3)
|
||||||||||||||||||||
Three months ended June 30,
2008
|
$ | (37 | ) | $ | 11 | - | - | $ | (3 | ) | ||||||||||
Six months ended June 30,
2008
|
$ | (38 | ) | $ | 19 | - | - | $ | (2 | ) | ||||||||||
Maturity
dates(4)
|
2009-2014 | 2009-2011 | n/a | 2009-2013 | 2009-2019 |
(1)
|
Fair
values equal carrying values.
|
(2)
|
Volumes
for power, natural gas and oil products derivatives are in GWh, Bcf and
thousands of barrels, respectively.
|
(3)
|
Realized
and unrealized gains and losses on power, natural gas and oil products
derivative financial instruments held for trading are included in
Revenues. Realized and unrealized gains and losses on interest rate and
foreign exchange derivative financial instruments held for trading are
included in Interest Expense and Interest Income and Other, respectively.
The effective portion of unrealized gains and losses on derivative
financial instruments in hedging relationships are initially recognized in
Other Comprehensive Income, and are reclassified to Revenues, Interest
Expense and Interest Income and Other, as appropriate, as the original
hedged item settles.
|
(4)
|
As
at December 31, 2008.
|
(5)
|
All
hedging relationships are designated as cash flow hedges except for
interest-rate derivative financial instruments designated as fair value
hedges with a fair value of $8 million and notional amounts of $50 million
and US$50 million at December 31, 2008. There were no net realized gains
or losses on fair value hedges for the three and six months ended June 30,
2008. In second quarter 2008, the Company did not record any amounts in
Net Income related to ineffectiveness for fair value
hedges.
|
(6)
|
Net
Income for the three and six months ended June 30, 2008 included losses of
$5 million and $3 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 six months
ended June 30, 2008 for discontinued cash flow hedges. No amounts have
been excluded from the assessment of hedge
effectiveness.
|
(unaudited)
|
||||||
(millions
of dollars)
|
June
30, 2009
|
December
31, 2008
|
||||
Current
|
||||||
Other current
assets
|
445
|
318
|
||||
Accounts
payable
|
(445
|
)
|
(298
|
)
|
||
Long-term
|
||||||
Other assets
|
165
|
191
|
||||
Deferred
amounts
|
(396
|
)
|
(694
|
)
|
7.
|
Employee
Future Benefits
|
Three
months ended June 30
|
Pension
Benefit Plans
|
Other
Benefit Plans
|
||||||||
(unaudited)(millions
of dollars)
|
2009
|
2008
|
2009
|
2008
|
||||||
Current
service cost
|
12
|
12
|
1
|
1
|
||||||
Interest
cost
|
22
|
20
|
2
|
2
|
||||||
Expected
return on plan assets
|
(26
|
)
|
(23
|
)
|
(1
|
)
|
(1
|
)
|
||
Amortization
of transitional obligation related to regulated business
|
-
|
-
|
1
|
1
|
||||||
Amortization
of net actuarial loss
|
1
|
5
|
1
|
1
|
||||||
Amortization
of past service costs
|
1
|
1
|
-
|
-
|
||||||
Net
benefit cost recognized
|
10
|
15
|
4
|
4
|
Six
months ended June 30
|
Pension
Benefit Plans
|
Other
Benefit Plans
|
||||||||
(unaudited)(millions
of dollars)
|
2009
|
2008
|
2009
|
2008
|
||||||
Current
service cost
|
23
|
25
|
1
|
1
|
||||||
Interest
cost
|
45
|
39
|
4
|
4
|
||||||
Expected
return on plan assets
|
(51
|
)
|
(46
|
)
|
(1
|
)
|
(1
|
)
|
||
Amortization
of transitional obligation related to regulated business
|
-
|
-
|
1
|
1
|
||||||
Amortization
of net actuarial loss
|
2
|
9
|
1
|
1
|
||||||
Amortization
of past service costs
|
2
|
2
|
-
|
-
|
||||||
Net
benefit cost recognized
|
21
|
29
|
6
|
6
|
8.
|
Acquisition
|
9.
|
Commitments
and Other
|
10.
|
Subsequent
Event
|
TransCanada welcomes questions from shareholders and potential investors. Please telephone: |
Investor Relations, at (800) 361-6522 (Canada and U.S. Mainland) or direct dial David Moneta/Myles Dougan/Terry Hook at (403) 920-7911. The investor fax line is (403) 920-2457. Media Relations: Cecily Dobson/Terry Cunha (403) 920-7859 or (800) 608-7859. |
Visit the TransCanada website at: http://www.transcanada.com. |
(unaudited)
|
Three
months ended June 30
|
Six
months ended June 30
|
||||||||||||||
(millions
of dollars, except per share amounts)
|
2009
|
2008
|
2009
|
2008
|
||||||||||||
Net
Income in Accordance with Canadian GAAP
|
314 | 324 | 648 | 773 | ||||||||||||
U.S.
GAAP adjustments:
|
||||||||||||||||
Net income attributable to
non-controlling interests(1)
|
13 | 17 | 48 | 88 | ||||||||||||
Unrealized loss/(gain) on
natural gas inventory held
in storage (2)
|
6 | (42 | ) | 29 | (76 | ) | ||||||||||
Tax impact of unrealized
loss/(gain) on natural gas inventory held
in storage
|
(2 | ) | 13 | (9 | ) | 24 | ||||||||||
Tax recovery due to a change in
tax legislation substantively enacted in Canada(3)
|
(1 | ) | (1 | ) | (1 | ) | (1 | ) | ||||||||
Net
Income in Accordance with U.S. GAAP
|
330 | 311 | 715 | 808 | ||||||||||||
Less:
net income attributable to non-controlling interests(1)
|
(13 | ) | (17 | ) | (48 | ) | (88 | ) | ||||||||
Net
Income Attributable to Common Shareholders
in Accordance with U.S. GAAP(1)
|
317 | 294 | 667 | 720 | ||||||||||||
Other
Comprehensive Income (Loss) (OCI) in Accordance with Canadian
GAAP
|
11 | 33 | 4 | 30 | ||||||||||||
U.S.
GAAP adjustments:
|
||||||||||||||||
Change in funded status of
postretirement plan liability, net of tax(4)
|
1 | 2 | 2 | 3 | ||||||||||||
Change in equity investment
funded status of postretirement plan liability, net of tax(4)
|
(1 | ) | 2 | - | 4 | |||||||||||
Comprehensive
Income in Accordance with U.S. GAAP
|
328 | 331 | 673 | 757 | ||||||||||||
Net
Earnings Per Share in Accordance with U.S. GAAP, Basic and
Diluted
|
$ | 0.51 | $ | 0.52 | $ | 1.07 | $ | 1.31 | ||||||||
(unaudited)
(millions
of dollars)
|
June
30,
2009
|
December
31,
2008
|
||||||
Current
assets(2)
|
4,705 | 3,399 | ||||||
Long-term
investments(4)(5)(6)
|
6,600 | 5,221 | ||||||
Plant,
property and equipment
|
22,800 | 22,901 | ||||||
Goodwill
|
4,037 | 4,258 | ||||||
Regulatory
Assets(4)(7)
|
1,764 | 1,810 | ||||||
Other
assets
(4)(8)
|
1,709 | 1,608 | ||||||
41,615 | 39,197 | |||||||
Current
liabilities(3)
|
2,679 | 4,264 | ||||||
Deferred
amounts(4)(6)
|
1,070 | 1,238 | ||||||
Regulatory
liabilities
|
487 | 551 | ||||||
Deferred
income taxes(2)(4)(5)(7)
|
2,636 | 2,602 | ||||||
Long-term
debt and junior subordinated notes(8)
|
18,814 | 16,664 | ||||||
25,686 | 25,319 | |||||||
Shareholders’
equity:
|
||||||||
Common
shares
|
11,176 | 9,265 | ||||||
Non-controlling
interests
|
1,153 | 1,194 | ||||||
Contributed
surplus
|
280 | 279 | ||||||
Retained
earnings(2)(3)(5)
|
3,983 | 3,809 | ||||||
Accumulated
other comprehensive income(4)(9)
|
(663 | ) | (669 | ) | ||||
15,929 | 13,878 | |||||||
41,615 | 39,197 |
(1)
|
As
required by Statement of Financial Accounting Standard (SFAS) 160
“Noncontrolling Interests in Consolidated Financial Statements – an
amendment of ARB No.51”, the Company has reclassified its non-controlling
interests on the income statement and balance sheet. On the balance sheet,
non-controlling interests are now presented in the equity section. On the
income statement, consolidated net income includes both the Company’s and
the non-controlling interests’ share of net income. In addition,
consolidated net income attributable to the Company and the
non-controlling interests are separately disclosed. This reclassification
has been applied retrospectively as
required.
|
(2)
|
In
accordance with Canadian GAAP, natural gas inventory held in storage is
recorded at its fair value. Under U.S. GAAP, inventory is recorded at
lower of cost or market.
|
(3)
|
In
accordance with Canadian GAAP, the Company recorded current income tax
benefits resulting from substantively enacted Canadian federal income tax
legislation. Under U.S. GAAP, the legislation must be fully enacted for
income tax adjustments to be
recorded.
|
(4)
|
Represents
the amortization of net loss and prior service cost amounts recorded in
accumulated other comprehensive income under SFAS No.158 “Employers’
Accounting for Defined Benefit Pension and Other Postretirement Plans” for
the Company’s defined benefit pension and other postretirement
plans.
|
(5)
|
Under
Canadian GAAP, pre-development costs incurred during the commissioning
phase of a new project are deferred until commercial production levels are
achieved. After such time, those costs are amortized over the estimated
life of the project. Under U.S. GAAP, such costs are expensed as incurred.
Certain development costs incurred by Bruce Power L.P., an equity
investment, were expensed under U.S.
GAAP.
|
(6)
|
Under
Canadian GAAP, the Company accounts for certain investments using the
proportionate consolidation basis whereby the Company’s proportionate
share of the assets, liabilities, revenues, expenses and cash flows are
included in the Company’s financial statements. U.S. GAAP does
not allow the use of proportionate consolidation and requires that such
investments be recorded on an equity accounting
basis. Information on the balances that have been
proportionately consolidated is located in Note 8 to the Company’s audited
consolidated annual financial statements for the year ended December 31,
2008. As a consequence of using equity accounting for U.S.
GAAP, the Company is required to reflect an additional liability of $179
million at June 30, 2009 (December 31, 2008 - $51 million) for the
estimated fair value of certain guarantees related to debt and other
performance commitments of the joint venture operations that were not
required to be recorded when the underlying liability was reflected on the
balance sheet under the proportionate consolidation method of
accounting.
|
(7)
|
Under
U.S. GAAP SFAS 71 “Accounting for the Effects of Certain Types of
Regulation”, the Company is required to record a deferred income tax
liability for its cost-of-service regulated businesses and a corresponding
regulatory asset. Effective January 1, 2009, the Company chose
to adopt accounting policies consistent with SFAS 71 for its Canadian GAAP
financial statements. Therefore, this U.S. GAAP difference has
been eliminated subsequent to December 31,
2008.
|
(8)
|
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. |
(9)
|
At June 30, 2009, Accumulated Other Comprehensive Income in accordance with U.S. GAAP is $195 million higher than under Canadian GAAP. The difference relates to the accounting treatment for defined benefit pension and other postretirement plans. |
(unaudited)
(millions
of dollars)
|
Quoted
prices in active markets
(Level
I)
|
Significant
other observable inputs
(Level
II)
|
Significant
unobservable inputs
(Level
III)
|
Total
|
||||
Derivative
Financial Instruments:
|
||||||||
Assets
|
95
|
540
|
-
|
635
|
||||
Liabilities
|
(155
|
)
|
(689
|
)
|
(22
|
)
|
(866
|
)
|
Non-Derivative
Financial Instruments Available for Sale:
|
||||||||
Assets
|
23
|
-
|
-
|
23
|
||||
Guarantees:
|
||||||||
Liabilities
|
-
|
-
|
(190
|
)
|
(190
|
)
|
||
Total
|
(37
|
)
|
(149
|
)
|
(212
|
)
|
(398
|
)
|
(unaudited)
|
3
Months Ended June 30
|
6
Months Ended June 30
|
||||||
(millions
of dollars, pre-tax)
|
Derivatives
|
(1)
|
Guarantees
|
(2)
|
Derivatives
|
(1)
|
Guarantees
|
(2)
|
Balance,
opening
|
-
|
-
|
-
|
-
|
||||
Transfers
in(2)
|
-
|
(200
|
)
|
-
|
(60
|
)
|
||
Total
realized and unrealized gains/(losses) included in OCI
|
(22
|
)
|
-
|
(22
|
)
|
-
|
||
Purchases
and settlements, net
|
-
|
10
|
-
|
(130
|
)
|
|||
Balance,
closing
|
(22
|
)
|
(190
|
)
|
(22
|
)
|
(190
|
)
|
Derivatives
in Statement 133 Net Investment Hedging Relationships
|
Amount
of Gain or (Loss) Recognized in OCI on Derivatives
|
Location
of Gain (Loss) Reclassified from AOCI into Income
|
Amount
of Gain or (Loss) Reclassified from AOCI into Income
|
Location
of Gain or (Loss) Recognized in Income on Derivative
|
Amount
of Gain or (Loss) Recognized in Income on Derivative
|
Foreign
exchange contracts
|
143
|
Gain
or (loss) on sale of subsidiary
|
Nil
|
Other
income/ (expense)
|
Nil
|
Derivatives
in Statement 133 Net Investment Hedging Relationships
|
Amount
of Gain or (Loss) Recognized in OCI on Derivatives
|
Location
of Gain (Loss) Reclassified from AOCI into Income
|
Amount
of Gain or (Loss) Reclassified from AOCI into Income
|
Location
of Gain or (Loss) Recognized in Income on Derivative
|
Amount
of Gain or (Loss) Recognized in Income on Derivative
|
Foreign
exchange contracts
|
147
|
Gain
or (loss) on sale of subsidiary
|
Nil
|
Other
income/ (expense)
|
Nil
|
Three
months ended June 30, 2009
(unaudited)
(millions of dollars,
pre-tax)
|
Power
|
Natural
Gas
|
Foreign
Exchange
|
Interest
|
||||
Amount
of gain or loss recognized in OCI on derivative (effective
portion)
|
65
|
(1
|
)
|
(8
|
)
|
5
|
||
Amount
of gain or loss reclassified from AOCI into income (effective
portion)
|
(30
|
)
|
9
|
-
|
11
|
|||
Amount
of gain or loss recognized in income on derivative (ineffective portion
and amount excluded from effectiveness testing)
|
(4
|
)
|
-
|
-
|
-
|
Six
months ended June 30, 2009
(unaudited)
(millions of dollars,
pre-tax)
|
Power
|
Natural
Gas
|
Foreign
Exchange
|
Interest
|
||||
Amount
of gain or loss recognized in OCI on derivative (effective
portion)
|
104
|
(14
|
)
|
(4
|
)
|
-
|
||
Amount
of gain or loss reclassified from AOCI into income (effective
portion)
|
(28
|
)
|
2
|
-
|
20
|
|||
Amount
of gain or loss recognized in income on derivative (ineffective portion
and amount excluded from effectiveness testing)
|
-
|
1
|
-
|
-
|
1. | I have reviewed this quarterly report on Form 6-K of TransCanada Corporation; |
2.
|
Based
on my knowledge, this report does not contain any untrue statement of a
material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this
report;
|
3.
|
Based
on my knowledge, the financial statements, and other financial information
included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the issuer as
of, and for, the periods presented in this
report;
|
4.
|
The
issuer's other certifying officer(s) and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal
control over financial reporting (as defined in Exchange Act Rules
13a-15(f) and 15d-15(f)) for the issuer and
have:
|
(a)
|
Designed
such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to ensure
that material information relating to the issuer, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being
prepared;
|
(b)
|
Designed
such internal control over financial reporting, or caused such internal
control over financial reporting to be designed under our supervision, to
provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting
principles;
|
(c)
|
Evaluated
the effectiveness of the issuer’s disclosure controls and procedures and
presented in this report our conclusions about the effectiveness of the
disclosure controls and procedures, as of the end of the period covered by
this report based on such evaluation;
and
|
(d)
|
Disclosed
in this report any change in the issuer’s internal control over financial
reporting that occurred during the issuer’s most recent fiscal quarter
(the issuer’s fourth fiscal quarter in the case of an annual report) that
has materially affected, or is reasonably likely to materially affect, the
issuer’s internal control over financial reporting;
and
|
5.
|
The
issuer’s other certifying officer(s) and I have disclosed, based on our
most recent evaluation of internal control over financial reporting, to
the issuer’s auditors and the audit committee of the issuer’s board of
directors (or persons performing the equivalent
functions):
|
(a)
|
All
significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are
reasonably likely to adversely affect the issuer’s ability to record,
process, summarize and report financial information;
and
|
(b)
|
Any
fraud, whether or not material, that involves management or other
employees who have a significant role in the issuer’s internal control
over financial reporting.
|
Dated:
|
July
30, 2009
|
/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 issuer as
of, and for, the periods presented in this report;
|
||
4.
|
The
issuer’s other certifying officer(s) and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal
control over financial reporting (as defined in Exchange Act Rules
13a-15(f) and 15d-15(f)) for the issuer and have:
|
||
(a) |
Designed
such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to ensure
that material information relating to the issuer, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being
prepared;
|
||
(b) |
Designed
such internal control over financial reporting, or caused such internal
control over financial reporting to be designed under our supervision, to
provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting
principles;
|
||
(c) |
Evaluated
the effectiveness of the issuer’s disclosure controls and procedures and
presented in this report our conclusions about the effectiveness of the
disclosure controls and procedures, as of the end of the period covered by
this report based on such evaluation; and
|
||
(d) |
Disclosed
in this report any change in the issuer’s internal control over financial
reporting that occurred during the issuer’s most recent fiscal quarter
(the issuer’s fourth fiscal quarter in the case of an annual report) that
has materially affected, or is reasonably likely to materially affect, the
issuer’s internal control over financial reporting; and
|
||
5.
|
The
issuer’s other certifying officer(s) and I have disclosed, based on our
most recent evaluation of internal control over financial reporting, to
the issuer’s auditors and the audit committee of the issuer’s board of
directors (or persons performing the equivalent functions):
|
||
(a) |
All
significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are
reasonably likely to adversely affect the issuer’s ability to record,
process, summarize and report financial information; and
|
||
(b) |
Any
fraud, whether or not material, that involves management or other
employees who have a significant role in the issuer’s internal control
over financial reporting.
|
Dated:
|
July
30, 2009
|
/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
|
|
July
30, 2009
|
1.
|
the
Report fully complies with the requirements of Section 13(a) or 15(d) of
the Securities Exchange Act of 1934; and
|
2.
|
the
information contained in the Report fairly presents, in all material
respects, the financial condition and results of operations of the
Company.
|
/s/ Gregory A.
Lohnes
|
|
Gregory
A. Lohnes
|
|
Chief
Financial Officer
|
|
July
30, 2009
|
Media
Inquiries:
|
Cecily
Dobson/Terry Cunha
|
(403)
920-7859
|
(800)
608-7859
|
||
Analyst
Inquiries:
|
David
Moneta/Myles Dougan/Terry Hook
|
(403)
920-7911
|
(800)
361-6522
|
§
|
Net
income of $314 million or $0.50 per
share
|
§
|
Comparable
earnings of $319 million or $0.51 per
share
|
§
|
Comparable
earnings before interest, taxes, depreciation and amortization (EBITDA) of
$1.0 billion
|
§
|
Funds
generated from operations of $692
million
|
§
|
Dividend
of $0.38 per common share declared by the Board of
Directors
|
§
|
Continued
to advance TransCanada’s $21 billion capital
program
|
§
|
Announced
that TransCanada will become the sole owner of the US$12 billion Keystone
Oil Pipeline System
|
§
|
Issued
approximately $1.8 billion of common shares to help fund the Company’s
capital program
|
§
|
TransCanada
reached an agreement to acquire ConocoPhillips’ remaining interest in the
Keystone Oil Pipeline System (Keystone) for approximately US$550 million
plus the assumption of approximately US$200 million of short-term
indebtedness. The transaction is expected to close in third quarter 2009,
subject to the receipt of certain regulatory
approvals.
|
§
|
TransCanada entered into a contract to build, own and operate the US$320 million Guadalajara Pipeline in Mexico, supported by a 25-year contract for its entire capacity with Comisión Federal de Electricidad, Mexico’s state-owned electric company. The proposed pipeline will extend 310 kilometres (kms) (193 miles) from an LNG terminal under construction near Manzanillo, Mexico, to Guadalajara, and is expected to be capable of transporting 500 million cubic feet per day of natural gas. The Company expects to complete most of the construction in 2010 with a targeted in-service date of March 2011. |
§
|
TransCanada sold the North Baja Pipeline (North Baja), to TC PipeLines, LP (PipeLines LP) on July 1, 2009. As part of the transaction, TransCanada agreed to amend its incentive distribution rights with PipeLines LP. TransCanada received aggregate consideration totalling approximately US$395 million from PipeLines LP, including approximately US$200 million in cash and 6,371,680 common units of PipeLines LP. TransCanada’s ownership in PipeLines LP increased to 42.6 per cent as a result of this transaction. TransCanada will continue to operate the North Baja Pipeline. |
§
|
TransCanada
submitted an application in April 2009 to the National Energy
Board (NEB) for approval to construct and operate the Groundbirch
Pipeline, which comprises a 77 km (48 mile) natural gas pipeline and
related facilities. The Groundbirch Pipeline is an extension of
the Alberta System which is expected to connect natural gas supply
primarily from the Montney shale gas region in northeast B.C. to existing
infrastructure in northwest Alberta. In June 2009, the NEB announced that
it will hold a public hearing process on the
application. Subject to regulatory approvals, construction of
the Groundbirch Pipeline is expected to commence in July 2010 with final
completion anticipated in November
2010.
|
§
|
TransCanada
filed a project description in May 2009 with the NEB to construct the
Horn River natural gas pipeline. The Horn River Pipeline
is a proposed extension of the Alberta System to service the Horn River
shale gas region in northeast B.C. Horn River producers have recently
notified TransCanada that they are extending their construction schedule
for upstream production facilities which will enhance their ability to
manage project costs, therefore, TransCanada will delay the in-service
date of the Horn River Pipeline from 2011 to
2012.
|
§
|
TransCanada
and ExxonMobil Corporation reached an agreement to work together to
progress TransCanada’s Alaska Pipeline Project. With a forecasted capital
cost of US$26 billion (2007 estimate in 2007 dollars), the project would
provide a variety of benefits to Alaska and Canada, as well as the rest of
the United States including substantial revenues, jobs, business
opportunities and new, long-term stable supplies of natural
gas.
|
§
|
On
July 6, 2009, Bruce Power and the Ontario Power Authority (OPA) amended
certain terms and conditions included in the Bruce Power Refurbishment
Implementation Agreement. The amendments are consistent with the original
intent of the contract, which was signed in 2005, and recognize the
significant changes in Ontario’s electricity market. The changes are
outlined in more detail in the recent developments section of
TransCanada’s Second Quarter 2009 Management’s Discussion and
Analysis.
|
§
|
TransCanada
continues to advance construction on the Kibby Wind Power (Kibby)
project including the installation of 22 turbines which are expected to be
completed this summer. Kibby is expected to have the
capacity to produce 132 megawatts (MW) of power when complete, with
commissioning of the first phase of the project to begin in late
2009.
|
§
|
Construction
of the 683 MW Halton Hills generating station also continued and it is
anticipated to be in service in the third quarter of
2010.
|
§
|
TransCanada
expects to begin construction of the US$500 million Coolidge Generating
Station in August 2009. The 575 MW power facility is expected to be
online by the end of second quarter 2011. The simple-cycle, natural
gas-fired peaking facility, with the capacity to power 575,000 homes, will
provide a quick response to peak power demand. The facility will also
provide reserve capacity and the ability to generate power quickly to
support power reliability in the region.
|
§
|
The
Government of Québec approved the construction of the 212 MW Gros-Morne
and 58 MW Montagne-Sèche wind farms on June 10,
2009. Representing an investment of approximately $340 million,
both wind farms are expected to be operational by 2012. These are the
fourth and fifth Québec-based wind farms under development by Cartier
Wind, which is 62 per cent owned by
TransCanada.
|
§
|
The
Company and its subsidiaries held cash and cash equivalents of $3.5
billion at June 30, 2009.
|
§
|
On
June 24, 2009, TransCanada completed a public offering of 50.8 million
common shares. On June 30, 2009, an additional 7.6 million common shares
were issued upon exercise of the underwriters’ over-allotment option.
Proceeds from the common share offering and over-allotment option totalled
$1.8 billion and will be used by TransCanada to partially fund capital
projects of the Company, including the acquisition of the remaining
interest in Keystone, for general corporate purposes and to repay
short-term indebtedness.
|
§
|
With
this recent common share offering, TransCanada is well positioned to fund
its existing capital program through its growing internally-generated cash
flow, its dividend reinvestment plan and the issuance of long-term debt,
supplemented by further subordinated capital, as required, in the form of
preferred shares or other hybrid securities. As demonstrated by the recent
sale of North Baja, TransCanada will also continue to examine
opportunities for portfolio management, including an ongoing role for
PipeLines LP, in the financing of TransCanada’s capital
program.
|
(unaudited)
|
Three
months ended June 30
|
Six
months ended June 30
|
||||||||||||
(millions
of dollars)
|
2009
|
2008
|
2009
|
2008
|
||||||||||
Revenues
|
2,127 | 2,017 | 4,507 | 4,150 | ||||||||||
Comparable EBITDA(1)
|
1,017 | 948 | 2,148 | 2,015 | ||||||||||
Comparable EBIT(1)
|
672 | 633 | 1,457 | 1,390 | ||||||||||
EBIT(1)
|
665 | 645 | 1,437 | 1,640 | ||||||||||
Net
Income
|
314 | 324 | 648 | 773 | ||||||||||
Comparable Earnings(1)
|
319 | 316 | 662 | 642 | ||||||||||
Cash
Flows
|
||||||||||||||
Funds generated from
operations(1)
|
692 | 676 | 1,458 | 1,598 | ||||||||||
Decrease/(increase) in
operating working capital
|
315 | (104 | ) | 393 | (98 | ) | ||||||||
Net cash provided by
operations
|
1,007 | 572 | 1,851 | 1,500 | ||||||||||
Capital
Expenditures
|
1,263 | 633 | 2,386 | 1,093 | ||||||||||
Acquisitions,
Net of Cash Acquired
|
115 | 2 | 249 | 4 |
Three
months ended June 30
|
Six
months ended June 30
|
|||||||||||||||
(unaudited)
|
2009
|
2008
|
2009
|
2008
|
||||||||||||
Net
Income Per Share - Basic
|
$ | 0.50 | $ | 0.58 | $ | 1.04 | $ | 1.40 | ||||||||
Comparable Earnings Per
Share(1)
|
$ | 0.51 | $ | 0.57 | $ | 1.06 | $ | 1.17 | ||||||||
Dividends
Declared Per Share
|
$ | 0.38 | $ | 0.36 | $ | 0.76 | $ | 0.72 | ||||||||
Basic Common Shares
Outstanding (millions)
|
||||||||||||||||
Average for the
period
|
624 | 561 | 621 | 551 | ||||||||||||
End of period
|
679 | 578 | 679 | 578 |
(1)
|
Refer
to the Non-GAAP Measures section in this News Release for further
discussion of comparable EBITDA, comparable EBIT, EBIT, comparable
earnings, comparable earnings per share and funds generated from
operations.
|