TransCanada Reports 2009 Net Income of $1.4 Billion
Common Share Dividend Increased by 5 Per Cent
CALGARY, ALBERTA--(Marketwire - Feb. 23, 2010) - TransCanada Corporation (TSX:TRP)(NYSE:TRP) (TransCanada or the Company) today announced net income applicable to common shares for fourth quarter 2009 of $381 million or $0.56 per share. For the year ended December 31, 2009, net income applicable to common shares was $1.4 billion or $2.11 per share. TransCanada's Board of Directors also declared a quarterly dividend of $0.40 per common share. The new quarterly dividend equates to $1.60 per common share on an annualized basis, an increase of five per cent.
"Our 2009 financial results highlight our ability to generate strong earnings and cash flow from a diverse portfolio of North American energy infrastructure assets" said Hal Kvisle, TransCanada's president and chief executive officer. "Looking forward, we expect that our $22 billion capital program will lead to significant growth in cash flow and earnings over the next five years as a number of attractive, low-risk projects are placed into service. This has enabled our Board of Directors to increase the dividend on common shares for the tenth consecutive year."
Mr. Kvisle noted that in 2009 TransCanada continued to make substantial progress on a number of major initiatives while maintaining its strong financial position.
"We have invested approximately $10 billion in large-scale, multi-year projects such as the Keystone Oil Pipeline System, the Alberta System's North Central Corridor expansion, the Bruce Power refurbishment and restart project and the development of three large natural gas-fired power plants," said Mr. Kvisle. "Each project is expected to generate significant long-term earnings and cash flow on commencement of operations."
"TransCanada is well positioned to fund the remaining portion of this unprecedented capital program," Mr. Kvisle added. "While the carrying costs and dilution associated with our prudent approach to financing this multi-year program will have a near-term impact on our earnings and cash flow per share, our growing internally generated cash flow and our strong financial position provide us with financial flexibility going forward."
Fourth Quarter and Year-End 2009 Highlights
(All financial figures are unaudited and in Canadian dollars unless noted otherwise)
- For fourth quarter
-- Net income applicable to common shares of $381 million or $0.56 per share
-- Comparable earnings of $328 million or $0.48 per share
-- Comparable EBITDA of $965 million
-- Funds generated from operations of $850 million
- For the year ended December 31
-- Net income applicable to common shares of $1.4 billion or $2.11 per share
-- Comparable earnings of $1.3 billion or $2.03 per share
-- Comparable EBITDA of $4.1 billion
-- Funds generated from operations of $3.1 billion
- Invested $6.3 billion to advance unprecedented $22 billion capital program
Comparable earnings for fourth quarter 2009 were $328 million ($0.48 per share) compared to $271 million ($0.46 per share) in fourth quarter 2008. The increase was primarily due to higher earnings from Natural Gas Storage, higher realized power prices at Bruce B, incremental earnings from Portlands Energy Centre, which was placed into service in April 2009 and lower interest expense from increased capitalization of interest related to the Company's large capital growth program. Partially offsetting these increases were lower realized power prices in Western Power and U.S. Power and business development costs associated with the Alaska pipeline project. Earnings per share were reduced by the dilutive impact in fourth quarter 2009 of a 14 per cent increase in the average number of common shares outstanding following the issuance of 58.4 million common shares in second quarter 2009 and 35.1 million common shares in fourth quarter 2008. Proceeds from these offerings were used to partially fund capital growth projects, including the acquisition of additional interests in Keystone, for general corporate purposes and to repay short term indebtedness. TransCanada's $22 billion capital program is expected to generate significant cash flow and earnings over the next five years as projects commence operations.
Comparable earnings for the year ended December 31, 2009 of $1.325 billion ($2.03 per share) increased $46 million compared to $1.279 billion ($2.25 per share) for 2008. The increase in comparable earnings was primarily due to higher earnings from the Alberta System, the start up of Portlands Energy Centre and Carleton Wind Farm and higher realized power prices at Bruce Power. Partially offsetting these increases were lower realized power prices on lower sales volumes in the Alberta and New England power markets. On a per share basis, in 2009, earnings were reduced by the dilutive impact of an increase in the average number of outstanding common shares following the issuance 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. Proceeds from these offerings were used to partially fund acquisitions and capital projects, for general corporate purposes and to repay short term indebtedness. Notable recent developments in Pipelines, Energy and Corporate include: Pipelines: - Commissioning of the first phase of the Keystone Oil Pipeline System (Keystone), extending from Hardisty, Alberta to Wood River and Patoka, Illinois with an initial nominal capacity of 435,000 barrels per day (Bbl/d), began in late 2009 and commercial operations are expected to commence mid-2010. In September 2009, the National Energy Board (NEB) held a hearing to review the application for the new Canadian facilities required for the Keystone Gulf Coast expansion. A decision from the NEB is expected in first quarter 2010, approving a certificate for the construction and operation of the facilities, subject to Governor-in-Council approval, and the proposed tolling methodology. Facility permits for the U.S. portion of the expansion are expected by fourth quarter 2010. Construction of the expansion facilities is anticipated to commence in first quarter 2011 following the receipt of the necessary regulatory approvals.
TransCanada expects Keystone to begin generating EBITDA in 2010 with EBITDA increasing through 2011, 2012 and 2013 as subsequent phases are placed in service. Contracted volumes of 217,500 Bbl/d will increase to 910,000 Bbl/d from 2010 through to 2013 in conjunction with commencement of the Cushing and Gulf Coast phases. Based on these current long-term commitments, TransCanada expects to generate EBITDA of approximately US$1.2 billion from Keystone in 2013, its first full year of commercial operation servicing both the U.S. Midwest and Gulf Coast markets. If volumes were to increase to 1.1 million Bbl/d, the full commercial design of the system, TransCanada would generate annual EBITDA of approximately US$1.5 billion from Keystone. In the future, Keystone could be economically expanded from 1.1 million Bbl/d to 1.5 million Bbl/d in response to additional market demand.
- TransCanada and ExxonMobil continued to advance the Alaska pipeline project by filing an open season plan in the first quarter of 2010 with the U.S. Federal Energy Regulatory Commission (FERC). The filing was made to obtain approval to conduct the first natural gas pipeline open season to develop Alaska's vast natural gas resources. If the FERC approves the plan, the project will commence its open season in April 2010.
- TransCanada and the other co-venture companies involved in the Mackenzie Gas Pipeline Project (MGP) continue to pursue approval of the proposed project, focusing on obtaining regulatory approval and the Canadian government's support of an acceptable fiscal framework. The regulatory process reached a milestone in late December 2009 with the release of the Joint Review Panel's report on environmental and socio-economic factors relating to the project. That report has been submitted into the NEB review process for approval of the project, which is scheduled to conclude in April 2010 with final arguments. A decision is currently expected by fourth quarter 2010.
- In November 2009, the NEB concluded a public hearing process on TransCanada's application for approval to construct and operate the Groundbirch pipeline, which is comprised of a 77 kilometre (km) (48 miles) natural gas pipeline and related above ground facilities. Upon approval, the Groundbirch pipeline will be an extension of the Alberta System and is expected to connect natural gas supply primarily from the Montney shale gas formation in northeast B.C. to existing infrastructure in northwest Alberta. Construction of the Groundbirch pipeline is expected to commence in July 2010 with final completion anticipated in November 2010. A decision from the NEB is expected in first quarter 2010. The proposed project is expected to cost approximately $200 million with secured firm transportation contracts that will reach 1.1 billion cubic feet per day (Bcf/d) by 2014.
- Total contractual commitments for the Alberta System's Horn River project have increased from 378 million cubic feet per day (mmcf/d) to 503 mmcf/d by 2014 as a result of newly contracted volumes from a recently announced natural gas processing facility that will be located in the Horn River area of British Columbia. The Horn River project will connect new shale gas supply in the Horn River development region to the Alberta System. As part of the Horn River project, in November 2009, TransCanada entered into an agreement to acquire the Ekwan Pipeline from EnCana Corporation. This acquisition is expected to close in September 2011. In February 2010, TransCanada filed an application with the NEB for approval to construct and operate the Horn River project, including acquisition of the Ekwan pipeline. Subject to regulatory approvals, the Horn River project is anticipated to be placed in-service in second quarter 2012.
- TransCanada continued work on the 160 km (99 miles) Red Earth section of the North Central Corridor (NCC) pipeline expansion of the Alberta System that is expected to be completed by April 2010. The 140 km (87 miles) North Star section was completed and two 13 megawatt (MW) compressor units at the Meikle River compressor station were operational on May 15, 2009 and August 21, 2009, respectively.
- Regulatory approvals were received in December 2009 for the approximate 305 km (190 miles), US$320 million Guadalajara natural gas pipeline project in Mexico. Construction is underway with an expected in-service date of first quarter 2011.
- TransCanada is expecting FERC approval in March 2010 of the Bison pipeline project, a proposed 487 km (303 miles) natural gas pipeline. Once approval is received, TransCanada will commence construction in May 2010. The project has shipping commitments for approximately 407 mmcf/d and is expected to be in service in fourth quarter 2010. The capital cost of the Bison pipeline project is estimated to be US$600 million.
- During 2009, TransCanada negotiated a Rate Design Settlement for the Alberta System, which provided for a new rate design for the existing system and expansions which addresses the evolving nature of the Alberta System and the commercial and operational integration of ATCO Pipelines. The changes are expected to improve the Alberta System services by making them more consistent and adding flexibility for customers. TransCanada filed a combination application with the NEB on November 27, 2009 for approval of both the Rate Design Settlement and the integration of commercial and operational services on the Alberta System and ATCO Pipelines' system in Alberta. A final decision is expected from the NEB by mid-2010 with implementation occurring within 12 months following approval.
Energy:
- In October 2009, TransCanada placed into service the first phase of Kibby Wind, which included 22 turbines capable of producing 66 MW of power. Construction continues on the 66 MW second phase of the project, which includes the installation of an additional 22 turbines. The second phase is expected to be in service in third quarter 2010.
- Construction of the 683 MW Halton Hills power plant in Ontario and the 575 MW Coolidge generating station in Arizona continued to progress on schedule with in service dates of third quarter 2010 and second quarter 2011, respectively.
- Clearing for the 58 MW Montagne-Seche wind farm was completed in fourth quarter 2009. The Montagne-Seche project and phase one of the Gros-Morne wind farm are expected to be operational in 2011. Gros-Morne phase two is expected to be operational in 2012. These are the fourth and fifth Quebec-based wind farms of Cartier Wind, which is 62 per cent owned by TransCanada.
- Construction activity is continuing on the refurbishment and restart of Bruce A Units 1 and 2 with a focus on the reassembly of the reactors and other related activities. As of December 31, 2009, Bruce A had incurred approximately $3.2 billion in costs for the refurbishment and restart of these units and approximately $0.2 billion for the refurbishment of Units 3 and 4. TransCanada believes that its share of the total capital cost to complete the Unit 1 and 2 refurbishment and restart program will be approximately $2 billion. The bulk of the highly technical, high-risk work on this project is now finished or nearing completion. Although a significant amount of work remains to be completed, most of the work is conventional power plant construction activity. A project optimization plan implemented by Bruce Power last year is achieving success in improving productivity. TransCanada expects that Unit 2 will be restarted in mid-2011, with Unit 1 to follow approximately four months later.
Bruce Power continues to advance an initiative to further extend the operating lives of Units 3 and 4. Unit 4 is now expected to continue to operate beyond 2018 and plans are in place to implement an extensive maintenance program that, if successful and approved by the Canadian Nuclear Safety Commission would see the life of Unit 3 extended for a similar period of time.
- TransCanada's open seasons for capacity on its proposed Zephyr and Chinook power transmission line projects closed in December 2009. A comprehensive review of the bids will be undertaken. Each project would be capable of delivering primarily renewable (wind) power originating in Wyoming (Zephyr) and Montana (Chinook) to Nevada.
Corporate:
- The Board of Directors of TransCanada declared a quarterly dividend of $0.40 per common share, an increase of five per cent, for the quarter ending March 31, 2010, on TransCanada's outstanding common shares.
- TransCanada is well positioned to fund its existing capital program through its growing internally-generated cash flow, its dividend reinvestment and share purchase plan, and its continued access to capital markets. TransCanada will also continue to examine opportunities for portfolio management, including an ongoing role for TC PipeLines, LP in financing its capital program.
Teleconference - Audio and Slide Presentation:
TransCanada will hold a teleconference and webcast to discuss its 2009 fourth quarter financial results. Hal Kvisle, TransCanada president and chief executive officer and Greg Lohnes, executive vice-president and chief financial officer, along with other members of the TransCanada executive leadership team, will discuss the financial results and company developments, including its $22 billion capital program, before opening the call to questions from analysts and members of the media.
Event:
TransCanada fourth quarter 2009 financial results teleconference and webcast
Date:
Tuesday, February 23, 2010
Time:
1 p.m. mountain standard time (MST) /3 p.m. eastern standard time (EST)
How:
To participate in the teleconference, please call 1.866.223.7781 or 416.340.8018 (Toronto area). Please dial in 10 minutes prior to the start of the call. No pass code is required. A live webcast of the teleconference will also be available on TransCanada's website (www.transcanada.com).
A replay of the teleconference will be available two hours after the conclusion of the call until midnight (EST) March 2, 2010. Please call 1.800.408.3053 or 416.695.5800 (Toronto area) and enter pass code 6338765#. 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 and oil pipelines, power generation and gas storage facilities. TransCanada's network of wholly owned natural gas pipelines extends more than 60,000 kilometres (37,000 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 380 billion cubic feet of storage capacity. A growing independent power producer, TransCanada owns, or has interests in, over 11,700 megawatts of power generation in Canada and the United States. TransCanada is developing one of North America's largest oil delivery systems. TransCanada's common shares trade on the Toronto and New York stock exchanges under the symbol TRP. For more information visit: www.transcanada.com
Fourth Quarter 2009 Financial Highlights
Operating Results
Three months ended Year ended
(unaudited) December 31 December 31
(millions of dollars) 2009 2008 2009 2008
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Revenues 2,206 2,332 8,966 8,619
Comparable EBITDA(1) 965 1,044 4,107 4,125
Comparable EBIT(1) 622 740 2,730 2,878
EBIT(1) 658 747 2,760 3,133
Net Income 387 277 1,380 1,440
Net Income Applicable to
Common Shares 381 277 1,374 1,440
Comparable Earnings(1) 328 271 1,325 1,279
Cash Flows
Funds generated from
operations(1) 850 712 3,080 3,021
(Increase)/decrease in
operating working capital (217) (150) (90) 135
---------------------------------------
Net cash provided by operations 633 562 2,990 3,156
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Capital Expenditures 1,474 1,235 5,417 3,134
Acquisitions, Net of Cash Acquired - 171 902 3,229
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---------------------------------------
Common Share Statistics
Three months ended Year ended
December 31 December 31
(unaudited) 2009 2008 2009 2008
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Net Income Per Share - Basic $0.56 $0.47 $2.11 $2.53
Comparable Earnings Per Share(1) $0.48 $0.46 $2.03 $2.25
Dividends Declared Per Share $0.38 $0.36 $1.52 $1.44
Basic Common Shares Outstanding
(millions)
Average for the period 683 597 652 570
End of period 684 616 684 616
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---------------------------------------
(1) Refer to the Non-GAAP Measures section in this news release for further
discussion of comparable EBITDA, comparable EBIT, EBIT, comparable
earnings, funds generated from operations and comparable earnings per
share.
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 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 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.
EBITDA is an approximate measure of the Company's pre-tax operating cash flow. EBITDA comprises earnings before deducting interest and other financial charges, income taxes, depreciation and amortization, and non-controlling interests. EBIT is a measure of the Company's earnings from ongoing operations. EBIT comprises earnings before deducting interest and other financial charges, income taxes and non-controlling interests.
Management uses the measures of comparable earnings, comparable EBITDA and comparable EBIT to better evaluate trends in the Company's underlying operations. Comparable earnings, comparable EBITDA and comparable EBIT comprise net income applicable to common shares, 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 news release presents a reconciliation of comparable earnings, comparable EBITDA, comparable EBIT and EBIT to net income and net income applicable to common shares. Comparable earnings per share is calculated by dividing comparable earnings by the weighted average number of common shares outstanding for the period.
Funds generated from operations comprises net cash provided by operations before changes in operating working capital. A reconciliation of funds generated from operations to net cash provided by operations is presented in the Fourth Quarter 2009 Financial Highlights table in this news release.
Consolidated Results of Operations
Reconciliation of Comparable Earnings, Comparable EBITDA, Comparable EBIT
and EBIT to Net Income
For the three months ended December 31
(unaudited)(millions
of dollars Pipelines Energy Corporate Total
except per
share
amounts) 2009 2008 2009 2008 2009 2008 2009 2008
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Comparable
EBITDA(1) 745 780 248 297 (28) (33) 965 1,044
Depreciation
and
amortization (257) (224) (86) (80) - - (343) (304)
-------------------------------------------------------------
Comparable
EBIT(1) 488 556 162 217 (28) (33) 622 740
Specific items:
Dilution gain
from reduced
interest in
PipeLines LP 29 - - - - - 29 -
Fair value
adjustments of
natural gas
inventory in
storage and
forward
contracts - - 7 7 - - 7 7
-------------------------------------------------------------
EBIT(1) 517 556 169 224 (28) (33) 658 747
---------------------------------------------
---------------------------------------------
Interest expense (184) (326)
Interest expense
of joint
ventures (17) (21)
Interest income
and other 22 (4)
Income taxes (67) (95)
Non-controlling
interests (25) (24)
-----------------
Net Income 387 277
Preferred share
dividends (6) -
-----------------
Net Income
Applicable to
Common Shares 381 277
Specific items (net of tax, where applicable):
Dilution gain from reduced interest in PipeLines LP (18) -
Fair value adjustments of natural gas inventory in storage
and forward contracts (5) (6)
Income tax adjustments (30) -
-----------------
Comparable Earnings(1) 328 271
-----------------
-----------------
Net Income Per Share
- Basic (2) $ 0.56 $ 0.47
- Diluted $ 0.56 $ 0.46
-----------------
-----------------
(1) Refer to the Non-GAAP Measures section in this news release for further
discussion of comparable EBITDA, comparable EBIT, EBIT, comparable
earnings and comparable earnings per share.
(2) For the three months ended December 31
(unaudited) 2009 2008
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Net Income Per Share $0.56 $0.47
Specific items (net of tax, where applicable):
Dilution gain from reduced interest in PipeLines LP (0.03) -
Fair value adjustments of natural gas inventory in
storage and forward contracts (0.01) (0.01)
Income tax adjustments (0.04) -
-----------------
Comparable Earnings Per Share(1) $0.48 $0.46
-----------------
-----------------
For the year ended December 31
(unaudited)
(millions of
dollars except Pipelines Energy Corporate Total
per share
amounts) 2009 2008 2009 2008 2009 2008 2009 2008
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Comparable
EBITDA(1) 3,093 3,019 1,131 1,210 (117) (104) 4,107 4,125
Depreciation
and
amortization (1,030) (989) (347) (258) - - (1,337) (1,247)
-------------------------------------------------------------
Comparable
EBIT(1) 2,063 2,030 784 952 (117) (104) 2,730 2,878
Specific
items:
Dilution
gain
from
reduced
interest
in
PipeLines LP 29 - - - - - 29 -
Fair value
adjustments
of natural
gas
inventory in
storage
and forward
contracts - - 1 - - - 1 -
Calpine
bankruptcy
settlements - 279 - - - - - 279
GTN lawsuit
settlement - 17 - - - - - 17
Writedown of
Broadwater
LNG
project costs - - - (41) - - - (41)
-------------------------------------------------------------
EBIT(1) 2,092 2,326 785 911 (117) (104) 2,760 3,133
Interest
expense (954) (943)
Interest
expense of
joint
ventures (64) (72)
Interest
income and
other 121 54
Income taxes (387) (602)
Non-controlling
interests (96) (130)
-----------------
Net Income 1,380 1,440
Preferred
share
dividends (6) -
-----------------
Net Income
Applicable to
Common Shares 1,374 1,440
Specific items (net of tax, where applicable):
Dilution gain from reduced interest in PipeLines LP (18) -
Fair value adjustments of natural gas inventory in
storage and forward contracts (1) -
Calpine bankruptcy settlements - (152)
GTN lawsuit settlement - (10)
Writedown of Broadwater LNG project costs - 27
Income tax adjustments (30) (26)
-----------------
Comparable Earnings(1) 1,325 1,279
-----------------
-----------------
Net Income Per Share
- Basic (2) $2.11 $2.53
- Diluted $2.11 $2.52
-----------------
-----------------
(1) Refer to the Non-GAAP Measures section in this news release for further
discussion of comparable EBITDA, comparable EBIT, EBIT, comparable
earnings and comparable earnings per share.
(2) For the year ended December 31
(unaudited) 2009 2008
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----------------------------------------------------------------------------
Net Income Per Share $ 2.11 $ 2.53
Specific items (net of tax, where applicable):
Dilution gain from reduced interest in PipeLines LP (0.03) -
Calpine bankruptcy settlements - (0.27)
GTN lawsuit settlement - (0.02)
Writedown of Broadwater LNG project costs - 0.05
Income tax adjustments (0.05) (0.04)
--------------------
Comparable Earnings Per Share(1) $ 2.03 $ 2.25
--------------------
--------------------
TransCanada's net income was $387 million and net income applicable to common shares was $381 million or $0.56 per share in fourth quarter 2009 compared to $277 million or $0.47 per share in fourth quarter 2008. The $104 million increase in net income applicable to common shares reflected:
- decreased EBIT from Pipelines primarily due to the negative impact of a weaker U.S. dollar on Pipeline's U.S. operations and increased business development costs related to the Alaska pipeline project. These decreases were partially offset by an $18 million after tax ($29 million pre-tax) dilution gain resulting from TransCanada's reduced ownership interest in PipeLines LP following PipeLines LP's public issuance of common units.
- decreased EBIT from Energy primarily due to lower power prices in Western Power and U.S. Power, and the impact of a weaker U.S. dollar on Energy's U.S. operations, partially offset by higher contribution from the Natural Gas Storage business due to increased third party storage revenues and increased earnings as a result of the start up of Portlands Energy.
- decreased interest expense primarily due to increased capitalized interest, reduced losses from changes in the fair value of interest rate derivatives used to manage TransCanada's exposure to fluctuating interest rates and the positive impact of a weaker U.S. dollar. These decreases were partially offset by incremental interest expense for new debt issuances in 2009.
- increased interest income and other due to the positive impact of a weaker U.S. dollar on working capital balances and changes in the fair value of derivatives used to manage the Company's exposure to foreign exchange rate fluctuations; and
- decreased income tax expense primarily due to positive income tax adjustments in fourth quarter 2009, including $30 million resulting from a reduction in the Province of Ontario's corporate income tax rates, partially offset by higher pre-tax income.
The increase in earnings per share in fourth quarter 2009 was partially offset by a 14 per cent increase in the average number of common shares outstanding, in fourth quarter 2009 compared to fourth quarter 2008, following the Company's issuance of 58.4 million and 35.1 million common shares in second quarter 2009 and fourth quarter 2008, respectively.
Comparable earnings in fourth quarter 2009 increased $57 million or $0.02 per share to $328 million or $0.48 per share, compared to $271 million or $0.46 per share for the same period in 2008. Comparable earnings in fourth quarter 2009 excluded the $18 million after tax dilution gain resulting from TransCanada's reduced ownership in PipeLines LP and the $30 million of favourable income tax adjustments. Comparable earnings in fourth quarter 2009 and 2008 also excluded net unrealized after tax gains of $5 million ($7 million pre-tax) and $6 million ($7 million pre-tax), respectively, resulting from changes in the fair value of proprietary natural gas inventory in storage and natural gas forward purchase and sale contracts.
On a consolidated basis, the impact of changes in the U.S. dollar on U.S. Pipelines and Energy EBIT is largely offset by the impact on U.S. dollar interest expense. The resultant net exposure is managed using derivatives thereby effectively reducing the Company's exposure to changes in foreign exchange rates. The average U.S. dollar exchange rate for the fourth quarter and year ended December 31, 2009 was 1.06 and 1.14, respectively (2008 - 1.21 and 1.07, respectively).
In 2009, net income was $1,380 million and net income applicable to common shares was $1,374 million or $2.11 per share compared to net income of $1,440 million or $2.53 per share in 2008. Net income applicable to common shares in 2009 included the $30 million of favourable income tax adjustments and the $18 million after tax dilution gain resulting from TransCanada's reduced interest in PipeLines LP. Net income in 2008 included $152 million of after tax gains on shares received by GTN and Portland from the Calpine bankruptcy settlements, $10 million after tax of GTN lawsuit settlement proceeds and a $27 million after tax writedown of costs previously capitalized for the Broadwater liquefied natural gas (LNG) project. Net income in 2008 also included $26 million of favourable income tax adjustments from an internal restructuring and realization of losses.
Comparable earnings for 2009 were $1,325 million or $2.03 per share compared to $1,279 million or $2.25 per share for 2008 and excluded the above-noted items. Comparable earnings increased $46 million and decreased $0.22 per share in 2009 compared to 2008. The increase in comparable earnings reflects:
- increased comparable EBIT from Pipelines primarily due to higher earnings from the Alberta System revenue requirement settlement and the positive impact in 2009 of a stronger U.S. dollar on Pipelines' U.S. operations, partially offset by increased costs for developing new Pipelines projects, primarily the Alaska pipeline project;
- decreased comparable EBIT from Energy primarily due to lower power prices and a decreased demand for power in Western Power and U.S. Power, reflecting the downturn in the North American economy, partially offset by increased earnings from the start up of Portlands Energy and the Carleton phase of the Cartier Wind project, and higher realized power prices for Bruce Power;
- increased comparable EBIT losses from Corporate primarily due to higher support services costs, reflecting a growing asset base;
- increased interest expense as a result of long-term debt issuances in the second half of 2008 and first quarter 2009 and the negative impact of a stronger U.S. dollar. These increases were partially offset by an increase in capitalized interest relating to Keystone and other capital projects and reduced losses from changes in the fair value of derivatives used to manage TransCanada's exposure to fluctuating interest rates;
- increased interest income and other due to the positive impact of a weakening U.S. dollar throughout 2009 on working capital balances and higher gains from derivatives used to manage the Company's exposure to foreign exchange rate fluctuations;
- decreased income tax expense due to lower pre-tax earnings, higher income tax savings from income tax rate differentials and other positive income tax adjustments in 2009; and
- a reduction in non-controlling interests due to Portland's portion of the Calpine bankruptcy settlements recorded in 2008, partially offset by higher PipeLines LP earnings in 2009.
Earnings per share in 2009 and 2008 was reduced by the increase in the average number of shares outstanding following the Company's issuance of 58.4 million, 35.1 million and 34.7 million common shares in second quarter 2009, fourth quarter 2008 and second quarter 2008, respectively. The shares were issued to partially finance TransCanada's acquisitions and extensive capital growth program.
Results from each of the segments for fourth quarter 2009 are discussed further in the Pipelines, Energy and Corporate sections of this news release.
Pipelines
Pipelines comparable EBIT was $488 million in fourth quarter 2009 compared to $556 million for the same period in 2008. Comparable EBIT excluded the $29 million pre-tax dilution gain resulting from a reduction in TransCanada's ownership interest in PipeLines LP following PipeLines LP's public issuance of common units in fourth quarter 2009.
Pipelines Results
Three months ended Year ended
(unaudited) December 31 December 31
(millions of dollars) 2009 2008 2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Canadian Pipelines
Canadian Mainline 282 300 1,133 1,141
Alberta System 193 152 728 692
Foothills 32 31 132 133
Other (TQM, Ventures LP) 15 11 59 50
----------------------------------------
Canadian Pipelines Comparable
EBITDA(1) 522 494 2,052 2,016
----------------------------------------
U.S. Pipelines
ANR 84 99 347 347
GTN(2) 43 52 195 198
Great Lakes 30 34 138 127
PipeLines LP(2)(3) 20 23 84 70
Iroquois 16 17 78 59
Portland(4) 8 9 26 27
International (Tamazunchale,
TransGas, Gas Pacifico/INNERGY) 12 8 58 40
General, administrative and
support costs(5) - (1) (17) (15)
Non-controlling interests(6) 46 54 194 187
----------------------------------------
U.S. Pipelines Comparable
EBITDA(1) 259 295 1,103 1,040
----------------------------------------
Business Development Comparable
EBITDA(1) (36) (9) (62) (37)
----------------------------------------
Pipelines Comparable EBITDA(1) 745 780 3,093 3,019
Depreciation and amortization (257) (224) (1,030) (989)
----------------------------------------
Pipelines Comparable EBIT(1) 488 556 2,063 2,030
Specific items:
Dilution gain from reduced
interest in PipeLines LP(3)(7) 29 - 29 -
Calpine bankruptcy settlements(8) - - - 279
GTN lawsuit settlement - - - 17
----------------------------------------
Pipelines EBIT(1) 517 556 2,092 2,326
----------------------------------------
----------------------------------------
(1) Refer to the Non-GAAP Measures section in this news release for further
discussion of comparable EBITDA, comparable EBIT and EBIT.
(2) GTN's results include North Baja until July 1, 2009 when it was sold to
PipeLines LP.
(3) Effective November 18, 2009, PipeLines LP's results reflect
TransCanada's ownership interest in PipeLines LP of 38.2 per cent.
From July 1, 2009 to November 17, 2009, TransCanada's ownership
interest in PipeLines LP was 42.6 per cent. From January 1, 2008 to
June 30, 2009, TransCanada's ownership interest in PipeLines LP was
32.1 per cent.
(4) Portland's results reflect TransCanada's 61.7 per cent ownership
interest.
(5) Represents certain costs associated with supporting the Company's
Canadian and U.S. Pipelines.
(6) Non-controlling interests reflects EBITDA for the portions of
PipeLines LP and Portland not owned by TransCanada.
(7) As a result of PipeLines LP issuing common units to the public, the
Company's ownership in PipeLines LP was reduced to 38.2 per cent from
42.6 per cent and a dilution gain of $29 million was realized.
(8) GTN and Portland received shares of Calpine with an initial value of
$154 million and $103 million, respectively, as a result of the
bankruptcy settlements with Calpine. These shares were subsequently sold
for an additional gain of $22 million.
Net Income for Wholly Owned Canadian Pipelines
Three months ended Year ended
(unaudited) December 31 December 31
(millions of dollars) 2009 2008 2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Canadian Mainline 72 74 273 278
Alberta System 45 48 168 145
Foothills 5 5 23 24
----------------------------------------
----------------------------------------
Canadian Pipelines
Canadian Mainline's net income for fourth quarter 2009 decreased $2 million to $72 million from $74 million for the same period in 2008. Net income for fourth quarter 2009 reflected 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 OM&A cost savings.
Canadian Mainline's EBITDA for fourth quarter 2009 of $282 million decreased $18 million compared to the same period in 2008 primarily due to lower revenues as a result of a recovery of lower income taxes and a lower overall return on average investment base in the 2009 tolls, partially offset by higher OM&A cost savings.
The Alberta System's net income was $45 million in fourth quarter 2009 compared to $48 million for the same period in 2008. Earnings in 2009 and 2008 reflect the impact of the 2008-2009 Revenue Requirement Settlement originally approved by the Alberta Utilities Commission (AUC) in December 2008 and subsequently approved by the NEB in December 2009.
The Alberta System's EBITDA was $193 million in fourth quarter 2009 compared to $152 million for the same period in 2008. Fourth quarter 2009 EBITDA reflects higher revenues as a result of the recovery of higher depreciation and income taxes, partially offset by lower settlement earnings.
EBITDA from Other Canadian Pipelines was $15 million for fourth quarter 2009 compared to $11 million for the same period in 2008. The increase in fourth quarter 2009 was primarily due to an adjustment to TQM's cost of capital for 2009.
U.S. Pipelines
ANR's EBITDA for fourth quarter 2009 was $84 million compared to $99 million for the same period in 2008. The decrease in EBITDA in fourth quarter 2009 was primarily due to the negative impact of a weaker U.S. dollar.
GTN's EBITDA for fourth quarter 2009 decreased $9 million from the same period in 2008 primarily due to the negative impact of a weaker U.S. dollar and the sale of North Baja to PipeLines LP.
EBITDA for the remainder of the U.S. Pipelines was $132 million for fourth quarter 2009 compared to $144 million for the same period in 2008. The decrease in fourth quarter 2009 compared to fourth quarter 2008 was primarily due to the negative impact of a weaker U.S. dollar on U.S. Pipelines operations, partially offset by the acquisition of North Baja by PipeLines LP.
Business Development
Pipelines business development comparable EBITDA losses increased $27 million in fourth quarter 2009 compared to the same period in 2008 primarily due to increased business development costs related to the Alaska pipeline project.
Energy
Energy's comparable EBIT was $162 million in fourth quarter 2009 compared to $217 million in fourth quarter 2008. Comparable EBIT in fourth quarter 2009 and 2008 excluded net unrealized gains of $7 million in each period resulting from changes in the fair value of proprietary natural gas inventory in storage and natural gas forward purchase and sale contracts.
Energy Results
Three months ended Year ended
(unaudited) December 31 December 31
(millions of dollars) 2009 2008 2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Canadian Power
Western Power 61 128 279 510
Eastern Power(1) 56 43 220 147
Bruce Power 70 70 352 275
General, administrative and
support costs (11) (11) (39) (39)
----------------------------------------
Canadian Power Comparable
EBITDA(2) 176 230 812 893
----------------------------------------
U.S. Power(3)
Northeast Power 39 63 237 272
General, administrative and
support costs (10) (13) (45) (41)
----------------------------------------
U.S. Power Comparable EBITDA(2) 29 50 192 231
----------------------------------------
Natural Gas Storage
Alberta Storage 51 38 173 152
General, administrative and
support costs (2) (4) (9) (14)
----------------------------------------
Natural Gas Storage Comparable
EBITDA(2) 49 34 164 138
----------------------------------------
Business Development Comparable
EBITDA(2) (6) (17) (37) (52)
----------------------------------------
Energy Comparable EBITDA(2) 248 297 1,131 1,210
Depreciation and amortization (86) (80) (347) (258)
----------------------------------------
Energy Comparable EBIT(2) 162 217 784 952
Specific items:
Fair value adjustments of
natural gas inventory in
storage and forward contracts 7 7 1 -
Writedown of Broadwater LNG
project costs - - - (41)
----------------------------------------
Energy EBIT(2) 169 224 785 911
----------------------------------------
----------------------------------------
(1) Includes Portlands Energy and the Carleton wind farm effective April
2009 and November 2008, respectively.
(2) Refer to the Non-GAAP Measures section in this news release for further
discussion of comparable EBITDA, comparable EBIT and EBIT.
(3) Includes phase one of Kibby Wind and Ravenswood effective October 2009
and August 2008, respectively.
Western and Eastern Canadian Power Comparable EBITDA(1)(2)
Three months ended Year ended
(unaudited) December 31 December 31
(millions of dollars) 2009 2008 2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenues
Western power 203 298 788 1,140
Eastern power 72 54 281 175
Other(3) 62 51 184 186
----------------------------------------
337 403 1,253 1,501
----------------------------------------
Commodity Purchases Resold
Western power (124) (137) (451) (517)
Eastern power - 2 - -
Other(4) (44) (41) (124) (112)
----------------------------------------
(168) (176) (575) (629)
----------------------------------------
Plant operating costs and other (49) (57) (178) (216)
General, administrative and
support costs (11) (11) (39) (39)
Other (expenses)/income (3) 1 (1) 1
----------------------------------------
Comparable EBITDA(1) 106 160 460 618
----------------------------------------
----------------------------------------
(1) Refer to the Non-GAAP Measures section in this news release for further
discussion of comparable EBITDA.
(2) Includes Portlands Energy and the Carleton wind farm effective April
2009 and November 2008, respectively.
(3) Other revenue includes sales of natural gas, sulphur (in 2008) and
thermal carbon black.
(4) Other commodity purchases resold includes the cost of natural gas sold.
Western and Eastern Canadian Power Operating Statistics(1)
Three months ended Year ended
December 31 December 31
(unaudited) 2009 2008 2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Sales Volumes (GWh)(2)
Supply
Generation
Western Power 616 589 2,334 2,322
Eastern Power 469 332 1,550 1,069
Purchased
Sundance A & B and
Sheerness PPAs 2,878 3,225 10,603 12,368
Other purchases 109 181 529 970
----------------------------------------
4,072 4,327 15,016 16,729
----------------------------------------
----------------------------------------
Sales
Contracted
Western Power 2,780 2,705 9,944 11,284
Eastern Power 471 333 1,588 1,232
Spot
Western Power 821 1,289 3,484 4,213
----------------------------------------
4,072 4,327 15,016 16,729
----------------------------------------
----------------------------------------
(1) Includes Portlands Energy and the Carleton wind farm effective April
2009 and November 2008, respectively.
(2) Gigawatt hours.
Western Power's EBITDA of $61 million and power revenues of $203 million in fourth quarter 2009 decreased $67 million and $95 million, respectively, compared to the same period in 2008. These decreases were primarily due to lower earnings from the Alberta power portfolio resulting from lower overall realized power prices on lower volumes of power sold. The reduction in power prices and sales volumes reflected reduced demand for electricity in Alberta as a result of the North American economic slowdown. Average spot market power prices in Alberta decreased 51 per cent, or $49 per MWh, in fourth quarter 2009 compared to fourth quarter 2008.
Western Power's commodity purchases resold decreased $13 million in fourth quarter 2009 compared to the same period in 2008 primarily due to lower purchased power volumes as a result of the reduced demand for electricity in Alberta.
Eastern Power's EBITDA of $56 million and power revenues of $72 million for fourth quarter 2009 increased $13 million and $18 million, respectively, compared to the same period in 2008. These increases were primarily due to incremental earnings from Portlands Energy which went into service in April 2009.
Plant operating costs and other, which includes fuel gas consumed in generation, of $49 million for fourth quarter 2009 decreased from the same period in 2008 primarily due to lower prices for natural gas fuel in Western Power, partially offset by incremental fuel consumed at Portlands Energy.
Approximately 77 per cent of Western Power sales volumes were sold under contract in fourth quarter 2009, compared to 68 per cent in fourth quarter 2008. To reduce its exposure to spot market prices on uncontracted volumes, as at December 31, 2009, Western Power had entered into fixed-price power sales contracts to sell approximately 8,400 gigawatt hours (GWh) for 2010 and 6,000 GWh for 2011.
In fourth 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 2010 and 2011.
Bruce Power Results
(TransCanada's proportionate share) Three months ended Year ended
(unaudited) December 31 December 31
(millions of dollars unless
otherwise indicated) 2009 2008 2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenues(1)(2) 198 182 883 785
Operating Expenses(2) (128) (112) (531) (510)
----------------------------------------
Comparable EBITDA(3) 70 70 352 275
----------------------------------------
----------------------------------------
Bruce A Comparable EBITDA(3) (29) (1) 48 78
Bruce B Comparable EBITDA(3) 99 71 304 197
----------------------------------------
Comparable EBITDA(3) 70 70 352 275
----------------------------------------
----------------------------------------
Bruce Power - Other Information
Plant availability
Bruce A 47% 62% 78% 82%
Bruce B 95% 98% 91% 87%
Combined Bruce Power 80% 86% 87% 86%
Planned outage days
Bruce A 10 46 56 91
Bruce B - - 45 100
Unplanned outage days
Bruce A 74 17 82 27
Bruce B 3 5 47 65
Sales volumes (GWh)
Bruce A 737 977 4,894 5,159
Bruce B 2,016 2,218 7,767 7,799
----------------------------------------
2,753 3,195 12,661 12,958
----------------------------------------
Results per MWh
Bruce A power revenues $ 64 $ 63 $ 64 $ 62
Bruce B power revenues(4) $ 62 $ 57 $ 64 $ 57
Combined Bruce Power revenues $ 62 $ 58 $ 64 $ 59
Percentage of Bruce B output sold
to spot market(5) 46% 24% 43% 33%
----------------------------------------
----------------------------------------
(1) Revenues include Bruce A's fuel cost recoveries of $6 million and $34
million for fourth quarter and the year ended December 31, 2009,
respectively (2008 - $8 million and $30 million, respectively). Revenues
also include Bruce B unrealized gains of $1 million and $5 million as a
result of changes in the fair value of held-for-trading derivatives for
fourth quarter and the year ended December 31, 2009, respectively (2008
- losses of $1 million and $2 million, respectively).
(2) Includes adjustments to eliminate the effects of inter-partnership
transactions between Bruce A and Bruce B.
(3) Refer to the Non-GAAP Measures section in this news release for further
discussion of comparable EBITDA.
(4) Includes revenues received under the floor price mechanism, contract
settlements, deemed generation and the associated generation and deemed
generation volumes.
(5) All of Bruce B's output is covered by the floor price mechanism,
including volumes sold to the spot market.
TransCanada's proportionate share of Bruce Power's comparable EBITDA of $70 million in fourth quarter 2009 was consistent with fourth quarter 2008. Increased revenues from higher realized prices and an annual lease expense reduction at Bruce B were offset by higher non-lease operating expenses and lower volumes resulting from an increase in outage days.
TransCanada's proportionate share of Bruce A's comparable EBITDA decreased $28 million to a loss of $29 million in fourth quarter 2009 compared to a loss of $1 million in fourth quarter 2008 as a result of decreased volumes and higher operating costs due to an unplanned extension of the two planned outages which were rescheduled from March 2009 to September 2009. Bruce A's availability in fourth quarter 2009 was 47 per cent as a result of 84 outage days compared to an availability of 62 per cent and 63 outage days in the same period in 2008.
TransCanada's proportionate share of Bruce B's comparable EBITDA increased $28 million to $99 million in fourth quarter 2009 compared to fourth 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), as well as a reduction in annual lease expense. Provisions in the Bruce B lease agreement with Ontario Power Generation allowed for a reduction in annual lease expense as the annual Ontario spot price for electricity was less than $30 per MWh.
Amounts received under the Bruce B floor price mechanism in any calendar year are subject to repayment if the annual average spot price exceeds the average annual floor price. In 2009, the annual average spot price did not exceed the annual average floor price, therefore, no amounts recorded in revenue in 2009 will be repaid. 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 annual average floor price.
TransCanada's share of Bruce Power's generation in fourth quarter 2009 decreased to 2,753 GWh compared to 3,195 GWh in fourth quarter 2008, partially due to periods in fourth quarter 2009 when the Independent Electricity System Operator (IESO) curtailed certain units at Bruce Power to address surplus baseload generation in Ontario. During these unit curtailments by the IESO, Bruce Power received deemed generation payments at OPA contract prices. Including deemed generation, the Bruce Power units' combined average availability was 80 per cent in fourth quarter 2009 compared to 86 per cent in fourth quarter 2008.
Under a contract with the OPA, all of the output from Bruce A in fourth 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 fourth quarter 2008. All output from the Bruce B units were subject to a floor price of $48.76 per MWh in fourth quarter 2009 and $47.66 per MWh in fourth quarter 2008. Both the Bruce A and Bruce B contract prices are adjusted annually for inflation on April 1.
Bruce B also enters into fixed-price contracts where the difference between the contract price and the spot price is received. Bruce B's realized price of $62 per MWh in fourth quarter 2009 reflects revenues recognized from both the floor price mechanism and contract sales, compared to $57 per MWh in the same period in 2008 during which no revenues were recognized under the floor price mechanism. At December 31, 2009, Bruce B had sold forward approximately 2,100 GWh and 500 GWh, representing TransCanada's proportionate share, for 2010 and 2011, respectively.
The overall plant availability percentage in 2010 is expected to be in the mid-80s for the two operating Bruce A units and in the high 80s for the four Bruce B units. An approximate ten week maintenance outage of Bruce A Unit 3 is scheduled to begin in late February 2010. An approximate eight week maintenance outage of Bruce B Unit 6 is scheduled to being in mid-May 2010 and an approximate eight week outage for Unit 5 is scheduled to begin mid-October 2010.
U.S. Power Comparable EBITDA(1)(2)
Three months ended Year ended
(unaudited) December 31 December 31
(millions of dollars) 2009 2008 2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenues
Power 233 282 1,118 938
Capacity 40 37 190 85
Other(3)(4) 145 92 509 350
----------------------------------------
418 411 1,817 1,373
----------------------------------------
Commodity Purchases Resold
Power (125) (159) (544) (519)
Other(5) (120) (85) (391) (324)
----------------------------------------
(245) (244) (935) (843)
----------------------------------------
Plant operating costs and other(4) (134) (104) (645) (258)
General, administrative and
support costs (10) (13) (45) (41)
----------------------------------------
Comparable EBITDA(1) 29 50 192 231
----------------------------------------
----------------------------------------
(1) Refer to the Non-GAAP Measures section of this news release for further
discussion of comparable EBITDA.
(2) Includes phase one of Kibby Wind and Ravenswood effective October 2009
and August 2008, respectively.
(3) Other revenue includes sales of natural gas.
(4) Includes revenues and costs at Ravenswood related to a third-party
service agreement.
(5) Other commodity purchases resold includes the cost of natural gas sold.
U.S. Power Sales Operating Statistics(1)
Three months ended Year ended
December 31 December 31
(unaudited) 2009 2008 2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Sales Volumes (GWh)
Supply
Generation 1,400 1,127 5,993 3,974
Purchased 1,657 1,637 5,310 6,020
----------------------------------------
3,057 2,764 11,303 9,994
----------------------------------------
----------------------------------------
Sales
Contracted 2,999 2,726 10,264 9,758
Spot 58 38 1,039 236
----------------------------------------
3,057 2,764 11,303 9,994
----------------------------------------
----------------------------------------
(1) Includes phase one of Kibby Wind and Ravenswood effective October 2009
and August 2008, respectively.
U.S. Power's comparable EBITDA for fourth quarter 2009 of $29 million decreased $21 million compared to the same period in 2008. The decrease was primarily due to lower overall realized power prices and the impact of a weaker U.S. dollar, partially offset by incremental revenue realized on contract sales in New England. While average spot market power prices in New England decreased in fourth quarter 2009 compared to fourth quarter 2008, the majority of U.S. Power's sales volumes are sold at contracted prices.
U.S. Power's power revenues for fourth quarter 2009 of $233 million decreased from $282 million for the same period in 2008 due to the impact of a weaker U.S. dollar and lower realized power prices, partially offset by higher volumes of power sold, higher revenues from Ravenswood as a result of the expiry of a tolling agreement with a third party at December 31, 2008 and an increase in financial contract sales. Beginning in 2009, the marketing output of Ravenswood has been managed in a manner consistent with the Company's other northeast U.S. portfolio of assets.
Power commodity purchases resold of $125 million for fourth quarter 2009 decreased from $159 million in the same period in 2008 primarily due to the impact of a weaker U.S. dollar in 2009 and a lower overall cost per GWh on purchased power volumes.
Other revenues and other power commodity purchases resold of $145 million and $120 million, respectively, increased in fourth quarter 2009 compared to the same period in 2008 due to an increase in the volume of natural gas sold, partially offset by the impact of a weaker U.S. dollar in 2009.
Plant operating costs and other of $134 million for fourth quarter 2009 increased $30 million from the same period in 2008 due to higher costs at Ravenswood as a result of the expiry of a tolling agreement with a third party on December 31, 2008, partially offset by the impact of a weaker U.S. dollar in 2009.
In fourth quarter 2009, two per cent of power sales volumes were sold into the spot market, compared to one per cent for the same period in 2008. To reduce its exposure to spot market prices on uncontracted volumes, as at December 31, 2009, U.S. Power had entered into fixed-price power sales contracts to sell approximately 10,300 GWh for 2010 and 5,400 GWh for 2011, including financial contracts to economically hedge the price of forecasted generation. Certain contracted volumes are dependent on customer usage levels and actual amounts contracted in future periods will depend on market liquidity and other factors.
Natural Gas Storage
Natural Gas Storage's comparable EBITDA for fourth quarter 2009 was $49 million compared to $34 million for the same period in 2008. The $15 million increase in EBITDA in fourth quarter 2009 was primarily due to increased third party storage revenues as a result of higher realized seasonal natural gas price spreads. Comparable EBITDA excluded net unrealized gains of $7 million in fourth quarter 2009 (2008 - gains of $7 million), resulting from changes in the fair value of proprietary natural gas inventory in storage and natural gas forward purchase and sale contracts.
Business Development
Business development comparable EBITDA losses of $6 million in fourth quarter 2009 decreased $11 million compared to the same period in 2008 primarily due to the timing of certain key projects.
Depreciation and Amortization
Depreciation and amortization for fourth quarter 2009 of $86 million increased $6 million compared to the same period in 2008, primarily due to Portlands Energy which went into service in April 2009.
Corporate
Corporate EBIT losses for fourth quarter 2009 were $28 million compared to losses of $33 million for the same period in 2008. The decreases in EBIT losses were primarily due to lower support service costs in fourth quarter 2009.
Other Income Statement Items
Interest Expense
Three months ended Year ended
(unaudited) December 31 December 31
(million of dollars) 2009 2008 2009 2008
----------------------------------------------------------------------------
Interest on long-term debt(1) 304 299 1,285 1,038
Other interest and amortization 8 71 27 46
Capitalized interest (128) (44) (358) (141)
----------------------------------------
184 326 954 943
----------------------------------------
----------------------------------------
(1) Includes interest for Junior Subordinated Notes.
Interest expense for fourth quarter 2009 decreased $142 million to $184 million from $326 million in fourth quarter 2008. The decrease reflected increased capitalized interest to finance the Company's larger capital growth program in 2009, primarily due to Keystone construction, and a decrease in U.S. dollar-denominated interest expense due to the impact of a weaker U.S. dollar in fourth quarter 2009 compared to fourth quarter 2008. Interest expense also decreased due to reduced losses in fourth quarter 2009 compared to 2008 from changes in the fair value of derivatives used to manage the Company's exposure to interest rate fluctuations. These decreases were partially offset by incremental interest expense on new debt issues of US$2.0 billion in January 2009 and $700 million in February 2009.
Interest Income and Other for fourth quarter 2009 was income of $22 million compared to an expense of $4 million for the same period in 2008. The increase in income of $26 million in fourth quarter 2009 was primarily due to the positive impact of a weaker U.S. dollar on working capital balances and higher gains from changes in the fair value of derivatives used to manage the Company's exposure to foreign exchange rate fluctuations in fourth quarter 2009. These increases were partially offset by lower interest income due to lower interest rates.
Income Taxes were $67 million in fourth quarter 2009 compared to $95 million for the same period in 2008. The decrease was primarily due to positive income tax adjustments in 2009, including a $30 million favourable adjustment resulting from a reduction in the Province of Ontario's corporate income tax rates, partially offset by higher pre-tax income.
Non-Controlling Interests were $25 million for fourth quarter 2009 compared to $24 million for the same period in 2008.
Consolidated Income
(unaudited)
(millions of dollars except Three months ended Year ended
number of shares and December 31 December 31
per share amounts) 2009 2008 2009 2008
----------------------------------------------------------------------------
Revenues 2,206 2,332 8,966 8,619
----------------------------------------
Operating and Other
Expenses/(Income)
Plant operating costs and other 823 857 3,367 3,014
Commodity purchases resold 411 424 1,511 1,501
Other income (29) - (49) (38)
Calpine bankruptcy settlements - - - (279)
Writedown of Broadwater LNG
project costs - - - 41
----------------------------------------
1,205 1,281 4,829 4,239
----------------------------------------
1,001 1,051 4,137 4,380
Depreciation and amortization 343 304 1,377 1,247
----------------------------------------
658 747 2,760 3,133
----------------------------------------
Financial Charges/(Income)
Interest expense 184 326 954 943
Interest expense of joint ventures 17 21 64 72
Interest income and other (22) 4 (121) (54)
----------------------------------------
179 351 897 961
----------------------------------------
Income before Income Taxes and
Non-Controlling Interests 479 396 1,863 2,172
----------------------------------------
Income Taxes
Current (73) 47 30 526
Future 140 48 357 76
----------------------------------------
67 95 387 602
----------------------------------------
Non-Controlling Interests
Non-controlling interest in
PipeLines LP 15 16 66 62
Preferred share dividends of
subsidiary 5 5 22 22
Non-controlling interest in
Portland 5 3 8 46
----------------------------------------
25 24 96 130
----------------------------------------
Net Income 387 277 1,380 1,440
Preferred Share Dividends 6 - 6 -
----------------------------------------
Net Income Applicable to Common
Shares 381 277 1,374 1,440
----------------------------------------
----------------------------------------
Net Income Per Common Share
Basic $0.56 $0.47 $2.11 $2.53
----------------------------------------
----------------------------------------
Diluted $0.56 $0.46 $2.11 $2.52
----------------------------------------
----------------------------------------
Average Common Shares
Outstanding
- Basic (millions) 683 597 652 570
----------------------------------------
----------------------------------------
Average Common Shares
Outstanding
- Diluted (millions) 684 599 653 572
----------------------------------------
----------------------------------------
Consolidated Cash Flows
Three months ended Year ended
December 31 December 31
(unaudited)(millions of dollars) 2009 2008 2009 2008
----------------------------------------------------------------------------
Cash Generated From Operations
Net income 387 277 1,380 1,440
Depreciation and amortization 343 304 1,377 1,247
Future income taxes 140 48 357 76
Non-controlling interests 25 24 96 130
Employee future benefits funding
(in excess of)/ lower than expense (32) (6) (111) 17
Writedown of Broadwater LNG
project costs - - - 41
Other (13) 65 (19) 70
----------------------------------------
850 712 3,080 3,021
(Increase)/decrease in operating
working capital (217) (150) (90) 135
----------------------------------------
Net cash provided by operations 633 562 2,990 3,156
----------------------------------------
Investing Activities
Capital expenditures (1,474) (1,235) (5,417) (3,134)
Acquisitions, net of cash
acquired - (171) (902) (3,229)
Disposition of assets, net of
current income taxes - 7 - 28
Deferred amounts and other (300) (372) (594) (484)
----------------------------------------
Net cash used in investing
activities (1,774) (1,771) (6,913) (6,819)
----------------------------------------
Financing Activities
Dividends on common and preferred
shares (193) (167) (728) (577)
Distributions paid to non-
controlling interests (24) (31) (100) (141)
Notes payable issued/(repaid),
net 363 827 (244) 1,293
Long-term debt issued, net of
issue costs - - 3,267 2,197
Reduction of long-term debt (496) (52) (1,005) (840)
Long-term debt of joint ventures
issued 25 16 226 173
Reduction of long-term debt of
joint ventures (138) (19) (246) (120)
Common shares issued, net of
issue costs 15 1,132 1,820 2,384
Partnership units of subsidiary
issued, net of issue costs 193 - 193 -
Preferred shares issued, net of
issue costs - - 539 -
----------------------------------------
Net cash (used in)/provided by
financing activities (255) 1,706 3,722 4,369
----------------------------------------
Effect of Foreign Exchange Rate
Changes on Cash and Cash
Equivalents (13) 59 (110) 98
----------------------------------------
(Decrease)/Increase in Cash and
Cash Equivalents (1,409) 556 (311) 804
Cash and Cash Equivalents
Beginning of period 2,406 752 1,308 504
----------------------------------------
Cash and Cash Equivalents
End of period 997 1,308 997 1,308
----------------------------------------
----------------------------------------
Consolidated Balance Sheet
December 31
(unaudited)(millions of dollars) 2009 2008
----------------------------------------------------------------------------
ASSETS
Current Assets
Cash and cash equivalents 997 1,308
Accounts receivable 966 1,280
Inventories 511 489
Other 701 523
----------------------------
3,175 3,600
Plant, Property and Equipment 32,879 29,189
Goodwill 3,763 4,397
Regulatory Assets 1,524 201
Intangibles and Other Assets 2,500 2,027
----------------------------
43,841 39,414
----------------------------
----------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Notes payable 1,687 1,702
Accounts payable 2,195 2,110
Accrued interest 377 359
Current portion of long-term debt 478 786
Current portion of long-term debt of
joint ventures 212 207
----------------------------
4,949 5,164
Regulatory Liabilities 385 317
Deferred Amounts 743 1,168
Future Income Taxes 2,856 1,223
Long-Term Debt 16,186 15,368
Long-Term Debt of Joint Ventures 753 869
Junior Subordinated Notes 1,036 1,213
----------------------------
26,908 25,322
----------------------------
Non-Controlling Interests
Non-controlling interest in
PipeLines LP 705 721
Preferred shares of subsidiary 389 389
Non-controlling interest in Portland 80 84
----------------------------
1,174 1,194
----------------------------
Shareholders' Equity 15,759 12,898
----------------------------
43,841 39,414
----------------------------
----------------------------
Segmented Information
Three months ended
December 31 Pipelines Energy Corporate Total
(unaudited)(millions -------------------------------------------------------
of dollars) 2009 2008 2009 2008 2009 2008 2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenues 1,171 1,233 1,035 1,099 - - 2,206 2,332
Plant operating costs
and other (428) (451) (368) (373) (27) (33) (823) (857)
Commodity purchases
resold - - (411) (424) - - (411) (424)
Other income/(expense) 31 (2) (1) 2 (1) - 29 -
------------------------------------------------------
774 780 255 304 (28) (33) 1,001 1,051
Depreciation and
amortization (257) (224) (86) (80) - - (343) (304)
------------------------------------------------------
517 556 169 224 (28) (33) 658 747
----------------------------------------
----------------------------------------
Interest expense (184) (326)
Interest expense of
joint ventures (17) (21)
Interest income and
other 22 (4)
Income taxes (67) (95)
Non-controlling
interests (25) (24)
--------------
Net Income 387 277
Preferred share
dividends (6) -
--------------
Net Income Applicable
to Common Shares 381 277
--------------
--------------
Year ended
December 31 Pipelines Energy Corporate Total
(unaudited) -------------------------------------------------------------
(millions
of dollars) 2009 2008 2009 2008 2009 2008 2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenues 4,729 4,650 4,237 3,969 - - 8,966 8,619
Plant operating
costs and other (1,655) (1,645) (1,595) (1,259) (117) (110) (3,367) (3,014)
Commodity
purchases resold - - (1,511) (1,501) - - (1,511) (1,501)
Other income 48 31 1 1 - 6 49 38
Calpine
bankruptcy
settlements - 279 - - - - - 279
Writedown of
Broadwater LNG
project costs - - - (41) - - - (41)
------------------------------------------------------------
3,122 3,315 1,132 1,169 (117) (104) 4,137 4,380
Depreciation and
amortization (1,030) (989) (347) (258) - - (1,377) (1,247)
------------------------------------------------------------
2,092 2,326 785 911 (117) (104) 2,760 3,133
--------------------------------------------
--------------------------------------------
Interest expense (954) (943)
Interest expense
of joint ventures (64) (72)
Interest income
and other 121 54
Income taxes (387) (602)
Non-controlling
interests (96) (130)
----------------
Net Income 1,380 1,440
Preferred share
dividends (6) -
----------------
Net Income Applicable to Common Shares 1,374 1,440
----------------
----------------
TransCanada welcomes questions from shareholders and potential investors. Please telephone:
Investor Relations, at 1.800.361.6522 (Canada and U.S. Mainland) or direct dial David Moneta/Myles Dougan/Terry Hook at 403.920.7911. The investor fax line is 403.920.2457. Media Relations: Cecily Dobson/Terry Cunha 403.920.7859 or 1.800.608.7859.
Visit the TransCanada website at: http://www.transcanada.com.
CONTACT INFORMATION
TransCanada
Media Inquiries
Cecily Dobson/Terry Cunha
(403) 920-7859 or (800) 608-7859
or
Analyst Inquiries
David Moneta/Myles Dougan/Terry Hook
(403) 920-7911 or (800) 361-6522
www.transcanada.com