TransCanada Reports Second Quarter Net Income of $314 Million or $0.50 Per Share
* Reuters is not responsible for the content in this press release.
CALGARY, ALBERTA, Jul 30 (MARKET WIRE) --
TransCanada Corporation (TSX: TRP) (NYSE: TRP) (TransCanada or the
Company) today announced net income for second quarter 2009 of $314
million or $0.50 per share. TransCanada's Board of Directors also
declared a quarterly dividend of $0.38 per common share.
"Our solid second quarter performance in the face of historically low
power prices in Alberta and Ontario demonstrates the inherent strength of
our business model and the quality of our existing assets," said Hal
Kvisle, TransCanada's president and chief executive officer. "Looking
forward, our strong internally generated cash flow and prudent decisions
to maintain TransCanada's financial strength means we are well positioned
to fund our large capital program. While the carrying costs and dilution
associated with recent financings will continue to have an impact on our
financial results through the remainder of 2009, we expect significant
growth in earnings and cash flow over the next four years as $21 billion
of secured, low-risk projects are placed into service."
Second Quarter 2009 Highlights
(All financial figures are unaudited and in Canadian dollars unless noted
otherwise)
- 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 reported net income for second quarter 2009 of $314 million
($0.50 per share) compared to $324 million ($0.58 per share) for second
quarter 2008.
Comparable earnings were $319 million in second quarter 2009 compared to
$316 million for the same period in 2008. The increase in comparable
earnings was primarily due to higher earnings from Bruce Power, Eastern
Power, Natural Gas Storage, and U.S. Pipelines, partially offset by a
decrease in Western Power and higher financing costs. Comparable earnings
per share of $0.51 in second quarter 2009 decreased from $0.57 per share
for the same period in 2008 due to an increase in the average number of
shares outstanding following the Company's common share issuances in the
second and fourth quarters of 2008 and the second quarter of 2009.
Comparable earnings in second quarter 2009 and 2008 excluded $5 million
of after tax unrealized losses, and $8 million of after tax unrealized
gains, respectively, resulting from changes in the fair value of
proprietary natural gas inventory and natural gas forward purchase and
sale contracts. Comparable EBITDA in second quarter 2009 of $1,017
million increased $69 million compared to $948 million in second quarter
2008.
Funds generated from operations in second quarter 2009 were $692 million
compared to $676 million in second quarter 2008.
Notable recent developments in Pipelines, Energy and Corporate include:
Pipelines:
- 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 will assume responsibility for ConocoPhillips' share of the
capital investment required to complete the project resulting in an
incremental commitment of approximately US$1.7 billion through the end of
2012.
When completed, the US$12 billion pipeline will be one of the largest oil
delivery systems in North America with the capacity to deliver 1.1
million barrels per day (bbl/d) from Western Canada to the largest
refining markets in the United States. To date, Keystone has secured
long-term commitments for 910,000 bbl/d for an average term of
approximately 18 years which represents 83 per cent of the commercial
design of the system. At July 30, 2009, the first phase was approximately
80 per cent complete.
Keystone is expected to begin to generate EBITDA in first quarter 2010,
when commercial operations to Wood River and Patoka, Illinois commence,
and increase through 2011 and 2012 as subsequent phases of Keystone are
placed in service. Based on current long-term commitments of 910,000
bbl/d, Keystone is expected to generate EBITDA of approximately US$1.2
billion in 2013, its first full year of commercial operation serving both
the U.S. Midwest and Gulf Coast markets. If volumes increase to 1.1
million bbl/d, Keystone would generate approximately US$1.5 billion of
annual EBITDA. In the future, Keystone could be economically expanded
from 1.1 million bbl/d to 1.5 million bbl/d in response to additional
market demand.
- 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 Comision 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.
The Alaska Pipeline Project continues to move forward with project
development, including engineering, environmental reviews, Alaska Native
and Canadian Aboriginal engagement, and commercial work to conclude an
initial binding open season by July 2010. Subject to the completion of a
successful open season, construction of the approximately 2,700 km (1,700
mile), 4.5 billion cubic feet per day pipeline is expected to begin in
2016, once environmental and regulatory approvals are received, and begin
transporting natural gas in 2018.
Energy:
- 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 Quebec approved the construction of the 212 MW Gros-Morne
and 58 MW Montagne-Seche 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 Quebec-based wind
farms under development by Cartier Wind, which is 62 per cent owned by
TransCanada.
Corporate:
- 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.
Teleconference - Audio and Slide Presentation
TransCanada Corporation will hold a teleconference and webcast to discuss
its 2009 second quarter financial results. Hal Kvisle, TransCanada
president and chief executive officer and Greg Lohnes, executive
vice-president and chief financial officer, along with other members of
the TransCanada executive leadership team, will discuss the financial
results and company developments, including its $21 billion capital
program before opening the call to questions from analysts, members of
the media and other interested parties.
Event:
TransCanada second quarter 2009 financial results teleconference and
webcast
Date:
Thursday, July 30, 2009
Time:
2:30 p.m. mountain daylight time (MDT) / 4:30 p.m. eastern daylight time
(EDT)
How:
To participate in the teleconference, please call (866) 225-6564 or (416)
641-6136 (Toronto area). Please dial in 10 minutes prior to the start of
the call. No pass code is required. A live webcast of the teleconference
will also be available on TransCanada's website (www.transcanada.com).
A replay of the teleconference will be available two hours after the
conclusion of the call until midnight (EDT) August 6, 2009. Please call
(800) 408-3053 or (416) 695-5800 (Toronto area) and enter pass code
7807228#. The webcast will be archived and available for replay on
www.transcanada.com.
With more than 50 years' experience, TransCanada is a leader in the
responsible development and reliable operation of North American energy
infrastructure including natural gas pipelines, power generation, gas
storage facilities, and projects related to oil pipelines. TransCanada's
network of wholly owned pipelines extends more than 59,000 kilometres
(36,500 miles), tapping into virtually all major gas supply basins in
North America. TransCanada is one of the continent's largest providers of
gas storage and related services with approximately 370 billion cubic
feet of storage capacity. A growing independent power producer,
TransCanada owns, or has interests in, over 10,900 megawatts of power
generation in Canada and the United States. TransCanada's common shares
trade on the Toronto and New York stock exchanges under the symbol TRP.
For more information visit: www.transcanada.com
Forward-Looking Information
This news release may contain certain information that is forward looking
and is subject to important risks and uncertainties. The words
"anticipate", "expect", "believe", "may", "should", "estimate",
"project", "outlook", "forecast" or other similar words are used to
identify such forward-looking information. Forward-looking statements in
this document are intended to provide TransCanada securityholders and
potential investors with information regarding TransCanada and its
subsidiaries, including management's assessment of TransCanada's and its
subsidiaries' future financial and operations plans and outlook.
Forward-looking statements in this document may include, among others,
statements regarding the anticipated business prospects and financial
performance of TransCanada and its subsidiaries, expectations or
projections about the future, and strategies and goals for growth and
expansion. All forward-looking statements reflect TransCanada's beliefs
and assumptions based on information available at the time the statements
were made. Actual results or events may differ from those predicted in
these forward-looking statements. Factors that could cause actual results
or events to differ materially from current expectations include, among
others, the ability of TransCanada to successfully implement its
strategic initiatives and whether such strategic initiatives will yield
the expected benefits, the operating performance of TransCanada's
pipeline and energy assets, the availability and price of energy
commodities, capacity payments, regulatory processes and decisions,
changes in environmental and other laws and regulations, competitive
factors in the pipeline and energy sectors, construction and completion
of capital projects, labour, equipment and material costs, access to
capital markets, interest and currency exchange rates, technological
developments and the current economic conditions in North America. By its
nature, forward-looking information is subject to various risks and
uncertainties, which could cause TransCanada's actual results and
experience to differ materially from the anticipated results or
expectations expressed. Additional information on these and other factors
is available in the reports filed by TransCanada with Canadian securities
regulators and with the U.S. Securities and Exchange Commission (SEC).
Readers are cautioned to not place undue reliance on this forward-looking
information, which is given as of the date it is expressed in this news
release or otherwise, and to not use future-oriented information or
financial outlooks for anything other than their intended purpose.
TransCanada undertakes no obligation to update publicly or revise any
forward-looking information, whether as a result of new information,
future events or otherwise, except as required by law.
Non-GAAP Measures
TransCanada uses the measures "comparable earnings", "comparable earnings
per share", "earnings before interest, taxes, depreciation and
amortization" (EBITDA), "comparable EBITDA", "earnings before interest
and taxes" (EBIT), "comparable EBIT" and "funds generated from
operations" in this news release. These measures do not have any
standardized meaning prescribed by Canadian generally accepted accounting
principles (GAAP). They are, therefore, considered to be non-GAAP
measures and may not be comparable to similar measures presented by other
entities. Management of TransCanada uses these non-GAAP measures to
improve its ability to compare financial results among reporting periods
and to enhance its understanding of operating performance, liquidity and
ability to generate funds to finance operations. These non-GAAP measures
are also provided to readers as additional information on TransCanada's
operating performance, liquidity and ability to generate funds to finance
operations.
Management uses the measures of comparable earnings, EBITDA and EBIT to
better evaluate trends in the Company's underlying operations. Comparable
earnings, comparable EBITDA and comparable EBIT comprise net income,
EBITDA and EBIT, respectively, adjusted for specific items that are
significant, but are not reflective of the Company's underlying
operations in the period. Specific items are subjective, however,
management uses its judgement and informed decision-making when
identifying items to be excluded in calculating comparable earnings,
comparable EBITDA and comparable EBIT, some of which may recur. Specific
items may include but are not limited to certain income tax refunds and
adjustments, gains or losses on sales of assets, legal and bankruptcy
settlements, and certain fair value adjustments. The table in the
Consolidated Results of Operations section of this MD&A presents a
reconciliation of comparable earnings, comparable EBITDA, comparable EBIT
and EBIT to Net Income. Comparable earnings per share is calculated by
dividing comparable earnings by the weighted average number of shares
outstanding for the period.
EBITDA is an approximate measure of the Company's pre-tax operating cash
flow. EBITDA comprises earnings before deducting interest and other
financial charges, income taxes, depreciation and amortization, and
non-controlling interests. EBIT is a measure of the Company's earnings
from ongoing operations. EBIT comprises earnings before deducting
interest and other financial charges, income taxes and non-controlling
interests.
Funds generated from operations comprises net cash provided by operations
before changes in operating working capital. A reconciliation of funds
generated from operations to net cash provided by operations is presented
in the "Liquidity and Capital Resources" section of this MD&A.
Second Quarter 2009 Financial Highlights
Operating Results
Three months ended Six months ended
(unaudited) June 30 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
---------------------------------------
---------------------------------------
Common Share Statistics
Three months ended Six months ended
June 30 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.
TRANSCANADA CORPORATION - SECOND QUARTER 2009
Quarterly Report to Shareholders
Management's Discussion and Analysis
Management's Discussion and Analysis (MD&A) dated July 30, 2009 should be
read in conjunction with the accompanying unaudited Consolidated
Financial Statements of TransCanada Corporation (TransCanada or the
Company) for the three and six months ended June 30, 2009. It should also
be read in conjunction with the audited Consolidated Financial Statements
and notes thereto, and the MD&A contained in TransCanada's 2008 Annual
Report for the year ended December 31, 2008. Additional information
relating to TransCanada, including the Company's Annual Information Form
and other continuous disclosure documents, is available on SEDAR at
www.sedar.com under TransCanada Corporation. Unless otherwise indicated,
"TransCanada" or "the Company" includes TransCanada Corporation and its
subsidiaries. Amounts are stated in Canadian dollars unless otherwise
indicated. Capitalized and abbreviated terms that are used but not
otherwise defined herein are identified in the Glossary of Terms
contained in TransCanada's 2008 Annual Report.
Forward-Looking Information
This MD&A may contain certain information that is forward looking and is
subject to important risks and uncertainties. The words "anticipate",
"expect", "believe", "may", "should", "estimate", "project", "outlook",
"forecast" or other similar words are used to identify such
forward-looking information. Forward-looking statements in this document
are intended to provide TransCanada shareholders and potential investors
with information regarding TransCanada and its subsidiaries, including
management's assessment of future financial and operational plans and
outlook. Forward-looking statements in this document may include, among
others, statements regarding the anticipated business prospects and
financial performance of TransCanada and its subsidiaries, expectations
or projections about the future, strategies and goals for growth and
expansion, expected and future cash flows, costs, schedules, operating
and financial results and expected impact of future commitments and
contingent liabilities. All forward-looking statements reflect
TransCanada's beliefs and assumptions based on information available at
the time the statements were made. Actual results or events may differ
from those predicted in these forward-looking statements. Factors that
could cause actual results or events to differ materially from current
expectations include, among others, the ability of TransCanada to
successfully implement its strategic initiatives and whether such
strategic initiatives will yield the expected benefits, the operating
performance of the Company's pipeline and energy assets, the availability
and price of energy commodities, capacity payments, regulatory processes
and decisions, changes in environmental and other laws and regulations,
competitive factors in the pipeline and energy sectors, construction and
completion of capital projects, labour, equipment and material costs,
access to capital markets, interest and currency exchange rates,
technological developments and the current economic conditions in North
America. By its nature, forward-looking information is subject to various
risks and uncertainties, which could cause TransCanada's actual results
and experience to differ materially from the anticipated results or
expectations expressed. Additional information on these and other factors
is available in the reports filed by TransCanada with Canadian securities
regulators and with the U.S. Securities and Exchange Commission (SEC).
Readers are cautioned to not place undue reliance on this forward-looking
information, which is given as of the date it is expressed in this
quarterly report or otherwise, and to not use future-oriented information
or financial outlooks for anything other than their intended purpose.
TransCanada undertakes no obligation to update publicly or revise any
forward-looking information, whether as a result of new information,
future events or otherwise, except as required by law.
Non-GAAP Measures
TransCanada uses the measures "comparable earnings", "comparable earnings
per share", "earnings before interest, taxes, depreciation and
amortization" (EBITDA), "comparable EBITDA", "earnings before interest
and taxes" (EBIT), "comparable EBIT" and "funds generated from
operations" in this MD&A. These measures do not have any standardized
meaning prescribed by Canadian generally accepted accounting principles
(GAAP). They are, therefore, considered to be non-GAAP measures and may
not be comparable to similar measures presented by other entities.
Management of TransCanada uses these non-GAAP measures to improve its
ability to compare financial results among reporting periods and to
enhance its understanding of operating performance, liquidity and ability
to generate funds to finance operations. These non-GAAP measures are also
provided to readers as additional information on TransCanada's operating
performance, liquidity and ability to generate funds to finance
operations.
Management uses the measures of comparable earnings, EBITDA and EBIT to
better evaluate trends in the Company's underlying operations. Comparable
earnings, comparable EBITDA and comparable EBIT comprise net income,
EBITDA and EBIT, respectively, adjusted for specific items that are
significant, but are not reflective of the Company's underlying
operations in the period. Specific items are subjective, however,
management uses its judgement and informed decision-making when
identifying items to be excluded in calculating comparable earnings,
comparable EBITDA and comparable EBIT, some of which may recur. Specific
items may include but are not limited to certain income tax refunds and
adjustments, gains or losses on sales of assets, legal and bankruptcy
settlements, and certain fair value adjustments. The table in the
"Consolidated Results of Operations" section of this MD&A presents a
reconciliation of comparable earnings, comparable EBITDA, comparable EBIT
and EBIT to Net Income. Comparable earnings per share is calculated by
dividing comparable earnings by the weighted average number of shares
outstanding for the period.
EBITDA is an approximate measure of the Company's pre-tax operating cash
flow. EBITDA comprises earnings before deducting interest and other
financial charges, income taxes, depreciation and amortization, and
non-controlling interests. EBIT is a measure of the Company's earnings
from ongoing operations. EBIT comprises earnings before deducting
interest and other financial charges, income taxes and non-controlling
interests.
Funds generated from operations comprises net cash provided by operations
before changes in operating working capital. A reconciliation of funds
generated from operations to net cash provided by operations is presented
in the "Liquidity and Capital Resources" section of this MD&A.
Financial Information Presentation
Effective January 1, 2009, TransCanada revised the information presented
in the tables of this MD&A to better reflect the operating and financing
structure of the Company. The Pipelines and Energy results summaries are
presented geographically by separating the Canadian and U.S. portions of
each segment. The Company believes this new format more clearly describes
the financial performance of its business units. The new format presents
EBITDA and EBIT as the Company believes these measures provide increased
transparency and more useful information with respect to the performance
of the Company's individual assets. Segmented information has been
retroactively reclassified to reflect these changes. These changes had no
impact on reported consolidated Net Income.
Consolidated Results of Operations
Reconciliation of Comparable Earnings, Comparable EBITDA, Comparable EBIT
and EBIT to Net Income
For the three
months ended
June 30
(unaudited)
(millions of
dollars except
per share Pipelines Energy Corporate Total
amounts) 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 (16) (17)
joint ventures
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.
(2) For the three months ended June 30
(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 share Pipelines Energy Corporate Total
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.
(2) For the six months ended June 30
(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
----------------
----------------
TransCanada's net income in second quarter 2009 was $314 million or
$0.50 per share compared to $324 million or $0.58 per share in second
quarter 2008. The decrease in net income reflects:
- 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.
Earnings per share in second quarter 2009 was further reduced primarily
due to an 11 per cent increase in the average number of shares
outstanding following the Company's share issuances of 58.4 million
common shares, 35.1 million common shares and 34.7 million common shares
in second quarter 2009, fourth quarter 2008 and second quarter 2008,
respectively.
Comparable earnings in second quarter 2009 were $319 million or $0.51 per
share compared to $316 million or $0.57 per share for the same period in
2008. Comparable earnings in second quarter 2009 and 2008 excluded $5
million of after tax unrealized losses ($7 million pre-tax) and $8
million of after tax unrealized gains ($12 million pre-tax),
respectively, resulting from changes in the fair value of proprietary
natural gas inventory and natural gas forward purchase and sale
contracts.
Comparable EBIT was $672 million in second quarter 2009 compared to $633
million in second quarter 2008. The increase in comparable EBIT of $39
million was primarily due to increases in Pipelines and Energy, partially
offset by increased support services costs in Corporate. TransCanada's
net income in the first six months of 2009 was $648 million or $1.04 per
share compared to $773 million or $1.40 per share for the same period in
2008. The $125 million decrease in net income reflects:
- 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.
Earnings per share in the first six months of 2009 was further reduced
due to an increased average number of shares outstanding following the
Company's share issuances in second quarter 2009, fourth quarter 2008 and
second quarter 2008.
Comparable earnings in the first six months of 2009 were $662 million or
$1.06 per share compared to $642 million or $1.17 per share for the same
period in 2008. Comparable earnings for the first six months of 2009 and
2008 excluded $14 million after tax ($20 million pre-tax) and $4 million
after tax ($5 million pre-tax), respectively, of net unrealized losses
resulting from changes in the fair value of proprietary natural gas
inventory and natural gas forward purchase and sale contracts. In
addition, comparable earnings in the first six months of 2008 excluded
the $152 million after tax gain on Calpine bankruptcy settlements, the
$10 million after tax gain on the GTN lawsuit settlement and the $27
million after tax writedown of Broadwater LNG project costs.
Comparable EBIT was $1.5 billion in the first six months of 2009 compared
to $1.4 billion in 2008. The increase in comparable EBIT of $67 million
was primarily due to an increase in Pipelines' comparable EBIT, partially
offset by a decrease in Energy's comparable EBIT and increased support
services costs in Corporate.
Results from each of the segments for the three and six month periods
ended June 30, 2009 are discussed further in the Pipelines, Energy and
Corporate sections of this MD&A.
Pipelines
The Pipelines business generated comparable EBIT of $489 million and $1.1
billion in the three and six month periods ended June 30, 2009,
respectively, compared to $457 million and $1.0 billion for the same
periods in 2008.
Comparable EBIT for first six months of 2008 excluded the $279 million of
gains realized by GTN and Portland for the Calpine bankruptcy settlements
and the $17 million of proceeds received by GTN from a lawsuit settlement
with a software supplier.
Pipelines Results
Three months ended Six months ended
(unaudited) June 30 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.
Net Income for Wholly Owned Canadian Pipelines
Three months ended Six months ended
(unaudited) June 30 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
---------------------------------------
---------------------------------------
Canadian Pipelines
Canadian Mainline's net income for the three and six months ended June
30, 2009 decreased $3 million and $5 million, respectively, primarily as
a result of a lower average investment base and a lower rate of return on
common equity (ROE) as determined by the National Energy Board (NEB), of
8.57 per cent in 2009 compared to 8.71 per cent in 2008, partially offset
by higher operations, maintenance and administrative (OM&A) cost savings.
The Alberta System's net income was $40 million in second quarter 2009
and $79 million for the first six months of 2009 compared to $33 million
and $65 million for the same periods in 2008. Earnings in 2009 reflect
the impact of a higher average investment base compared to 2008 due to
customer-driven expansion of this system, and the impact of a 2008-2009
settlement approved by the Alberta Utilities Commission (AUC) in December
2008.
The Alberta System's EBITDA was $177 million in second quarter 2009 and
$345 million for the first six months of 2009 compared to $179 million
and $358 million for the same periods in 2008. These decreases were
primarily due to lower revenues as a result of lower depreciation
approved in the settlement, partially offset by revenue received for
higher financial charges and increased earnings from the settlement.
U.S. Pipelines
ANR's EBITDA in the three and six months ended June 30, 2009 was $73
million and $206 million, respectively, compared to $72 million and $174
million in the same periods in 2008. The increase in second quarter and
the first six months in 2009 was primarily due to a stronger U.S. dollar
in 2009, partially offset by reduced incidental natural gas and
condensate sales primarily due to lower prices, and higher OM&A costs.
For the six months ended June 30, 2009, the increase was also due to
higher transportation and storage revenues as a result of increased
utilization and favourable pricing on existing capacity and new growth
projects.
GTN's EBITDA for the three and six months ended June 30, 2009 was $49
million and $110 million, respectively, an increase of $3 million and $12
million, respectively, from the same periods in 2008. The increases were
primarily due to a stronger U.S. dollar in 2009, partially offset by
lower revenues. EBITDA for the remainder of the U.S. Pipelines was $122
million and $302 million for the three and six months ended June 30,
2009, respectively, compared to $104 million and $245 million for the
same periods in 2008. The increase was primarily due to a stronger U.S.
dollar, increased short-term revenues for Iroquois and lower support
costs in 2009.
Operating Statistics
Six months
ended June Canadian Alberta GTN
30 Mainline(1) System(2) Foothills ANR(3) System(3)
(unaudited) 2009 2008 2009 2008 2009 2008 2009 2008 2009 2008
----------------------------------------------------------------------------
Average
investment
base
($ 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.
Capitalized Project Costs
At June 30, 2009, Other Assets included $162 million of capitalized costs
related to the Keystone pipeline system expansion to the U.S. Gulf Coast.
As at June 30, 2009, TransCanada had advanced $142 million to the
Aboriginal Pipeline Group (APG) with respect to the Mackenzie Gas
Pipeline Project (MGP). TransCanada and the other co-venture companies
involved in the MGP continue to pursue approval of the proposed project,
focusing on obtaining regulatory approval and the Canadian government's
support of an acceptable fiscal framework. Project timing continues to be
uncertain and discussions between the co-venture group and the Canadian
government are ongoing. In the event the co-venture group is unable to
reach an agreement with the government on an acceptable fiscal framework,
the parties will need to determine the appropriate next steps for the
project. For TransCanada, this may result in a reassessment of the
carrying amount of the APG advances.
Energy
Energy's comparable EBIT was $214 million in second quarter 2009 compared
to $202 million in second quarter 2008. Comparable EBIT excluded a net
unrealized loss of $7 million and an unrealized gain of $12 million in
second quarter 2009 and 2008, respectively, resulting from changes in the
fair value of proprietary natural gas inventory and natural gas forward
purchase and sale contracts.
Energy's comparable EBIT was $418 million for the first six months of
2009 compared to $433 million in same six months of 2008. Comparable EBIT
excluded net unrealized losses of $20 million and $5 million in 2009 and
2008, respectively, resulting from changes in the fair value of
proprietary natural gas inventory and natural gas forward purchase and
sale contracts. In addition, comparable EBIT in 2008 excluded the $41
million writedown of costs previously capitalized for the Broadwater LNG
project.
Energy Results
Three months ended Six months ended
(unaudited) June 30 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.
Western and Eastern Canadian Power Comparable EBITDA(1)(2)
Three months ended Six months ended
(unaudited) June 30 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.
Western and Eastern Canadian Power Operating Statistics(1)
Three months ended Six months ended
June 30 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.
Western Power's EBITDA of $59 million in second quarter 2009 decreased
$79 million compared to $138 million in second quarter 2008. The decrease
was primarily due to lower earnings from the Alberta power portfolio
resulting from lower overall realized power prices.
Western Power's EBITDA of $152 million in the first six months ended June
30, 2009 decreased $85 million compared to $237 million in the same
period in 2008 primarily due to lower overall realized power prices on
lower volumes of power sold, partially offset by lower power purchase
arrangements (PPA) costs per megawatt hour (MWh).
Lower overall realized power prices resulted in decreases of $109 million
and $189 million in Western Power's power revenues for the three and six
months ended June 30, 2009, respectively, compared to the same periods in
2008.
Eastern Power's EBITDA of $60 million and $112 million for the three and
six months ended June 30, 2009, respectively, increased $26 million and
$43 million, respectively, compared to the same periods in 2008. These
increases were primarily due to incremental earnings from Portlands
Energy and the Carleton wind farm at Cartier Wind, which went into
service in April 2009 and November 2008, respectively, as well as higher
contracted revenue from Becancour.
Plant Operating Costs and Other, which includes fuel gas consumed in
generation, of $43 million and $87 million for the three and six months
ended June 30, 2009, respectively, decreased from the same periods in
2008 primarily due to lower natural gas prices in Western Power.
Western Power manages the sale of its supply volumes on a portfolio
basis. A portion of its supply is held for sale in the spot market for
operational reasons and the amount of supply volumes eventually sold into
the spot market is dependent upon the ability to transact in forward
sales markets at acceptable contract terms. This approach to portfolio
management assists in minimizing costs in situations where Western Power
would otherwise have to purchase electricity in the open market to
fulfill its contractual sales obligations. Approximately 76 per cent of
Western Power sales volumes were sold under contract in second quarter
2009, compared to 80 per cent in second quarter 2008. To reduce its
exposure to spot market prices on uncontracted volumes, as at June 30,
2009, Western Power has entered into fixed-price power sales contracts to
sell approximately 4,800 gigawatt hours (GWh) for the remainder of 2009
and 6,100 GWh for 2010.
Eastern Power is focused on selling power under long-term contracts. As a
result, in second quarter 2009 and 2008, 100 per cent of Eastern Power
sales volumes were sold under contract and are expected to continue to be
fully sold under contract for the remainder of 2009 and 2010.
Bruce Power Results
(TransCanada's proportionate share)
(unaudited) Three months ended Six months ended
(millions of dollars unless June 30 June 30
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). Revenues also include 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.
TransCanada's proportionate share of Bruce Power's comparable EBITDA
increased $53 million to $102 million in second quarter 2009 compared to
second quarter 2008 primarily due to higher realized prices as well as
increased output and lower operating costs as a result of fewer outage
days.
TransCanada's proportionate share of Bruce A's comparable EBITDA
increased $25 million to $47 million in second quarter 2009 compared to
second quarter 2008 as a result of increased volumes and lower operating
costs due to a decrease in outage days following the rescheduling of two
planned outages from March 2009 to September 2009. Bruce A's availability
in second quarter 2009 was 100 per cent as a result of having no outage
days compared to an availability of 85 per cent and 27 outage days in the
same period in 2008.
TransCanada's proportionate share of Bruce B's comparable EBITDA
increased $28 million to $55 million in second quarter 2009 compared to
second quarter 2008 primarily due to higher realized prices resulting
from the recognition of payments received pursuant to the floor price
mechanism in Bruce B's contract with the Ontario Power Authority (OPA).
This was partially offset by lower output due to a 13 day increase in
total outage days compared to second quarter 2008.
In 2008, Bruce B did not recognize into revenue any of the support
payments received under the floor price mechanism as the annual average
spot price exceeded the average floor price. Amounts received under the
floor price mechanism in any year are subject to repayment if spot prices
in the remainder of that year increase above the floor price. With
respect to 2009, TransCanada currently expects spot prices to be less
than the floor price for the remainder of the year, therefore, no amounts
recorded in revenue in the first six months of 2009 are expected to be
repaid.
TransCanada's proportionate share of Bruce Power's Comparable EBITDA
increased $98 million to $201 million in the six months ended June 30,
2009 compared to the same period in 2008 as a result of higher realized
prices as well as higher output and lower operating costs due to fewer
outage days.
TransCanada's share of Bruce Power's generation in second quarter 2009
increased to 3,225 GWh compared to 3,134 GWh in second quarter 2008. The
Bruce Power units ran at a combined average availability of 83 per cent
in second quarter 2009, compared to 82 per cent in second quarter 2008.
In mid-April 2009, an approximate eight week planned outage of Bruce B
Unit 8 commenced. An approximate six week maintenance outage of Bruce A
Unit 4 and an approximate one month outage of Bruce A Unit 3 were
rescheduled from March 2009 to September 2009. The overall plant
availability percentage in 2009 is currently expected to be in the low
90s for the four Bruce B units and the mid 80s for the two operating
Bruce A units. Pursuant to the terms of a contract with the OPA, all of
the output from Bruce A in second quarter 2009 was sold at a fixed price
of $64.45 per MWh (before recovery of fuel costs from the OPA) compared
to $63.00 per MWh in second quarter 2008. All output from the Bruce B
Units 5 to 8 were subject to a floor price of $48.76 per MWh in second
quarter 2009 and $47.66 per MWh in second quarter 2008. Both the Bruce A
and Bruce B contract prices are adjusted annually for inflation on April
1.
At June 30, 2009, Bruce B had sold forward approximately 1,900 GWh and
2,700 GWh, representing TransCanada's proportionate share, for the
remainder of 2009 and the year 2010, respectively. To reduce its exposure
to spot prices, Bruce B had entered into most of these fixed price
contracts in 2006 to 2008 when the spot price exceeded the floor price.
Under these 'contracts for differences', Bruce B receives the difference
between the contract price and spot price on output sold forward under
contract. As a result, Bruce B's realized price of $70 per MWh and $63
per MWh in the three and six months ended June 30, 2009, respectively,
reflects revenues recognized from both the floor price mechanism and
contract sales, compared to $56 per MWh in the same periods in 2008 in
which no revenues were recognized under the floor price mechanism.
As at June 30, 2009, Bruce A had incurred $2.9 billion in costs for the
refurbishment and restart of Units 1 and 2, and approximately $0.2
billion for the refurbishment of Units 3 and 4.
U.S. Power Comparable EBITDA(1)(2)
Three months ended Six months ended
(unaudited) June 30 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.
U.S. Power Sales Operating Statistics(1)
Three months ended Six months ended
June 30 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.
U.S. Power's EBITDA for the three months ended June 30, 2009 was $65
million, an increase of $15 million from the same period in 2008. Second
quarter 2009 results reflect EBITDA from the Ravenswood facility acquired
in August 2008 and the positive impact of the stronger U.S. dollar in
2009, partially offset by lower realized power prices in the New England
market. For the six months ended June 30, 2009, U.S. Power's EBITDA of
$95 million decreased $10 million from the same period in 2008, primarily
due to decreased water flows from the TC Hydro generation assets in
second quarter 2009 compared to the considerably higher than average
levels experienced in 2008, and lower realized prices in the New England
market, partially offset by a stronger U.S. dollar.
U.S. Power's power revenues for the three and six months ended June 30,
2009 of $321 million and $661 million, respectively, increased from $215
million and $441 million for the same periods in 2008 due to incremental
revenue from the August 2008 acquisition of Ravenswood and the positive
impact of the stronger U.S. dollar.
Power Commodity Purchases Resold of $117 million and $272 million for the
three and six months ended June 30, 2009, respectively, increased from
$105 million and $239 million compared to the same periods in 2008
primarily due to the impact of the stronger U.S. dollar in 2009.
Other Revenues and Other Commodity Purchases Resold of $78 million and
$56 million, respectively, decreased in second quarter 2009 compared to
second quarter 2008 as a result of decreased natural gas prices,
partially offset by an increase in the volume of natural gas sold and
purchased, and a stronger U.S. dollar. The decrease in Other Revenues was
also partially offset by incremental revenues earned related to a steam
generating facility at Ravenswood.
Other Revenue and Other Commodity Purchases Resold of $250 million and
$187 million, respectively, increased $73 million and $25 million,
respectively, in the first six months ended June 30, 2009 primarily due
to higher volumes of natural gas sold and purchased, and the impact of a
stronger U.S. dollar, partially offset by a decrease in natural gas
prices. In addition, Other Revenues also increased as a result of
incremental revenues earned related to the steam generating facility at
Ravenswood.
Plant Operating Costs and Other, which includes fuel gas consumed in
generation, of $150 million and $334 million for the three and six months
ended June 30, 2009, respectively, increased from $49 million and $93
million compared to the same periods in 2008 due to the incremental costs
from Ravenswood.
In the three and six months ended June 30, 2009, 29 per cent and 28 per
cent, respectively, of power sales volumes were sold into the spot
market, compared to three and four per cent for the same periods in 2008,
as there were no power sales contracts in place for Ravenswood extending
beyond 2008 at the time the facility was acquired. U.S. Power is focused
on selling the majority of its power under contract to wholesale,
commercial and industrial customers, while managing a portfolio of power
supplies sourced from its own generation and wholesale power purchases.
To reduce its exposure to spot market prices on uncontracted volumes, as
at June 30, 2009, U.S. Power had entered into fixed-price power sales
contracts to sell approximately 3,800 GWh for the remainder of 2009 and
8,100 GWh for 2010, although certain contracted volumes are dependent on
customer usage levels. Actual amounts contracted in future periods will
depend on market liquidity and other factors.
Natural Gas Storage
Natural Gas Storage's comparable EBITDA for the three and six month
periods ended June 30, 2009 was $34 million and $70 million,
respectively, compared to $6 million and $73 million for the same periods
in 2008. The $28 million increase in EBITDA in second quarter 2009 was
primarily due to a lower cost of proprietary natural gas sold at the
Edson facility as well as increased third party storage revenues. The $3
million decrease in EBITDA for the six months ended June 30, 2009 was due
to lower withdrawal activity and reduced sales of proprietary natural gas
at the Edson facility compared to the same period in 2008.
Comparable EBITDA excluded net unrealized losses of $7 million and $20
million in the three and six months ended June 30, 2009, respectively
(2008 - $12 million gain and $5 million loss), resulting from changes in
the fair value of proprietary natural gas inventory in storage and
natural gas forward purchase and sale contracts. TransCanada manages its
proprietary natural gas storage earnings by simultaneously entering into
a forward purchase of natural gas for injection into storage and an
offsetting forward sale of natural gas for withdrawal at a later period,
thereby locking in future positive margins and effectively eliminating
exposure to price movements of natural gas. Fair value adjustments are
recorded in each period on proprietary natural gas held in storage and
these forward contracts are not representative of the amounts that will
be realized on settlement. Beginning in second quarter 2009, the fair
value of proprietary natural gas inventory held in storage is measured
using a weighted average of forward prices for the following four months
less selling costs. Previously the inventory was measured using the
one-month forward price. The impact of this change on EBITDA for the
three and six months ended June 30, 2009 was insignificant. Depreciation
and Amortization
Depreciation and Amortization for the three and six months ended June 30,
2009 of $87 million and $173 million, respectively, increased $29 million
and $59 million, respectively, compared with the same periods in 2008,
primarily due to the acquisition of Ravenswood in August 2008.
Corporate
Corporate EBIT losses for the three and six months ended June 30, 2009
were $31 million and $61 million, respectively, compared to losses of $26
million and $48 million for the same periods in 2008. These decreases in
Corporate EBIT were primarily due to higher support services costs in
2009, reflecting a growing asset base.
Other Income Statement Items
Interest Expense
Three months ended Six months ended
(unaudited) June 30 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.
Interest Expense for second quarter 2009 increased $73 million to $259
million from $186 million in second quarter 2008. Interest Expense for
the six months ended June 30, 2009, increased $150 million to $554
million from $404 million for the six months ended June 30, 2008. The
increases were primarily due to new debt issues of US$1.5 billion and
$500 million in August 2008, US$2.0 billion in January 2009 and $700
million in February 2009. In addition, U.S. dollar-denominated interest
expense increased due to the impact of a stronger U.S. dollar. These
increases were partially offset by increased capitalization of interest
to finance the Company's larger capital spending program in 2009.
On a consolidated basis, the positive impact of a stronger U.S. dollar on
U.S. Pipelines and Energy EBIT is almost fully offset by the net negative
impact on U.S. dollar interest expense and other income statement items,
thereby effectively reducing the Company's net exposure to changes in
foreign exchange.
Interest Income and Other was $34 million and $56 million for the three
and six month periods ended June 30, 2009, respectively, compared to $25
million and $36 million for the same periods in 2008. The increase of $9
million and $20 million for the three and six months ended June 30, 2009,
respectively, was primarily due to higher gains from changes in the fair
value of derivatives used to manage the Company's exposure to foreign
exchange rate fluctuations and the positive impact of a stronger U.S.
dollar. Partially offsetting these increases was reduced interest income
as a result of lower interest rates in 2009.
Income Taxes were $97 million in second quarter 2009 compared to $126
million for the same period in 2008. Income Taxes for the six months
ended June 30, 2009 were $213 million compared to $378 million for the
same period in 2008. The decreases were primarily due to reduced
earnings, higher income tax rate differentials and other positive income
tax adjustments in 2009.
Non-Controlling Interests were $13 million for second quarter 2009
compared to $17 million for the same period in 2008. The decrease of $4
million was primarily due to lower earnings from PipeLines LP.
Non-Controlling Interests of $48 million for the first six months of
2009, decreased $40 million compared to $88 million for the same period
in 2008, primarily due to the non-controlling interests' portion of
Portland's Calpine bankruptcy settlement in first quarter 2008.
Liquidity and Capital Resources
Global Market Conditions
Despite continued uncertainty in global financial markets, TransCanada's
financial position remains sound and consistent with recent years as does
its ability to generate cash in the short and long term to provide
liquidity, maintain financial capacity and flexibility, as well as
provide for planned growth. TransCanada's liquidity position remains
solid, underpinned by highly predictable cash flow from operations,
significant cash balances on hand from recent debt and equity issues, as
well as committed revolving bank lines of US$1.0 billion, $2.0 billion
and US$300 million, maturing in November 2010, December 2012 and February
2013, respectively. To date, no draws have been made on these facilities
as TransCanada has maintained continuous access to the Canadian
commercial paper market on competitive terms. An additional approximate
$230 million of capacity remains available on Canadian and U.S. dollar
committed bank facilities at TransCanada-operated affiliates with
maturity dates from 2010 through 2012. In addition, common shares are
expected to be issued under the Company's Dividend Reinvestment and Share
Purchase Plan (DRP) in lieu of making cash dividend payments.
At June 30, 2009, the Company held cash and cash equivalents of $3.5
billion compared to $1.3 billion at December 31, 2008. The increase in
cash and cash equivalents was primarily due to proceeds from the issuance
of common shares in second quarter 2009 and long-term debt in first
quarter 2009.
Operating Activities
Funds Generated from Operations(1)
Three months ended Six months ended
(unaudited) June 30 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.
Net Cash Provided by Operations increased $435 million and $351
million for the three and six months ended June 30, 2009 compared to the
same periods in 2008, primarily due to decreases in operating working
capital. Funds Generated from Operations for the three and six months
ended June 30, 2009, were $692 million and $1.5 billion, respectively,
compared to $676 million and $1.6 billion for the same periods in 2008.
The decrease for the six months ended June 30, 2009 was primarily due to
$152 million of after tax proceeds received in 2008 from the Calpine
bankruptcy settlement.
Investing Activities
Acquisitions, net of cash acquired, were $115 million in second quarter
2009 (2008 - $2 million) and $249 million (2008 - $4 million) for the six
months ended June 30, 2009. The acquisitions included the increase in
ownership interest in Keystone pursuant to an agreement with
ConocoPhillips that closed in December 2008.
TransCanada remains committed to executing its previously announced $21
billion capital expenditure program over the next four years. For the
three and six months ended June 30, 2009, capital expenditures totalled
$1.3 billion and $2.4 billion, respectively (2008 - $633 million and $1.1
billion), primarily related to the Keystone pipeline system, expansion of
the Alberta System, refurbishment and restart of Bruce A Units 1 and 2,
and construction of Kibby Wind, Halton Hills, Coolidge and Bison.
Financing Activities
On 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 an underwriters' over-allotment option.
Proceeds from the common share offering and the 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 offering, the Company is well
positioned to fund its existing capital program through its growing
internally-generated cash flow, its DRP 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 a greater role for
PipeLines LP, in the financing of its capital program.
As a result of the June 2009 common share issue, TransCanada has
effectively exhausted the $3.0 billion base equity shelf prospectus filed
in July 2008. The Company expects to file a new base equity shelf
prospectus in the normal course in third quarter 2009.
In the three and six months ended June 30, 2009, TransCanada issued nil
and $3.1 billion, respectively, (2008 - nil and $112 million), and
retired $18 million and $500 million, respectively (2008 - $379 million
and $773 million), of long-term debt. TransCanada's notes payable
increased $233 million and decreased $684 million in the three and six
months ended June 30, 2009, respectively, compared to increases of $754
million and $724 million for the same periods in 2008.
On April 23, 2009, TCPL filed a $2.0 billion Canadian Medium-Term Notes
shelf prospectus to replace a March 2007 $1.5 billion Canadian
Medium-Term Notes shelf prospectus, which expired in April 2009. No
amounts have been issued under this shelf prospectus. In February 2009,
TCPL issued Medium-Term Notes of $300 million and $400 million maturing
in February 2014 and February 2039, respectively, and bearing interest at
5.05 per cent and 8.05 per cent, respectively. These notes were issued
under the $1.5 billion debt shelf prospectus filed in March 2007.
In January 2009, TCPL issued Senior Unsecured Notes of US$750 million and
US$1.25 billion maturing in January 2019 and January 2039, respectively,
and bearing interest at 7.125 per cent and 7.625 per cent, respectively.
These notes were issued under a US$3.0 billion debt shelf prospectus
filed in January 2009, which now has capacity of US$1.0 billion remaining.
Dividends
On July 30, 2009, TransCanada's Board of Directors declared a quarterly
dividend of $0.38 per share for the quarter ending September 30, 2009 on
the Company's outstanding common shares. It is payable on October 30,
2009 to shareholders of record at the close of business on September 30,
2009.
TransCanada's Board of Directors also approved the issuance of common
shares from treasury at a three per cent discount under TransCanada's DRP
for the dividends payable on October 30, 2009. The Company reserves the
right to alter the discount or return to purchasing shares on the open
market at any time. In the three and six months ended June 30, 2009,
TransCanada issued 1.4 million and 3.5 million common shares,
respectively, under its DRP, in lieu of making cash dividend payments of
$42 million and $109 million, respectively.
Significant Accounting Policies and Critical Accounting Estimates
To prepare financial statements that conform with Canadian GAAP,
TransCanada is required to make estimates and assumptions that affect
both the amount and timing of recording assets, liabilities, revenues and
expenses since the determination of these items may be dependent on
future events. The Company uses the most current information available
and exercises careful judgement in making these estimates and assumptions.
TransCanada's significant accounting policies and critical accounting
estimates have remained unchanged since December 31, 2008. For further
information on the Company's accounting policies and estimates refer to
the MD&A in TransCanada's 2008 Annual Report.
Changes in Accounting Policies
The Company's accounting policies have not changed materially from those
described in TransCanada's 2008 Annual Report except as follows:
2009 Accounting Changes
Rate-Regulated Operations
Effective January 1, 2009, the temporary exemption was withdrawn from the
Canadian Institute of Chartered Accountants (CICA) Handbook Section 1100
"Generally Accepted Accounting Principles", which permitted the
recognition and measurement of assets and liabilities arising from rate
regulation. In addition, Section 3465 "Income Taxes" was amended to
require the recognition of future income tax assets and liabilities for
rate-regulated entities. The Company chose to adopt accounting policies
consistent with the U.S. Financial Accounting Standards Board's Financial
Accounting Standard (FAS) 71 "Accounting for the Effects of Certain Types
of Regulation". As a result, TransCanada retained its current method of
accounting for its rate-regulated operations, except that TransCanada is
required to recognize future income tax assets and liabilities, instead
of using the taxes payable method, and records an offsetting adjustment
to regulatory assets and liabilities. As a result of adopting this
accounting change, additional future income tax liabilities and a
regulatory asset in the amount of $1.4 billion were recorded January 1,
2009 in each of Future Income Taxes and Other Assets, respectively.
Adjustments to the 2009 financial statements have been made in accordance
with the transitional provisions for Section 3465, which required a
cumulative adjustment in the current period to future income taxes and a
regulatory asset. Restatement of prior periods' financial statements was
not permitted under Section 3465.
Intangible Assets
Effective January 1, 2009, the Company adopted CICA Handbook Section 3064
"Goodwill and Intangible Assets", which replaced Section 3062 "Goodwill
and Other Intangible Assets". Section 3064 gives guidance on the
recognition of intangible assets as well as the recognition and
measurement of internally developed intangible assets. In addition,
Section 3450 "Research and Development Costs" was withdrawn from the
Handbook. Adopting this accounting change did not have a material effect
on the Company's financial statements.
Credit Risk and the Fair Value of Financial Assets and Financial
Liabilities
Effective January 1, 2009, the Company adopted the accounting provisions
of Emerging Issues Committee (EIC) Abstract EIC 173, "Credit Risk and the
Fair Value of Financial Assets and Financial Liabilities". Under EIC 173
an entity's own credit risk and the credit risk of its counterparties is
taken into account in determining the fair value of financial assets and
financial liabilities, including derivative instruments. Adopting this
accounting change did not have a material effect on the Company's
financial statements.
Future Accounting Changes
International Financial Reporting Standards
The CICA's Accounting Standards Board announced that Canadian publicly
accountable enterprises are required to adopt International Financial
Reporting Standards (IFRS), as issued by the International Accounting
Standards Board (IASB), effective January 1, 2011. The Company will
prepare its financial statements under IFRS commencing January 1, 2011.
TransCanada has developed a conversion plan that is overseen by its IFRS
Implementation and Steering Committees. The plan includes identifying
resources and training requirements, analyzing the impact of key
differences between Canadian GAAP and IFRS, and developing a phased
approach to conversion implementation. The Company's conversion project
is discussed in further detail in its 2008 Annual Report. TransCanada
continues to progress its conversion project by scheduling training
sessions and IFRS updates for employees, reviewing new IFRS developments
and assessing the impact that significant differences between Canadian
GAAP and IFRS may have on TransCanada.
Under existing Canadian GAAP, TransCanada follows specific accounting
policies unique to a rate-regulated business. TransCanada is actively
monitoring developments regarding potential future guidance on the
applicability of certain aspects of rate-regulated accounting under IFRS.
Developments in this area could have a significant effect on the scope of
the Company's IFRS project and on TransCanada's financial results under
IFRS. On July 23, 2009, the IASB issued an exposure draft "Rate-regulated
Activities" and the Company is assessing the impact of this exposure
draft on TransCanada.
The impact of the adoption of IFRS on the Company's consolidated
financial statements and accounting systems is currently being evaluated.
At the current stage of its IFRS project, TransCanada cannot reasonably
determine the full impact that adopting IFRS would have on its financial
position and future results.
Financial Instruments Disclosure
The CICA implemented revisions to Handbook Section 3862 "Financial
Instruments - Disclosures" for fiscal years ending after September 30,
2009. These revisions are intended to align the disclosure requirements
for financial instruments to the maximum extent possible with the
disclosure required under IFRS. These revisions require additional
disclosure based on a three level hierarchy that reflects the
significance of inputs used in measuring fair value. Fair values of
assets and liabilities included in Level 1 are determined by reference to
quoted prices in active markets for identical assets and liabilities.
Fair values of assets and liabilities included in Level 2 include
valuations using inputs other than quoted prices for which all
significant outputs are observable, either directly or indirectly. Fair
values of assets and liabilities included in Level 3 valuations are based
on inputs that are unobservable and significant to the overall fair value
measurement. These changes will be applied by TransCanada effective
December 31, 2009.
Contractual Obligations
On June 16, 2009, the Company entered into an agreement to acquire
ConocoPhillips' remaining interest in 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.
In addition, TransCanada will also assume responsibility for
ConocoPhillips' share of the capital investment required to complete the
project, which is expected to result in an incremental commitment of
US$1.7 billion through the end of 2012.
Other than the commitments discussed above and obligations for future
debt and interest payments relating to debt issuances and redemptions
discussed in the "Financing Activities" section of this MD&A, there have
been no other material changes to TransCanada's contractual obligations
from December 31, 2008 to June 30, 2009, including payments due for the
next five years and thereafter. For further information on these
contractual obligations, refer to the MD&A in TransCanada's 2008 Annual
Report.
Financial Instruments and Risk Management
TransCanada continues to manage and monitor its exposure to market,
counterparty credit and liquidity risk.
Counterparty Credit and Liquidity Risk
TransCanada's maximum counterparty credit exposure with respect to
financial instruments at the balance sheet date, without taking into
account security held, consisted primarily of the carrying amount, which
approximates fair value, of non-derivative financial assets, such as
accounts receivable, as well as the fair value of derivative assets.
Letters of credit and cash are the primary types of security provided to
support these amounts. The Company does not have significant
concentrations of counterparty credit risk with any individual
counterparties and the majority of counterparty credit exposure is with
counterparties who are investment grade. At June 30, 2009, there were no
significant amounts past due or impaired. As the uncertainty in the
global financial markets persists, TransCanada continues to closely
monitor and reassess the creditworthiness of its counterparties. This has
resulted in TransCanada reducing or mitigating its exposure to certain
counterparties where it is deemed warranted and permitted under
contractual terms. As part of its ongoing operations, TransCanada must
balance its market and counterparty credit risks when making business
decisions.
The Company continues to manage its liquidity risk by ensuring sufficient
cash and credit facilities are available to meet its operating and
capital expenditure obligations when due, under both normal and stressed
economic conditions. Further discussion of the Company's ability to
manage its cash and credit facilities is provided in the "Liquidity and
Capital Resources" section in this MD&A.
Natural Gas Inventory
At June 30, 2009, the fair value of proprietary natural gas inventory
held in storage as measured using a weighted average of forward prices
for the following four months less selling costs was $44 million
(December 31, 2008 - $76 million). Prior to second quarter 2009,
inventory was measured using the one-month forward price. The impact of
this change was insignificant.
The change in fair value of proprietary natural gas inventory in the
three and six months ended June 30, 2009 resulted in pre-tax net
unrealized losses of $6 million and $29 million, respectively, which were
recorded as a decrease to Revenues and Inventories (gains of $42 million
and $102 million for the three and six months ended June 30, 2008). The
net change in fair value of natural gas forward purchase and sales
contracts in the three and six months ended June 30, 2009 resulted in a
pre-tax net unrealized loss of $1 million and a pre-tax net unrealized
gain of $9 million (losses of $30 million and $107 million for the three
and six months ended June 30, 2008), respectively, which were included in
Revenues.
Net Investment in Self-Sustaining Foreign Operations
The Company hedges its net investment in self-sustaining foreign
operations with U.S. dollar-denominated debt, cross-currency swaps and
foreign exchange forward contracts and options. At June 30, 2009, the
Company had designated as a net investment hedge U.S. dollar-denominated
debt with a carrying value of $8.8 billion (US$7.6 billion) and a fair
value of $9.2 billion (US$7.9 billion). At June 30, 2009, Deferred
Amounts included $124 million for the fair value of derivatives used to
hedge the Company's net U.S. dollar investment in foreign operations.
Information for the derivatives used to hedge the Company's net
investment in its self-sustaining foreign operations is as follows:
Derivatives Hedging Net Investment in Self-Sustaining Foreign Operations
June 30, 2009 December 31, 2008
----------------------------------------
Notional Notional
Asset/(Liability) Fair or Fair or
(unaudited) Value Principal Value Principal
(millions of dollars) (1) Amount (1) Amount
----------------------------------------------------------------------------
U.S. dollar cross-currency swaps U.S. U.S.
(maturing 2009 to 2014)(2) (116) 1,450 (218) 1,650
U.S. dollar forward foreign
exchange contracts U.S. U.S.
(maturing 2009)(2) (3) 100 (42) 2,152
U.S. dollar options U.S. U.S.
(maturing 2009)(2) (5) 300 6 300
---------------------------------------
U.S. U.S.
(124) 1,850 (254) 4,102
---------------------------------------
---------------------------------------
(1) Fair values equal carrying values.
(2) As at June 30, 2009.
Non-Derivative Financial Instruments Summary
The carrying and fair values of non-derivative financial instruments were as
follows:
June 30, 2009 December 31, 2008
----------------------------------------
(unaudited) Carrying Fair Carrying Fair
(millions of dollars) Amount Value Amount 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
Information for the Company's derivative financial instruments, excluding
hedges of the Company's net investment in self-sustaining foreign
operations, is as follows:
June 30, 2009
(unaudited)
(all amounts in
millions
unless otherwise Natural Oil Foreign
indicated) Power Gas Products 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) - - - - -
227/U.S.
Cross-currency - - - 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- 2009- 2009- 2009-2012 2009-
2014 2014 2010 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- 2009- n/a 2009-2013 2010-
2015 2012 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 Natural Oil Foreign
indicated) Power Gas Products 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- 2009- 2009 2009- 2009-
2014 2011 2012 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. U.S.
15 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- 2009- n/a 2009- 2009-
2014 2011 2013 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.
Balance Sheet Presentation of Derivative Financial Instruments
The fair value of the derivative financial instruments in the Company's
Balance Sheet was as follows:
(unaudited) June 30, December 31,
(millions of dollars) 2009 2008
----------------------------------------------------------------------------
Current
Other current assets 445 318
Accounts payable (445) (298)
Long-term
Other assets 165 191
Deferred amounts (396) (694)
------------------------
------------------------
Other Risks
Additional risks faced by the Company are discussed in the MD&A in
TransCanada's 2008 Annual Report. These risks remain substantially
unchanged since December 31, 2008.
Controls and Procedures
As of June 30, 2009, an evaluation was carried out under the supervision
of, and with the participation of management, including the President and
Chief Executive Officer and the Chief Financial Officer, of the
effectiveness of TransCanada's disclosure controls and procedures as
defined under the rules adopted by the Canadian securities regulatory
authorities and by the SEC. Based on this evaluation, the President and
Chief Executive Officer and the Chief Financial Officer concluded that
the design and operation of TransCanada's disclosure controls and
procedures were effective as at June 30, 2009.
During the recent fiscal quarter, there have been no changes in
TransCanada's internal control over financial reporting that have
materially affected, or are reasonably likely to materially affect,
TransCanada's internal control over financial reporting.
During second quarter 2009, TransCanada completed its integration of
Ravenswood's internal controls over financial reporting.
Outlook
The economic turmoil and deterioration of financial markets in North
America is continuing to have a slowing effect on certain aspects of the
North American economy. TransCanada does not expect this to have a
material effect on the Company's financial position, access to capital
markets, committed projects or corporate strategy.
Since the disclosure in TransCanada's 2008 Annual Report, the Company's
earnings outlook for 2009 has declined due to the negative impact of
reduced market prices for power on Energy's results. With respect to the
Pipelines segment, although the global economic downturn has an impact on
throughput on certain pipelines and on some drilling activities, the
short-term financial outlook for the Company's Pipelines segment is not
expected to be materially impacted as the pipeline assets are generally
underpinned by contracts or earn a regulated rate of return. TransCanada
completed the issuance of $1.8 billion of common shares in second quarter
2009, $3.1 billion of long-term debt in first quarter 2009 and $1.1
billion of common shares at the end of 2008. While these offerings will
impact future net income and earnings per share through carrying costs
and dilution, when combined with $1.9 billion of cash provided by
operations in the first half of 2009, they have contributed to a cash
balance of $3.5 billion at June 30, 2009 and provided most of the
necessary financing for the Company's 2009 capital expenditure program
and acquisition of the remaining interest in Keystone. This strategy of
strengthening TransCanada's liquidity and financial position through its
ability to successfully access capital markets in very volatile and
uncertain economic times has reduced the Company's future financing risk
around its committed growth program. For further information on outlook,
refer to the MD&A in TransCanada's 2008 Annual Report.
Since December 31, 2008, there have been no changes to TransCanada's
credit ratings. TransCanada's issuer rating assigned by Moody's Investors
Service (Moody's) is Baa1 with a stable outlook. TransCanada PipeLines
Limited's senior unsecured debt is rated A with a stable outlook by DBRS,
A3 with a stable outlook by Moody's and A- with a stable outlook by
Standard and Poor's.
Recent Developments
Pipelines
Keystone
On June 16, 2009, TransCanada announced an agreement to acquire
ConocoPhillips' remaining interest in Keystone for approximately US$550
million plus the assumption of approximately US$200 million of short-term
indebtedness. The purchase price reflects ConocoPhillips' capital
contributions to date and includes an allowance for funds used during
construction. TransCanada will also assume responsibility for
ConocoPhillips' share of the capital investment required to complete the
project, resulting in an incremental commitment of approximately US$1.7
billion through the end of 2012. The transaction is expected to close in
third quarter 2009, subject to the receipt of certain regulatory
approvals. At June 30, 2009, TransCanada's equity ownership in the
Keystone partnerships was 77 per cent.
The first phase of Keystone is currently under construction. It will
extend 3,456 km (2,148 miles) from Hardisty, Alberta to serve markets in
Wood River and Patoka, Illinois, and have an initial nominal capacity of
435,000 barrels per day (bbl/d). Commissioning of this segment is
expected to commence in late 2009 with commercial operations to follow in
early 2010. At July 30, 2009, the first phase was approximately 80 per
cent complete. The pipeline is expected to subsequently be expanded to a
nominal capacity of 590,000 bbl/d and extend to Cushing, Oklahoma.
Commissioning of the Cushing segment is expected to commence in late 2010.
Keystone is also currently seeking the necessary regulatory approvals in
Canada and the U.S. to construct and operate an expansion and extension
of the pipeline that will provide additional capacity of 500,000 bbl/d
from Western Canada to the U.S. Gulf Coast in 2012. This Keystone
expansion will extend 2,720 km (1,690 miles) from Hardisty, Alberta to a
delivery point near existing terminals in Port Arthur, Texas.
Construction of the expansion facilities is anticipated to commence in
2010 following the receipt of the necessary regulatory approvals.
The total capital cost of Keystone is expected to be approximately US$12
billion. Approximately US$3 billion has been spent to date with the
remaining approximately US$9 billion expected to be incurred by the end
of 2012. Capital costs related to the construction of Keystone are
subject to capital cost risk-and-reward sharing mechanisms with its
customers.
Keystone is expected to begin generating EBITDA in first quarter 2010
when commercial operations to Wood River and Patoka, Illinois commence,
with EBITDA increasing through 2011 and 2012 as subsequent phases are
placed in service. Based on current long-term commitments of 910,000
bbl/d, Keystone is expected to generate EBITDA of approximately US$1.2
billion in 2013, its first full year of commercial operation serving both
the U.S. Midwest and Gulf Coast markets. If volumes increase to 1.1
million bbl/d, the full commercial design of the system, Keystone would
generate approximately US$1.5 billion of annual EBITDA. In the future,
Keystone can be economically expanded from 1.1 million bbl/d to 1.5
million bbl/d in response to additional market demand.
Alaska
On June 11, 2009, 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 U.S., including substantial
revenues, jobs, business opportunities and new, long-term stable supplies
of natural gas.
The Alaska pipeline project continues to move forward with project
development, including engineering, environmental reviews, Alaska Native
and Canadian Aboriginal engagement, and commercial work to conclude an
initial binding open season by July 2010. Subject to the completion of a
successful open season, construction of the approximately 2,700 km (1,700
miles), 4.5 Bcf per day pipeline would begin in 2016, once environmental
and regulatory approvals are received, and the pipeline would begin
transporting natural gas in 2018.
North Baja
On July 1, 2009, TransCanada sold the North Baja pipeline to PipeLines
LP. As part of the transaction, TransCanada agreed to amend its incentive
distribution rights with PipeLines LP. TransCanada received aggregate
consideration totalling approximately US$395 million from PipeLines LP,
including approximately US$200 million in cash and 6,371,680 common units
of PipeLines LP. PipeLines LP utilized US$170 million of its US$250
million committed and available bank facility to fund this transaction.
TransCanada's ownership in PipeLines LP increased to 42.6 per cent as a
result of this transaction. The Company will continue to operate the
North Baja pipeline.
Alberta System
The Company has initiated discussions with stakeholders to transfer the
Alberta System's 2008 - 2009 Revenue Requirement Settlement to NEB
jurisdiction. Following these discussions, TransCanada will apply to the
NEB for approval of final 2009 tolls.
In April 2009, TransCanada submitted an application to the NEB for
approval to construct and operate the Groundbirch pipeline, which
comprises a 77 km (48 miles) natural gas pipeline and related facilities
including meter stations and valve sites. 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.
The oral part of the hearing is scheduled to begin November 17, 2009.
Subject to regulatory approvals, construction of the Groundbirch pipeline
is expected to commence in July 2010 with final completion anticipated in
November 2010.
In May 2009, TransCanada filed a Project Description 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.
Guadalajara
In May 2009, TransCanada entered into a contract to build, own and
operate a US$320 million pipeline in Mexico, which is supported by a
25-year contract for its entire capacity with Comision Federal de
Electricidad, Mexico's state-owned electric company.
The proposed Guadalajara pipeline will extend 310 km (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.
TQM
In June 2009, the NEB approved TQM's final tolls for 2007 and 2008,
consisting of a 6.4 per cent after-tax weighted average cost of capital
on its cost of capital application for the years 2007 and 2008. This
decision equates to a 9.85 per cent return on 40 per cent deemed common
equity in 2007 and a 9.75 per cent return on 40 per cent deemed common
equity in 2008. The decision granted TQM an aggregate return on capital,
leaving it to TQM to choose its optimal capital structure. TQM expects to
recover the variance between interim and final tolls for 2007 and 2008 in
third quarter 2009. The net earnings impact related to the variance was
recorded by TQM in first quarter 2009.
Ventures LP
In May 2009, the AUC announced that it intends to seek an Order in
Council allowing it to set rates on the Ventures LP pipeline. Ventures LP
has initiated appeal proceedings of this decision and the application to
the court is expected to commence in third quarter 2009.
Bison
The Bison pipeline project is expected to be in service November 2010.
The regulatory approval process and the engineering and procurement work
are progressing as planned.
Review of NEB ROE Formula
In May 2009, the NEB received comments on whether it should initiate a
multi-pipeline review of the RH-2-94 Decision pursuant to the National
Energy Board Act (Canada) (NEB Act), which established an ROE formula
tied to 10 year and 30 year Government of Canada bond rates, that has
formed the basis of determining tolls for pipelines under NEB
jurisdiction since January 1, 1995. Based on comments submitted, the NEB
has decided to initiate a review of this decision by seeking comments on
the continuing applicability of the decision by September 18, 2009.
TransCanada's position, included in its May 2009 letter to the NEB, is
that the decision should be rescinded on a prospective basis. Land
Matters Consultation Initiative
In May 2009, the NEB issued its RH-2-2008 Decision on the Land Matters
Consultation Initiative Stream 3 with respect to financial issues related
to pipeline abandonment. All pipeline companies regulated under the NEB
Act will be required to comply with the framework and action plan set out
in the decision. The NEB's goal is to have pipeline companies begin
collecting and setting aside funds to cover future abandonment costs no
later than mid-2014. There are several filing deadlines in the action
plan with which NEB regulated pipeline companies have to comply,
including deadlines for the preparation and filing of an estimate of the
abandonment costs, developing a proposal for collection of funds through
tolls or some other satisfactory method and developing a proposed process
to set aside the funds collected. As a result of this decision,
TransCanada has initiated a project to estimate the abandonment costs on
its NEB regulated pipelines to be filed with the NEB for approval by May
31, 2011.
Energy
Bruce Power
On July 6, 2009, Bruce Power and the OPA amended certain terms and
conditions of commercial agreements in place between the two parties.
Payments received pursuant to the Bruce B floor price mechanism were
previously subject to repayment during the entire term of the contract,
dependent on future periods' spot prices. The contract with the OPA was
amended such that, beginning in 2009, annual payments received will not
be subject to repayment in future years.
Other changes to the contract with the OPA include the removal of a
support payment cap for Bruce A. The cumulative support payments received
by Bruce A, which are equal to the difference between the fixed prices
under the OPA contract and spot market prices, were originally capped at
$575 million until both Units 1 and 2 were restarted. Under the
amendment, should either of the restarted Units 1 and 2 not be placed
into commercial service by December 31, 2011, Bruce A will receive spot
prices on all of its output until the restart of both units is complete,
after which Bruce A prices will return to the then prevailing contract
levels.
The OPA contract was also amended, commencing July 6, 2009, to provide
for deemed generation payments to Bruce Power at contract prices under
circumstances when Bruce Power generation is reduced due to system
curtailments on the Independent Electricity System Operator controlled
grid in Ontario.
Additionally, the capital cost sharing mechanism for the restart and
refurbishment of Bruce A Units 1 and 2 was amended such that the OPA will
not share in any cost overruns over $3.4 billion. Previously the OPA was
responsible for 25 per cent of cost overruns above $3.4 billion through a
future adjustment to the fixed price paid to Bruce Power for power
generated by the Bruce A units. Although Bruce Power estimates the total
capital costs to be $3.4 billion, the Company's current view is that
costs may exceed that amount by up to ten per cent. Units 1 and 2 are
expected to return to service by the end of 2010.
Cartier Wind
On June 10, 2009, the Government of Quebec approved the construction of
the 212 MW Gros-Morne and 58 MW Montagne-Seche wind farms. Both wind
farms are expected to be operational by 2012, representing an investment
of approximately $340 million. These are the fourth and fifth
Quebec-based wind farms either in place or under development by Cartier
Wind, which is 62 per cent owned by TransCanada.
Kibby Wind
TransCanada continues to advance construction on the Kibby Wind power
project, including the installation of 22 turbines which are expected to
be completed in the summer of 2009. Kibby Wind is expected to have the
capacity to produce 132 MW of power when complete, with commissioning of
the first phase of the project to begin in late 2009.
Coolidge
TransCanada expects to begin construction of the US$500 million Coolidge
generating station in August 2009. The 575 MW, simple-cycle, natural
gas-fired peaking power facility is expected to be in service in second
quarter 2011.
Becancour
On June 29, 2009, TransCanada entered into an agreement with Hydro-Quebec
to continue to suspend all electricity generation from the Becancour
power plant throughout 2010. Hydro-Quebec has the option, subject to
certain conditions, to extend the suspension on an annual basis until
such time as regional electricity demand levels recover. TransCanada will
continue to receive payments under the agreement similar to those that
would have been received under the normal course of operation.
Ravenswood
Ravenswood's 972 MW Unit 30 returned to service May 17, 2009 following an
extensive outage. The Company continues to work with its insurers with
respect to claims for both the physical damage and business interruption
losses associated with the outage.
In 2010, the Company expects capacity prices in the New York City Zone J,
in which Ravenswood operates, to return to historic levels, which were
somewhat higher than current rates. This increase in capacity prices will
be driven in part by the long-planned retirement of a power generating
facility owned by the New York Power Authority, which is scheduled to
occur in January 2010.
Share Information
As at June 30, 2009, TransCanada had 679 million issued and outstanding
common shares. In addition, there were 9 million outstanding options to
purchase common shares, of which 7 million were exercisable as at June
30, 2009.
Selected Quarterly Consolidated Financial Data(1)
(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.
Factors Impacting Quarterly Financial Information
In Pipelines, which consists primarily of the Company's investments in
regulated pipelines and regulated natural gas storage facilities, annual
revenues and net income fluctuate over the long term based on regulators'
decisions and negotiated settlements with shippers. Generally,
quarter-over-quarter revenues and net income during any particular fiscal
year remain relatively stable with fluctuations resulting from
adjustments being recorded due to regulatory decisions and negotiated
settlements with shippers, seasonal fluctuations in short-term throughput
volumes on U.S. pipelines, acquisitions and divestitures, and
developments outside of the normal course of operations.
In Energy, which consists primarily of the Company's investments in
electrical power generation plants and non-regulated natural gas storage
facilities, quarter-over-quarter revenues and net income are affected by
seasonal weather conditions, customer demand, market prices, planned and
unplanned plant outages, acquisitions and divestitures, certain fair
value adjustments and developments outside of the normal course of
operations.
Significant developments that impacted the last eight quarters' EBIT and
Net Income are as follows:
- 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.
- Second quarter 2008, Energy's EBIT included net unrealized gains of $12
million pre-tax ($8 million after tax) due to changes in the fair value
of proprietary natural gas storage inventory and natural gas forward
purchase and sale contracts. In addition, Western Power's revenues and
EBIT increased due to higher overall realized prices and market heat
rates in Alberta.
- First quarter 2008, Pipelines' EBIT included $279 million pre-tax ($152
million after tax) from the Calpine bankruptcy settlements received by
GTN and Portland, and proceeds of $17 million pre-tax ($10 million after
tax) from a lawsuit settlement. Energy's EBIT included a writedown of $41
million pre-tax ($27 million after tax) of costs related to the
Broadwater LNG project and net unrealized losses of $17 million pre-tax
($12 million after tax) due to changes in the fair value of proprietary
natural gas storage inventory and natural gas forward purchase and sale
contracts. - Fourth quarter 2007, Net Income included $56 million of
favourable income tax adjustments resulting from reductions in Canadian
federal income tax rates and other legislative changes. 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.
Consolidated Income
Three months ended Six months ended
(unaudited) June 30 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
--------------------------------------
--------------------------------------
See accompanying notes to the consolidated financial statements.
Consolidated Cash Flows
Three months ended Six months ended
June 30 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
--------------------------------------
--------------------------------------
See accompanying notes to the consolidated financial statements.
Consolidated Balance Sheet
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 489Other
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
-------------------------
-------------------------
See accompanying notes to the consolidated financial statements.
Consolidated Comprehensive Income
Three months ended Six months ended
June 30 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).
See accompanying notes to the consolidated financial statements.
Consolidated Accumulated Other Comprehensive Income
Cash
Flow
Currency Hedges
Translation 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.
See accompanying notes to the consolidated financial statements.
Consolidated Shareholders' Equity
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
-------------------------
-------------------------
See accompanying notes to the consolidated financial statements.
Notes to Consolidated Financial Statements
(Unaudited)
1. Significant Accounting Policies
The consolidated financial statements of TransCanada Corporation
(TransCanada or the Company) have been prepared in accordance with
Canadian generally accepted accounting principles (GAAP). The accounting
policies applied are consistent with those outlined in TransCanada's
annual audited Consolidated Financial Statements for the year ended
December 31, 2008, except as described in Note 2. These Consolidated
Financial Statements reflect all normal recurring adjustments that are,
in the opinion of management, necessary to present fairly the financial
position and results of operations for the respective periods. These
Consolidated Financial Statements do not include all disclosures required
in the annual financial statements and should be read in conjunction with
the 2008 audited Consolidated Financial Statements included in
TransCanada's 2008 Annual Report. Unless otherwise indicated,
"TransCanada" or "the Company" includes TransCanada Corporation and its
subsidiaries. Amounts are stated in Canadian dollars unless otherwise
indicated. Certain comparative figures have been reclassified to conform
with the current year's presentation.
In Pipelines, which consists primarily of the Company's investments in
regulated pipelines and regulated natural gas storage facilities, annual
revenues and net income fluctuate over the long term based on regulators'
decisions and negotiated settlements with shippers. Generally,
quarter-over-quarter revenues and net income during any particular fiscal
year remain relatively stable with fluctuations resulting from
adjustments being recorded due to regulatory decisions and negotiated
settlements with shippers, seasonal fluctuations in short-term throughput
volumes on U.S. pipelines, acquisitions and divestitures, and
developments outside of the normal course of operations.
In Energy, which consists primarily of the Company's investments in
electrical power generation plants and non-regulated natural gas storage
facilities, quarter-over-quarter revenues and net income are affected by
seasonal weather conditions, customer demand, market prices, planned and
unplanned plant outages, acquisitions and divestitures, certain fair
value adjustments and developments outside of the normal course of
operations.
In preparing these financial statements, TransCanada is required to make
estimates and assumptions that affect both the amount and timing of
recording assets, liabilities, revenues and expenses as the determination
of these items may be dependent on future events. The Company uses the
most current information available and exercises careful judgement in
making these estimates and assumptions. In the opinion of management,
these consolidated financial statements have been properly prepared
within reasonable limits of materiality and within the framework of the
Company's significant accounting policies.
2. Changes in Accounting Policies
The Company's accounting policies have not changed materially from those
described in TransCanada's 2008 Annual Report except as follows:
2009 Accounting Changes
Rate-Regulated Operations
Effective January 1, 2009, the temporary exemption was withdrawn from the
Canadian Institute of Chartered Accountants (CICA) Handbook Section 1100
"Generally Accepted Accounting Principles", which permitted the
recognition and measurement of assets and liabilities arising from rate
regulation. In addition, Section 3465 "Income Taxes" was amended to
require the recognition of future income tax assets and liabilities for
rate-regulated entities. The Company chose to adopt accounting policies
consistent with the U.S. Financial Accounting Standards Board's Financial
Accounting Standard (FAS) 71 "Accounting for the Effects of Certain Types
of Regulation". As a result, TransCanada retained its current method of
accounting for its rate-regulated operations, except that TransCanada is
required to recognize future income tax assets and liabilities, instead
of using the taxes payable method, and records an offsetting adjustment
to regulatory assets and liabilities. As a result of adopting this
accounting change, additional future income tax liabilities and a
regulatory asset in the amount of $1.4 billion were recorded January 1,
2009 in each of Future Income Taxes and Other Assets, respectively.
Adjustments to the 2009 financial statements have been made in accordance
with the transitional provisions for Section 3465, which required a
cumulative adjustment in the current period to future income taxes and a
regulatory asset. Restatement of prior periods' financial statements was
not permitted under Section 3465.
Intangible Assets
Effective January 1, 2009, the Company adopted CICA Handbook Section 3064
"Goodwill and Intangible Assets", which replaced Section 3062 "Goodwill
and Other Intangible Assets". Section 3064 gives guidance on the
recognition of intangible assets as well as the recognition and
measurement of internally developed intangible assets. In addition,
Section 3450 "Research and Development Costs" was withdrawn from the
Handbook. Adopting this accounting change did not have a material effect
on the Company's financial statements.
Credit Risk and the Fair Value of Financial Assets and Financial
Liabilities
Effective January 1, 2009, the Company adopted the accounting provisions
of Emerging Issues Committee (EIC) Abstract EIC 173, "Credit Risk and the
Fair Value of Financial Assets and Financial Liabilities". Under EIC 173
an entity's own credit risk and the credit risk of its counterparties is
taken into account in determining the fair value of financial assets and
financial liabilities, including derivative instruments. Adopting this
accounting change did not have a material effect on the Company's
financial statements.
Future Accounting Changes
International Financial Reporting Standards
The CICA's Accounting Standards Board announced that Canadian publicly
accountable enterprises are required to adopt International Financial
Reporting Standards (IFRS), as issued by the International Accounting
Standards Board (IASB), effective January 1, 2011. The Company will
prepare its financial statements under IFRS commencing January 1, 2011.
Under existing Canadian GAAP, TransCanada follows specific accounting
policies unique to a rate-regulated business. TransCanada is actively
monitoring developments regarding potential future guidance on the
applicability of certain aspects of rate-regulated accounting under IFRS.
Developments in this area could have a significant effect on the scope of
the Company's IFRS project and on TransCanada's financial results under
IFRS. On July 23, 2009, the IASB issued an exposure draft "Rate-regulated
Activities" and the Company is assessing the impact of this exposure
draft on TransCanada.
At the current stage of its IFRS project, TransCanada cannot reasonably
determine the full impact that adopting IFRS would have on its financial
position and future results.
Financial Instruments Disclosure
The CICA implemented revisions to Handbook Section 3862 "Financial
Instruments - Disclosures" for fiscal years ending after September 30,
2009. These revisions are intended to align the disclosure requirements
for financial instruments to the maximum extent possible with the
disclosure required under IFRS. These revisions require additional
disclosure based on a three level hierarchy that reflects the
significance of inputs used in measuring fair value. Fair values of
assets and liabilities included in Level 1 are determined by reference to
quoted prices in active markets for identical assets and liabilities.
Fair values of assets and liabilities included in Level 2 include
valuations using inputs other than quoted prices for which all
significant outputs are observable, either directly or indirectly. Fair
values of assets and liabilities included in Level 3 valuations are based
on inputs that are unobservable and significant to the overall fair value
measurement. These changes will be applied by TransCanada effective
December 31, 2009. 3. Segmented Information
Effective January 1, 2009, TransCanada revised its presentation of
certain income and expense items in the Consolidated Statement of Income
to better reflect the operating and financing structure of the Company.
To conform with the new presentation, certain of the income and expense
amounts pertaining to operations that were previously classified on the
Consolidated Income Statement as Other Expenses/(Income) are now included
in Operating and Other Expenses/(Income). Depreciation expense has been
redefined as Depreciation and Amortization expense and includes
amortization of $15 million and $29 million in the three and six month
periods ended June 30, 2009, respectively (2008 - $15 million and $29
million, respectively), for power purchase arrangements, which were
previously included in Commodity Purchases Resold. Support services costs
previously allocated to Pipelines and Energy of $31 million and $62
million in the three and six month periods ended June 30, 2009 (2008 -
$25 million and $51 million, respectively), are now included in
Corporate. In addition, amounts related to interest expense and financial
charges of joint ventures, interest income and other, income taxes and
non-controlling interests are no longer reported on a segmented basis.
Segmented information has been retroactively reclassified to reflect all
changes. These changes had no impact on Consolidated Net Income.
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 years ended December 31, 2008 and 2007, segmented information has
been retroactively reclassified to reflect all changes.
For the year
ended December
31
(unaudited) Pipelines Energy Corporate Total
(millions of --------------------------------------------------------------
dollars) 2008 2007 2008 2007 2008 2007 2008 2007
----------------------------------------------------------------------------
Revenues 4,650 4,712 3,969 4,116 - - 8,619 8,828
Plant
operating
costs and
other (1,645) (1,590) (1,307) (1,336) (110) (104) (3,062) (3,030)
Commodity
purchases
resold - (72) (1,453) (1,829) - - (1,453) (1,901)
Calpine
bankruptcy
settlements 279 - - 16 - - 279 16
Writedown of
Broadwater LNG
project costs - - (41) - - - (41) -
Other income 31 27 1 3 6 2 38 32
---------------------------------------------------------------
3,315 3,077 1,169 970 (104) (102) 4,380 3,945
Depreciation
and
amortization (989) (1,021) (258) (216) - - (1,247) (1,237)
---------------------------------------------------------------
2,326 2,056 911 754 (104) (102) 3,133 2,708
-----------------------------------------------
-----------------------------------------------
Interest
expense (943) (943)
Financial
charges of
joint ventures (72) (75)
Interest income
and other 54 120
Income taxes (602) (490)
Non-controlling
interests (130) (97)
---------------
Net Income 1,440 1,223
---------------
---------------
Total Assets
(unaudited) June 30, December 31,
(millions of dollars) 2009 2008
----------------------------------------------------------------------------
Pipelines 27,813 25,020
Energy 12,259 12,006
Corporate 4,201 2,388
------------------------
44,273 39,414
------------------------
------------------------
4. Long-Term Debt
On April 23, 2009, TCPL filed a $2.0 billion Canadian Medium-Term Notes
shelf prospectus to replace a March 2007 $1.5 billion Canadian
Medium-Term Notes shelf prospectus, which expired in April 2009. No
amounts have been issued under this shelf prospectus.
In February 2009, TCPL issued Medium-Term Notes of $300 million and $400
million maturing in February 2014 and February 2039, respectively, and
bearing interest at 5.05 per cent and 8.05 per cent, respectively. These
notes were issued under the $1.5 billion debt shelf prospectus filed in
March 2007.
In January 2009, TCPL issued Senior Unsecured Notes of US$750 million and
US$1.25 billion maturing in January 2019 and January 2039, respectively,
and bearing interest at 7.125 per cent and 7.625 per cent, respectively.
These notes were issued under a US$3.0 billion debt shelf prospectus
filed in January 2009, which now has capacity of US$1.0 billion remaining.
In the three and six months ended June 30, 2009, the Company capitalized
interest related to capital projects of $63 million and $117 million,
respectively (2008 - $32 million and $59 million).
5. Share Capital
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 an underwriters' over-allotment option.
Proceeds from the common share offering and the over-allotment option
totalled $1.8 billion. In the three and six months ended June 30, 2009,
TransCanada issued 1.4 million and 3.5 million common shares,
respectively, under its Dividend Reinvestment and Share Purchase Plan
(DRP), in lieu of making cash dividend payments totalling $42 million and
$109 million. In the three and six months ended June 30, 2008,
TransCanada issued 1.7 million and 3.1 million common shares,
respectively, under its DRP, in lieu of making cash dividend payments
totalling $58 million and $112 million. The dividends under the DRP were
paid with common shares issued from treasury.
6. Financial Instruments and Risk Management
TransCanada continues to manage and monitor its exposure to market,
counterparty credit and liquidity risk.
Counterparty Credit and Liquidity Risk
TransCanada's maximum counterparty credit exposure with respect to
financial instruments at the balance sheet date, without taking into
account security held, consisted primarily of the carrying amount, which
approximates fair value, of non-derivative financial assets, such as
accounts receivable, as well as the fair value of derivative assets.
Letters of credit and cash are the primary types of security provided to
support these amounts. The Company does not have significant
concentrations of counterparty credit risk with any individual
counterparties and the majority of counterparty credit exposure is with
counterparties who are investment grade. At June 30, 2009, there were no
significant amounts past due or impaired.
As the uncertainty in the global financial markets persists, TransCanada
continues to closely monitor and reassess the creditworthiness of its
counterparties. This has resulted in TransCanada reducing or mitigating
its exposure to certain counterparties where it is deemed warranted and
permitted under contractual terms. As part of its ongoing operations,
TransCanada must balance its market and counterparty credit risks when
making business decisions.
The Company continues to manage its liquidity risk by ensuring sufficient
cash and credit facilities are available to meet its operating and
capital expenditure obligations when due, under both normal and stressed
economic conditions.
VaR Analysis
TransCanada uses a Value-at-Risk (VaR) methodology to estimate the
potential impact from its exposure to market risk on its open liquid
positions. VaR represents the potential change in pre-tax earnings over a
given holding period. It is calculated assuming a 95 per cent confidence
level that the daily change resulting from normal market fluctuations in
its open positions will not exceed the reported VaR. TransCanada's
consolidated VaR was $14 million at June 30, 2009 (December 31, 2008 -
$23 million). The decrease from December 31, 2008 was primarily due to
decreased prices and lower open positions in the U.S. Power portfolio.
Natural Gas Inventory
At June 30, 2009, the fair value of proprietary natural gas inventory
held in storage as measured using a weighted average of forward prices
for the following four months less selling costs was $44 million
(December 31, 2008 - $76 million). Prior to second quarter 2009,
inventory was measured using the one-month forward price. The impact of
this change was insignificant.
The change in fair value of proprietary natural gas inventory in the
three and six months ended June 30, 2009 resulted in pre-tax net
unrealized losses of $6 million and $29 million, respectively, which were
recorded as a decrease to Revenues and Inventories (gains of $42 million
and $102 million for the three and six months ended June 30, 2008). The
net change in fair value of natural gas forward purchase and sales
contracts in the three and six months ended June 30, 2009 resulted in a
pre-tax net unrealized loss of $1 million and a pre-tax net unrealized
gain of $9 million (losses of $30 million and $107 million for the three
and six months ended June 30, 2008), respectively, which were included in
Revenues.
Net Investment in Self-Sustaining Foreign Operations
The Company hedges its net investment in self-sustaining foreign
operations with U.S. dollar-denominated debt, cross-currency swaps and
foreign exchange forward contracts and options. At June 30, 2009, the
Company had designated as a net investment hedge U.S. dollar-denominated
debt with a carrying value of $8.8 billion (US$7.6 billion) and a fair
value of $9.2 billion (US$7.9 billion). At June 30, 2009, Deferred
Amounts included $124 million for the fair value of derivatives used to
hedge the Company's net U.S. dollar investment in foreign operations.
Information for the derivatives used to hedge the Company's net
investment in its self-sustaining foreign operations is as follows:
Derivatives Hedging Net Investment in Self-Sustaining Foreign Operations
June 30, 2009 December 31, 2008
---------------------------------------------
Notional Notional
Asset/(Liability) Fair or Fair or
(unaudited) Value Principal Value Principal
(millions of dollars) (1) Amount (1) Amount
----------------------------------------------------------------------------
U.S. dollar cross-currency swaps
(maturing 2009 to 2014)(2) (116) U.S. (218) U.S.
1,450 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. (254) U.S.
1,850 4,102
--------------------------------------------
--------------------------------------------
(1) Fair values equal carrying values.
(2) As at June 30, 2009.
Non-Derivative Financial Instruments Summary
The carrying and fair values of non-derivative financial instruments were
as follows:
June 30, 2009 December 31, 2008
---------------------------------------------
(unaudited) Carrying Fair Carrying Fair
(millions of dollars) Amount Value Amount 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
Information for the Company's derivative financial instruments, excluding
hedges of the Company's net investment in self-sustaining foreign
operations, is as follows:
June 30, 2009
(unaudited)
(all amounts in
millions unless
otherwise Natural Oil Foreign
indicated) Power Gas Products 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- 2009- n/a 2009- 2010-
2015 2012 2013 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 Natural Oil Foreign
otherwise indicated) Power Gas Products 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.
Balance Sheet Presentation of Derivative Financial Instruments
The fair value of the derivative financial instruments in the Company's
Balance Sheet was as follows:
(unaudited)(millions of June 30,
December 31,
dollars) 2009 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
The net benefit plan expense for the Company's defined benefit pension
plans and other post-employment benefit plans is as follows:
Pension Benefit Other Benefit
Three months ended June 30 Plans 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
-------------------------------------
-------------------------------------
Pension Benefit Other Benefit
Six months ended June 30 Plans 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
On June 16, 2009, TransCanada announced that it will acquire
ConocoPhillips' remaining interest in Keystone for approximately US$550
million plus the assumption of approximately US$200 million of short-term
indebtedness. The purchase price reflects ConocoPhillips' capital
contributions to date and includes an allowance for funds used during
construction. The transaction is expected to close in third quarter 2009,
subject to the receipt of certain regulatory approvals. At June 30, 2009,
TransCanada's equity ownership in the Keystone partnerships was
approximately 77 per cent.
9. Commitments and Other
The Company has entered into an agreement to acquire ConocoPhillips'
remaining interest in 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. In addition,
TransCanada will also assume responsibility for ConocoPhillips' share of
the capital investment required to complete the project, which is
expected to result in an incremental commitment of US$1.7 billion through
the end of 2012.
Amounts received under the Bruce B floor price mechanism in any year are
subject to repayment if spot prices in the remainder of that year
increase above the floor price. With respect to 2009, TransCanada
currently expects spot prices to be less than the floor price for the
remainder of the year, therefore, no amounts recorded in revenue in the
first six months of 2009 are expected to be repaid.
10. Subsequent Event
On July 1, 2009, TransCanada sold the North Baja pipeline to PipeLines
LP. As part of the transaction, TransCanada agreed to amend its incentive
distribution rights with PipeLines LP. TransCanada received aggregate
consideration totalling approximately US$395 million from PipeLines LP,
including approximately US$200 million in cash and 6,371,680 common units
of PipeLines LP. PipeLines LP utilized US$170 million of its US$250
million committed and available bank facility to fund this transaction.
TransCanada's ownership in PipeLines LP increased to 42.6 per cent as a
result of this transaction.
Subsequent events have been assessed up to July 30, 2009, which is the
date the financial statements were issued.
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.
Contacts:
TransCanada
Media Inquiries
Cecily Dobson/Terry Cunha
(403) 920-7859 or (800) 608-7859
Analyst Inquiries
David Moneta/Myles Dougan/Terry Hook
(403) 920-7911 or (800) 361-6522
Website: www.transcanada.com
Copyright 2009, Market Wire, All rights reserved.
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