TransCanada Reports Third Quarter Net Income of $345 Million or $0.50 Per Common Share
Funds Generated from Operations of $772 Million
CALGARY, ALBERTA--(Marketwire - Nov. 4, 2009) - TransCanada Corporation (TSX:TRP) (NYSE:TRP) (TransCanada or the Company) today announced net income for third quarter 2009 of $345 million or $0.50 per common share. TransCanada's Board of Directors also declared a quarterly dividend of $0.38 per common share.
"TransCanada continues to post solid earnings and strong cash flows on the strength of our diverse energy infrastructure business. Third quarter earnings were ahead of last year for our pipelines and natural gas storage assets, while the economic downturn continues to impact power revenues," said Hal Kvisle, TransCanada's president and chief executive officer.
"We made significant progress during the quarter executing the major projects within our $22 billion capital program. TransCanada is well positioned to fund this unprecedented growth. The carrying costs and dilution associated with financing this multi-year program continues to have a near-term impact on our earnings and cash flow per share. However, we are confident that our capital program will generate significant growth in cash flows and earnings over the next four years as our large scale, highly attractive projects commence operations."
Third Quarter 2009 Highlights
(All financial figures are unaudited and in Canadian dollars unless noted otherwise)
- Net income of $345 million or $0.50 per common share
- Comparable earnings of $335 million or $0.49 per common share
- Comparable earnings before interest, taxes, depreciation and amortization (EBITDA) of $994 million
- Funds generated from operations of $772 million
- Dividend of $0.38 per common share declared by the Board of Directors
- Awarded a 20-year contract to build, own and operate a $1.2 billion, 900 megawatt (MW) power generating station in Oakville, Ontario
- Issued $550 million of cumulative redeemable first preferred shares
- Continued to advance $22 billion capital program
TransCanada reported net income for third quarter 2009 of $345 million ($0.50 per common share) compared to $390 million ($0.67 per common share) for third quarter 2008.
Comparable earnings were $335 million ($0.49 per common share) in third quarter 2009 compared to $366 million ($0.63 per common share) for the same period in 2008. This decrease was primarily due to lower power prices and volumes sold in Western Power and reduced generation volumes from New England and Bruce Power.
Partially offsetting these decreases were higher earnings from Canadian pipelines, natural gas storage, Ravenswood acquired in August 2008 and the start up of Portlands Energy and the Carleton wind farm.
Comparable earnings per common share in third quarter 2009 was further reduced compared to the same period last year due to an 18 per cent increase in the average number of shares outstanding following the Company's issuances of 58.4 million and 35.1 million common shares in second quarter 2009 and fourth quarter 2008, respectively. Proceeds from the offerings were used to fund the acquisition of additional interests in Keystone and for other capital projects, general corporate purposes and to repay short-term debt. TransCanada's $22 billion capital program is expected to boost cash flow and earnings in the coming years as projects come on-line.
Comparable earnings in third quarter 2009 and 2008 excluded $10 million of after tax net unrealized gains and $2 million of after tax net unrealized losses, respectively, resulting from changes in the fair value of proprietary natural gas inventory in storage and natural gas forward purchase and sale contracts. Comparable earnings in 2008 also excluded $26 million of favourable income tax adjustments.
Comparable EBITDA in third quarter 2009 was $994 million compared to $1,066 million in third quarter 2008.
Funds generated from operations in third quarter 2009 were $772 million compared to $711 million in third quarter 2008.
Notable recent developments in Pipelines, Energy and Corporate include:
Pipelines:
- On August 14, 2009, TransCanada purchased ConocoPhillips' remaining interest in Keystone for US$553 million plus the assumption of US$197 million of short-term debt. TransCanada now owns 100 per cent of this project.
TransCanada also assumed responsibility for ConocoPhillips' share of the capital investment required to complete the project, resulting in an incremental commitment of US$1.7 billion through the end of 2012.
The first phase of the pipeline is now approximately 90 per cent complete and TransCanada expects to begin filling the line in the fourth quarter of this year with deliveries of oil to the U.S. Midwest commencing in first quarter 2010.
Keystone is currently seeking the necessary regulatory approvals in Canada and the U.S. to build and operate an expansion and extension of the pipeline system that will provide additional capacity of 500,000 barrels per day (bbl/d) from Western Canada to the Gulf Coast in 2012.
In September 2009, the National Energy Board (NEB) held a hearing to review the application for the Canadian portion of the Keystone Gulf Coast expansion with a decision expected in early 2010. Permits for the U.S. portion of the expansion are expected by mid-2010. Construction of the Keystone expansion is expected to begin in 2010 once TransCanada receives all the necessary regulatory approvals.
When completed, the approximately US$12 billion Keystone pipeline will be one of the largest oil delivery systems in North America with the capacity to deliver 1.1 million bbl/d from Western Canada to the largest refining markets in the United States.
Keystone has secured long-term commitments for 910,000 bbl/d for an average term of 18 years, which represents 83 per cent of the commercial design of the system.
The pipeline is expected to begin generating EBITDA in first quarter 2010 when oil begins flowing to Wood River and Patoka, Illinois. EBITDA is expected to increase through 2011 and 2012 as future phases of Keystone become operational.
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 were to increase to 1.1 million bbl/d, Keystone would generate approximately US$1.5 billion of annual EBITDA. In the future, the pipeline could be economically expanded from 1.1 million bbl/d to 1.5 million bbl/d based on market demand.
- On September 28, 2009, TransCanada began work on the 160 kilometre (km) Red Earth section of the North Central Corridor (NCC) pipeline that is expected to be complete by April 2010. The 140 km North Star section has been completed and two 13 MW compressor units at the Meikle River compressor station were operational on May 15, 2009 and August 21, 2009 respectively.
The NCC project is a 300 km natural gas pipeline in the northern section of the Alberta System. It will provide capacity needed to deal with increasing gas supply in northwest Alberta and northeast B.C., declining gas supply in northeast Alberta, growing markets within the province, and help deliver more gas to interconnecting pipelines at the Alberta-Saskatchewan border.
The NCC pipeline is expected to reduce fuel consumption on the entire Alberta System by approximately 50 per cent which is expected to result in shipper savings of between $50 million-$75 million per year.
- The Alaska Pipeline Project continues to move forward, with the joint TransCanada and ExxonMobil project team actively advancing the engineering, technical, commercial, environmental and stakeholder engagement work leading to the project's initial open season targeted for completion by July 2010.
Energy:
- On September 30, 2009 the Ontario Power Authority (OPA) awarded TransCanada a 20-year clean energy supply contract to build, own and operate the 900 MW Oakville Generating Station in Oakville, Ontario. A contract has now been finalized with the OPA.
TransCanada expects to invest approximately $1.2 billion in the natural gas-fired, combined-cycle plant, scheduled to start producing power by the end of 2013.
- Commissioning of the first phase of the Kibby Wind Power project began in September 2009. Twenty-two of the 44 turbines have been constructed and were in service effective October 30, 2009. Roads and foundations for the remaining 22 turbines will be completed this year and the turbines are expected to be installed and operational by the end of third quarter 2010. Kibby will have the capacity to produce 132 MW.
- Construction of the approximately $670 million, 683 MW Halton Hills Generating Station is continuing on schedule and the facility is anticipated to be in service in the summer of 2010. All of the power produced by the facility will be sold to the OPA under a 20-year power purchase agreement.
- TransCanada began construction of the US$500 million Coolidge Generating Station in August 2009. The 575 MW power facility is expected to be on-line in second quarter 2011. All of the power produced by the facility will be sold to the Phoenix, Arizona based utility Salt River Project under a 20-year power purchase agreement.
The simple-cycle, natural gas-fired peaking facility will provide a quick response to peak power demand. The facility will also provide reserve capacity and have the ability to generate power on short notice to support power reliability in the region.
- Initial brush clearing work for the 212 MW Gros-Morne wind farm in Quebec has been completed. Clearing for the 58 MW Montagne-Seche wind farm will be completed by the end of November 2009.
The Montagne-Seche project and phase one of the Gros-Morne wind farm are expected to be operational by 2011. Gros-Morne phase two is 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. These two wind farms are expected to have a capital cost of approximately $340 million. Once these two phases are complete, Cartier Wind will be capable of producing 590 MW of electricity. All of the power produced by Cartier Wind is sold to Hydro- Quebec Distribution under a 20-year power purchase agreement.
- Progress continues on the refurbishment and restart of Bruce A Units 1 and 2 with work now advanced to the re-assembly of the reactors. As of September 30, 2009, Bruce A had incurred approximately $3.1 billion in costs for the refurbishment and restart of Units 1 and 2. TransCanada believes that the work on Units 1 and 2 is now approximately 75 per cent complete, with the bulk of the highly technical, high risk work now finished. Although a significant amount of work remains to be done, most of this work is conventional power plant construction activity.
The project has experienced delays and TransCanada now expects that Unit 2 will be restarted mid-2011, with Unit 1 expected to follow approximately four months thereafter. The impact of this delay is mitigated by the previously announced extension of the operating lives of Unit 3 to 2011 and Unit 4 to 2016, with further life extensions expected as additional reactor optimization activities proceed. TransCanada continues to work closely with Bruce Power to address productivity and overall project management and notes that there have been recent, significant successes in this area.
Corporate:
- TransCanada and its subsidiaries held cash and cash equivalents of $2.4 billion at September 30, 2009.
- On September 30, 2009, TransCanada completed a public offering of 22 million cumulative redeemable first preferred shares. Proceeds from the preferred share offering totalled $550 million and are expected to be used by TransCanada to partially fund capital projects, for general corporate purposes and to re-pay short-term debt of TransCanada and its affiliates.
- 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 the financing of TransCanada's capital program.
Teleconference - Audio and Slide Presentation
TransCanada will hold a teleconference and webcast to discuss its 2009 third 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, members of the media and other interested parties.
Event:
TransCanada third quarter 2009 financial results teleconference and webcast
Date:
Wednesday, November 4, 2009
Time:
9 a.m. mountain standard time (MST) /11 a.m. eastern standard time (EST)
How:
To participate in the teleconference, please call (800) 769-8320 or (416) 695-6622 (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) November 11, 2009. Please call (800) 408-3053 or (416) 695-5800 (Toronto area) and enter pass code 1281126#. 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 11,800 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 security holders 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 common 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, 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. Comparable earnings per common 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 Third Quarter 2009 Financial Highlights chart in this news release.
Third Quarter 2009 Financial Highlights
Operating Results
Three months ended Nine months ended
(unaudited) September 30 September 30
(millions of dollars) 2009 2008 2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenues 2,253 2,137 6,760 6,287
Comparable EBITDA(1) 994 1,066 3,142 3,081
Comparable EBIT(1) 651 748 2,108 2,138
EBIT(1) 665 746 2,102 2,386
Net Income 345 390 993 1,163
Comparable Earnings(1) 335 366 997 1,008
Cash Flows
Funds generated from operations(1) 772 711 2,230 2,309
(Increase)/decrease in operating
working capital (31) 114 362 16
----------------------------------------
Net cash provided by operations 741 825 2,592 2,325
----------------------------------------
----------------------------------------
Capital Expenditures 1,557 806 3,943 1,899
Acquisitions, Net of Cash Acquired 653 3,054 902 3,058
----------------------------------------
----------------------------------------
Common Share Statistics
Three months ended Nine months ended
September 30 September 30
(unaudited) 2009 2008 2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net Income Per Share - Basic $ 0.50 $ 0.67 $ 1.55 $ 2.07
Comparable Earnings Per Share(1) $ 0.49 $ 0.63 $ 1.56 $ 1.80
Dividends Declared Per Share $ 0.38 $ 0.36 $ 1.14 $ 1.08
Basic Common Shares Outstanding
(millions)
Average for the period 681 579 641 560
End of period 681 580 681 580
----------------------------------------
----------------------------------------
(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 common share and funds generated from
operations.
TRANSCANADA CORPORATION - THIRD QUARTER 2009
Quarterly Report to Shareholders
Management's Discussion and Analysis
Management's Discussion and Analysis (MD&A) dated November 3, 2009 should be read in conjunction with the accompanying unaudited Consolidated Financial Statements of TransCanada Corporation (TransCanada or the Company) for the three and nine months ended September 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 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 other things, 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 industry 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 common 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.
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, 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 common 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 "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
September 30
(unaudited)(millions of
dollars except per Pipelines Energy Corporate Total
share amounts) 2009 2008 2009 2008 2009 2008 2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Comparable EBITDA(1) 730 723 292 366 (28) (23) 994 1,066
Depreciation and
amortization (255) (254) (88) (64) - - (343) (318)
----------------------------------------------------
Comparable EBIT(1) 475 469 204 302 (28) (23) 651 748
Specific item:
Fair value adjustments
of natural gas
inventory and forward
contracts - - 14 (2) - - 14 (2)
----------------------------------------------------
EBIT(1) 475 469 218 300 (28) (23) 665 746
----------------------------------------------------
----------------------------------------------------
Interest expense (216) (213)
Financial charges of
joint ventures (17) (18)
Interest income and
other 43 22
Income taxes (107) (129)
Non-controlling
interests (23) (18)
--------------
Net Income 345 390
Specific items (net of
tax, where applicable):
Fair value adjustments
of natural gas inventory
and forward contracts (10) 2
Income tax reassessments and
adjustments - (26)
--------------
Comparable Earnings(1) 335 366
--------------
--------------
Net Income Per Common Share
- Basic and Diluted(2) $ 0.50 $ 0.67
--------------
--------------
(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 common share.
(2) For the three months ended September 30
(unaudited) 2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net Income Per Common Share $ 0.50 $ 0.67
Specific items (net of tax, where applicable):
Fair value adjustments of natural gas inventory and
forward contracts (0.01) -
Income tax reassessments and adjustments - (0.04)
------------------------
Comparable Earnings Per Common Share(1) $ 0.49 $ 0.63
------------------------
------------------------
For the nine months ended
September 30
(unaudited)(millions of
dollars except Pipelines Energy Corporate Total
per share amounts) 2009 2008 2009 2008 2009 2008 2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Comparable EBITDA(1) 2,348 2,239 883 913 (89) (71) 3,142 3,081
Depreciation and
amortization (773) (765) (261) (178) - - (1,034) (943)
----------------------------------------------------
Comparable EBIT(1) 1,575 1,474 622 735 (89) (71) 2,108 2,138
Specific items:
Fair value adjustments
of natural gas
inventory and forward
contracts - - (6) (7) - - (6) (7)
Calpine bankruptcy
settlements - 279 - - - - - 279
GTN lawsuit settlement - 17 - - - - - 17
Writedown of Broadwater
LNG project costs - - - (41) - - - (41)
----------------------------------------------------
EBIT(1) 1,575 1,770 616 687 (89) (71) 2,102 2,386
-------------------------------------
-------------------------------------
Interest expense (770) (617)
Financial charges of
joint ventures (47) (51)
Interest income and
other 99 58
Income taxes (320) (507)
Non-controlling
interests (71) (106)
--------------
Net Income 993 1,163
Specific items (net of
tax, where applicable):
Fair value adjustments
of natural gas inventory
and forward contracts 4 6
Calpine bankruptcy
settlements - (152)
GTN lawsuit settlement - (10)
Writedown of Broadwater
LNG project costs - 27
Income tax reassessments and
adjustments - (26)
--------------
Comparable Earnings(1) 997 1,008
--------------
--------------
Net Income Per Common Share
- Basic and Diluted(2) $ 1.55 $ 2.07
--------------
--------------
(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 common share.
(2) For the nine months ended September 30
(unaudited) 2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net Income Per Common Share $ 1.55 $ 2.07
Specific items (net of tax, where applicable):
Fair value adjustments of natural gas inventory
and forward contracts 0.01 0.01
Calpine bankruptcy settlements - (0.27)
GTN lawsuit settlement - (0.02)
Writedown of Broadwater LNG project costs - 0.05
Income tax reassessments and adjustments - (0.04)
--------------------------
Comparable Earnings Per Common Share(1) $ 1.56 $ 1.80
--------------------------
--------------------------
TransCanada's net income in third quarter 2009 was $345 million or $0.50 per common share compared to $390 million or $0.67 per common share in third quarter 2008. The $45 million decrease in net income reflected:
- increased EBIT from Pipelines primarily due to increased earnings for the Alberta System as a result of a settlement approved in December 2008, the positive impact of a stronger U.S. dollar on Pipelines' U.S. operations and higher operations, maintenance and administrative (OM&A) cost savings for the Canadian Mainline;
- decreased EBIT from Energy primarily due to lower power prices in Western Power, and reduced volumes in Western Power, New England and Bruce Power. These decreases were partially offset by a $16 million year-over-year positive change in the pre-tax fair value adjustment of natural gas inventory and forward contracts, as well as increased earnings as a result of the acquisition of Ravenswood and the start up of Portlands Energy and the Carleton wind farm. Energy's EBIT also reflects higher contribution from the Natural Gas Storage business due to increased third party storage revenues;
- increased interest income and other 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; and
- decreased income tax expense primarily due to reduced earnings, higher income tax rate differentials and other positive income tax adjustments.
Earnings per common share in third quarter 2009 was further reduced by an 18 per cent increase in the average number of common shares outstanding 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 third quarter 2009 were $335 million or $0.49 per common share compared to $366 million or $0.63 per common share for the same period in 2008. Comparable earnings in third quarter 2009 and 2008 excluded $10 million of after tax ($14 million pre-tax) net unrealized gains and $2 million of after tax ($2 million pre-tax) net unrealized losses, respectively, resulting from changes in the fair value of proprietary natural gas inventory in storage and natural gas forward purchase and sale contracts. Comparable earnings in 2008 also excluded $26 million of favourable income tax adjustments.
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 and other income statement items. The resultant net exposure is managed using derivatives thereby effectively reducing the Company's exposure to changes in foreign exchange. The average U.S. dollar exchange rate for the three and nine months ended September 30, 2009 was 1.10 and 1.17, respectively (2008 - 1.04 and 1.02, respectively).
TransCanada's net income in the first nine months of 2009 was $993 million or $1.55 per common share compared to $1.2 billion or $2.07 per common share for the same period in 2008. The $170 million decrease in net income reflected:
- decreased EBIT from Pipelines primarily 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 in 2009 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 reduced volumes in Western Power and New England. These decreases were partially offset by higher realized prices at Bruce Power, increased earnings from the start up of Portlands Energy and the Carleton wind farm, and the positive impact of a stronger U.S. dollar on Energy's U.S. operations. EBIT also reflects 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;
- increased EBIT losses from Corporate due to higher support services costs as a result of a growing asset base;
- 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 an increase in interest capitalized relating to Keystone and other capital projects;
- increased interest income and other 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;
- decreased income tax expense due to lower earnings and higher income tax rate differentials in 2009; and
- a reduction in non-controlling interests due to Portland's portion of the Calpine bankruptcy settlements recorded in 2008.
Earnings per common share in the first nine months of 2009 was further reduced due to an increased average number of common shares outstanding following the Company's common share issuances in second quarter 2009 and fourth quarter 2008.
Comparable earnings in the first nine months of 2009 were $997 million or $1.56 per common share compared to $1.0 billion or $1.80 per common share for the same period in 2008. Comparable earnings for the first nine months of 2009 and 2008 excluded $4 million after tax ($6 million pre-tax) and $6 million after tax ($7 million pre-tax), respectively, of net unrealized losses from changes in the fair value of proprietary natural gas inventory in storage and natural gas forward purchase and sale contracts. In addition, comparable earnings in the first nine 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, the $27 million after tax writedown of Broadwater LNG project costs and $26 million of favourable income tax adjustments.
Results from each of the segments for the three and nine month periods ended September 30, 2009 are discussed further in the Pipelines, Energy and Corporate sections of this MD&A.
Pipelines
The Pipelines business generated comparable EBIT of $475 million and $1.6 billion in the three and nine month periods ended September 30, 2009, respectively, compared to $469 million and $1.5 billion for the same periods in 2008.
Comparable EBIT for the first nine months of 2008 excluded the $279 million of gains realized by GTN and Portland for the Calpine bankruptcy settlements and the $17 million gain on the GTN lawsuit settlement with a software supplier.
Pipelines Results
Three months ended Nine months ended
(unaudited) September 30 September 30
(millions of dollars) 2009 2008 2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Canadian Pipelines
Canadian Mainline 279 268 851 841
Alberta System 190 182 535 540
Foothills 32 33 100 102
Other (TQM, Ventures LP) 13 13 44 39
----------------------------------------
Canadian Pipelines Comparable
EBITDA(1) 514 496 1,530 1,522
----------------------------------------
U.S. Pipelines
ANR 57 74 263 248
GTN(2) 42 48 152 146
Great Lakes 31 28 108 93
Iroquois 18 15 62 42
PipeLines LP(3) 24 13 64 47
Portland(4) 2 4 18 18
International (Tamazunchale,
TransGas, INNERGY/Gas Pacifico) 18 10 46 32
General, administrative and
support costs(5) (11) (4) (17) (14)
Non-controlling interests(6) 45 40 148 133
----------------------------------------
U.S. Pipelines Comparable
EBITDA(1) 226 228 844 745
----------------------------------------
Business Development Comparable
EBITDA(1) (10) (1) (26) (28)
----------------------------------------
Pipelines Comparable EBITDA(1) 730 723 2,348 2,239
Depreciation and amortization (255) (254) (773) (765)
----------------------------------------
Pipelines Comparable EBIT(1) 475 469 1,575 1,474
Specific items:
Calpine bankruptcy settlements(7) - - - 279
GTN lawsuit settlement - - - 17
----------------------------------------
Pipelines EBIT(1) 475 469 1,575 1,770
----------------------------------------
----------------------------------------
(1) Refer to the Non-GAAP Measures section in this MD&A for further
discussion of comparable EBITDA, comparable EBIT and EBIT.
(2) GTN's results include North Baja to June 30, 2009.
(3) Effective July 1, 2009, TransCanada's ownership interest in PipeLines LP
increased to 42.6 per cent. As a result, PipeLines LP's results include
TransCanada's ownership of an additional 10.5 per cent of PipeLines LP
and TransCanada's effective ownership of 42.6 per cent of North Baja
since July 1, 2009.
(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) The non-controlling interests reflect PipeLines LP and Portland amounts
not owned by TransCanada.
(7) 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 Nine months ended
(unaudited) September 30 September 30
(millions of dollars) 2009 2008 2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Canadian Mainline 68 66 201 204
Alberta System 44 32 123 97
Foothills 6 6 18 19
----------------------------------------
----------------------------------------
Canadian Pipelines
Canadian Mainline's net income for the three and nine months ended September 30, 2009 increased $2 million and decreased $3 million, respectively, to $68 million and $201 million, respectively, compared to the same periods in 2008. Net income for third quarter 2009 reflected higher OM&A cost savings, partially offset by 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. Net income for the nine months ended September 30, 2009 decreased as higher OM&A cost savings were more than offset by the lower average investment base and ROE.
Canadian Mainline's EBITDA for the three and nine months ended September 30, 2009 of $279 million and $851 million, respectively, increased $11 million and $10 million, respectively, compared to the same periods in 2008, primarily due to higher revenues as a result of the recovery of higher depreciation and income taxes approved in the 2009 tolls, and higher OM&A cost savings. The increases in revenues were partially offset by a lower overall return on a reduced average investment base.
The Alberta System's net income was $44 million in third quarter 2009 and $123 million for the first nine months of 2009 compared to $32 million and $97 million for the same periods in 2008. Earnings in 2009 reflected the impact of a 2008-2009 settlement approved by the Alberta Utilities Commission (AUC) in December 2008 and the impact of a higher average investment base compared to 2008 due to customer-driven expansions of the Alberta System.
The Alberta System's EBITDA was $190 million in third quarter 2009 and $535 million for the first nine months of 2009 compared to $182 million and $540 million for the same periods in 2008. Third quarter EBITDA reflects increases due to higher settlement earnings and revenues as a result of the recovery of higher financial charges. For the nine months ended September 30, 2009, these increases were more than offset by reduced revenues as a result of the recovery of lower depreciation and income taxes approved in the settlement.
EBITDA from Other Canadian Pipelines was $13 million and $44 million for the three and nine months ended September 30, 2009, respectively, compared to $13 million and $39 million for the same periods in 2008. The increase in the nine month period was primarily due to the NEB decision on TQM's cost of capital for the years 2007 and 2008 reached in February 2009.
U.S. Pipelines
ANR's EBITDA for the three and nine months ended September 30, 2009 was $57 million and $263 million, respectively, compared to $74 million and $248 million, respectively, for the same periods in 2008. The decrease in EBITDA in third quarter 2009 was primarily due to reduced revenues as a result of lower utilization, lower incidental natural gas and condensate sales, and higher OM&A costs, partially offset by the positive impact of a stronger U.S. dollar. For the nine months ended September 30, 2009, the increase in EBITDA was primarily due to the positive impact of a stronger U.S. dollar and higher revenues, partially offset by lower natural gas and condensate sales, and higher OM&A costs.
GTN's EBITDA for the three months ended September 30, 2009 decreased $6 million from the same period in 2008 primarily due to the sale of North Baja to PipeLines LP on July 1, 2009. GTN's EBITDA for the nine months ended September 30, 2009 increased $6 million from the same period in 2008 primarily due to the positive impact of a stronger U.S. dollar, partially offset by the sale of North Baja in 2009.
EBITDA for the remainder of the U.S. Pipelines was $127 million and $429 million for the three and nine months ended September 30, 2009, respectively, compared to $106 million and $351 million for the same periods in 2008. The increases were primarily due to the positive impact of a stronger U.S. dollar in 2009, increased revenues for Gas Pacifico resulting from a new transportation agreement, TransCanada's increased ownership in PipeLines LP and PipeLines LP's acquisition of North Baja, partially offset by charges incurred in restructuring the U.S. pipeline operations. The increase for the nine month period also included higher short-term revenues for Iroquois.
Operating Statistics
Nine months
ended
September Canadian Alberta GTN
30 Mainline(1) System(2) Foothills ANR(3) System(3)
(unaudited) 2009 2008 2009 2008 2009 2008 2009 2008 2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Average
investment
base ($
millions) 6,549 7,065 4,724 4,322 711 755 n/a n/a n/a n/a
Delivery
volumes
(Bcf)
Total 1,561 1,635 2,652 2,833 901 955 1,199 1,219 578 595
Average
per day 5.7 6.0 9.7 10.3 3.3 3.5 4.4 4.5 2.1 2.2
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Canadian Mainline 2009 and 2008 delivery volumes reflect physical
deliveries to domestic and export markets. Delivery volumes reported
prior to third quarter 2009 reflected contract deliveries, however,
customer contracting patterns have changed in recent years making
physical deliveries a better measure of system utilization. Canadian
Mainline's physical receipts originating at the Alberta border and in
Saskatchewan for the nine months ended September 30, 2009 were 1,234
billion cubic feet (Bcf) (2008 - 1,460 Bcf); average per day was 4.5 Bcf
(2008 - 5.3 Bcf).
(2) Field receipt volumes for the Alberta System for the nine months ended
September 30, 2009 were 2,734 Bcf (2008 - 2,908 Bcf); average per day
was 10.0 Bcf (2008 - 10.6 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 September 30, 2009, Other Assets included $212 million of capitalized costs related to the Keystone pipeline system expansion to the Gulf Coast.
As at September 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 $204 million in third quarter 2009 compared to $302 million in third quarter 2008. Comparable EBIT excluded net unrealized gains of $14 million and net unrealized losses of $2 million in third 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 $622 million for the first nine months of 2009 compared to $735 million in the same nine months of 2008. Comparable EBIT excluded net unrealized losses of $6 million and $7 million in the first nine months of 2009 and 2008, respectively, resulting from changes in the fair value of proprietary natural gas inventory and natural gas forward purchase and sale contracts. Comparable EBIT in 2008 also excluded the $41 million writedown of costs previously capitalized for the Broadwater LNG project.
Energy Results
Three months ended Nine months ended
(unaudited) September 30 September 30
(millions of dollars) 2009 2008 2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Canadian Power
Western Power 66 145 218 382
Eastern Power 52 35 164 104
Bruce Power 81 102 282 205
General, administrative and
support costs (9) (12) (28) (28)
----------------------------------------
Canadian Power Comparable
EBITDA(1) 190 270 636 663
----------------------------------------
U.S. Power(2)
Northeast Power 80 85 198 209
General, administrative and
support costs (12) (9) (35) (28)
----------------------------------------
U.S. Power Comparable EBITDA(1) 68 76 163 181
----------------------------------------
Natural Gas Storage
Alberta Storage 47 35 122 114
General, administrative and
support costs (2) (4) (7) (10)
----------------------------------------
Natural Gas Storage Comparable
EBITDA(1) 45 31 115 104
----------------------------------------
Business Development Comparable
EBITDA(1) (11) (11) (31) (35)
----------------------------------------
Energy Comparable EBITDA(1) 292 366 883 913
Depreciation and amortization (88) (64) (261) (178)
----------------------------------------
Energy Comparable EBIT(1) 204 302 622 735
Specific items:
Fair value adjustments of
natural gas inventory and
forward contracts 14 (2) (6) (7)
Writedown of Broadwater LNG
project costs - - - (41)
----------------------------------------
Energy EBIT(1) 218 300 616 687
----------------------------------------
----------------------------------------
(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 Nine months ended
(unaudited) September 30 September 30
(millions of dollars) 2009 2008 2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenues
Western power 196 264 585 842
Eastern power 69 48 209 148
Other(3) 32 56 122 108
----------------------------------------
297 368 916 1,098
----------------------------------------
Commodity Purchases Resold
Western power (120) (114) (327) (380)
Eastern power - - - (2)
Other(4) (17) (13) (80) (47)
----------------------------------------
(137) (127) (407) (429)
----------------------------------------
Plant operating costs and
other (42) (60) (129) (183)
General, administrative and
support costs (9) (12) (28) (28)
Other (expense)/income - (1) 2 -
----------------------------------------
Comparable EBITDA(2) 109 168 354 458
----------------------------------------
----------------------------------------
(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 MD&A for further
discussion of comparable EBITDA.
(3) Other revenue includes sales of natural gas, sulphur 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 Nine months ended
September 30 September 30
(unaudited) 2009 2008 2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Sales Volumes (GWh)
Supply
Generation
Western Power 541 598 1,718 1,733
Eastern Power 305 225 1,081 737
Purchased
Sundance A & B and
Sheerness PPAs 2,560 2,949 7,725 9,143
Other purchases 113 252 420 789
----------------------------------------
3,519 4,024 10,944 12,402
----------------------------------------
----------------------------------------
Sales
Contracted
Western Power 2,514 2,686 7,164 8,579
Eastern Power 307 297 1,117 899
Spot
Western Power 698 1,041 2,663 2,924
----------------------------------------
3,519 4,024 10,944 12,402
----------------------------------------
----------------------------------------
Plant Availability
Western Power(2) 90% 92% 92% 87%
Eastern Power 97% 98% 97% 97%
----------------------------------------
----------------------------------------
(1) Includes Portlands Energy and the Carleton wind farm effective April
2009 and November 2008, respectively.
(2) Excludes facilities that provide power to TransCanada under PPAs.
Western Power's EBITDA of $66 million in third quarter 2009 decreased $79 million compared to $145 million in third quarter 2008. This decrease was primarily due to lower earnings from the Alberta power portfolio resulting from lower overall realized power prices on lower volumes of power sold. In addition, Western Power's EBITDA in third quarter 2008 included $17 million relating to sulphur sales.
Western Power's EBITDA of $218 million in the nine months ended September 30, 2009 decreased $164 million compared to $382 million for 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). Western Power's EBITDA for the nine months ended September 30, 2008 also included $17 million relating to sulphur sales.
Lower overall realized power prices as well as lower sales volumes resulted in decreases of $68 million and $257 million in Western Power's power revenues for the three and nine months ended September 30, 2009, respectively, compared to the same periods in 2008. Lower sales volumes were the result of reduced dispatch of the Alberta PPAs during periods of reduced demand.
Eastern Power's EBITDA of $52 million and $164 million for the three and nine months ended September 30, 2009, respectively, increased $17 million and $60 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 the Becancour facility.
Eastern Power's power revenues increased $21 million and $61 million for the three and nine months ended September 30, 2009, respectively, primarily due to incremental revenues from Portlands Energy and the Carleton wind farm.
For the nine months ended September 30, 2009, Other Revenues and Other Commodity Purchases Resold of $122 million and $80 million, respectively, increased compared to the same period in 2008 as a result of an increase in the quantity of natural gas being resold in Eastern Power in first quarter 2009.
Plant Operating Costs and Other, which includes fuel gas consumed in generation, of $42 million and $129 million for the three and nine months ended September 30, 2009, respectively, decreased from the same periods in 2008 primarily due to lower prices for natural gas 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 78 per cent of Western Power sales volumes were sold under contract in third quarter 2009, compared to 72 per cent in third quarter 2008. To reduce its exposure to spot market prices on uncontracted volumes, as at September 30, 2009, Western Power had entered into fixed-price power sales contracts to sell approximately 3,200 gigawatt hours (GWh) for the remainder of 2009 and 9,200 GWh for 2010.
Eastern Power is focused on selling power under long-term contracts. As a result, in third 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 Nine months ended
(millions of dollars unless September 30 September 30
otherwise indicated) 2009 2008 2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenues(1)(2) 224 227 685 603
Operating Expenses(2) (143) (125) (403) (398)
----------------------------------------
Comparable EBITDA(3) 81 102 282 205
----------------------------------------
----------------------------------------
Bruce A Comparable EBITDA(3) (11) 22 77 79
Bruce B Comparable EBITDA(3) 92 80 205 126
----------------------------------------
Comparable EBITDA(3) 81 102 282 205
----------------------------------------
----------------------------------------
Bruce Power - Other Information
Plant availability
Bruce A 71% 85% 89% 88%
Bruce B 97% 94% 90% 82%
Combined Bruce Power 89% 92% 90% 85%
Planned outage days
Bruce A 46 12 46 45
Bruce B - - 45 100
Unplanned outage days
Bruce A 3 8 8 10
Bruce B 3 12 44 60
Sales volumes (GWh)
Bruce A 1,099 1,356 4,157 4,182
Bruce B 1,950 2,153 5,751 5,581
----------------------------------------
3,049 3,509 9,908 9,763
----------------------------------------
Results per MWh
Bruce A power revenues $64 $63 $64 $62
Bruce B power revenues $66 $59 $64 $57
Combined Bruce Power revenues $66 $60 $64 $59
Percentage of Bruce B output sold
to spot market 49% 33% 42% 37%
----------------------------------------
----------------------------------------
(1) Revenues include Bruce A's fuel cost recoveries of $7 million and $28
million for the three and nine months ended September 30, 2009,
respectively (2008 - $5 million and $32 million, respectively).
Revenues also include gains of $2 and $4 million as a result of changes
in fair value of held-for-trading derivatives for the three and nine
months ended September 30, 2009, respectively (2008 - gain of $5 million
and loss of $1 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 MD&A for further
discussion of comparable EBITDA.
TransCanada's proportionate share of Bruce Power's comparable EBITDA decreased $21 million to $81 million in third quarter 2009 compared to third quarter 2008 primarily due to higher operating costs as well as lower output as a result of increased outage days.
TransCanada's proportionate share of Bruce A's comparable EBITDA decreased $33 million to a loss of $11 million in third quarter 2009 compared to earnings of $22 million in third quarter 2008 as a result of decreased volumes and higher operating costs due to an increase in outage days following the rescheduling of two planned outages from March 2009 to September 2009. Bruce A's availability in third quarter 2009 was 71 per cent as a result of 49 outage days compared to an availability of 85 per cent and 20 outage days in the same period in 2008.
TransCanada's proportionate share of Bruce B's comparable EBITDA increased $12 million to $92 million in third quarter 2009 compared to third 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).
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 nine months of 2009 are expected to be repaid.
TransCanada's proportionate share of Bruce Power's Comparable EBITDA increased $77 million to $282 million in the nine months ended September 30, 2009 compared to the same period in 2008 due to higher realized prices resulting from the recognition of payments received pursuant to the floor price mechanism as well as higher output, deemed generation payments in third quarter 2009 and lower operating costs per MWh due to fewer outage days.
TransCanada's share of Bruce Power's generation in third quarter 2009 decreased to 3,049 GWh compared to 3,509 GWh in third quarter 2008, however, Bruce Power received deemed generation payments at OPA contract prices during periods of surplus baseload generation when the output of the units was reduced due to system curtailments required by the Independent Electricity System Operator. Including deemed generation, the Bruce Power units' combined average availability was 89 per cent in third quarter 2009, compared to 92 per cent in third quarter 2008. 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 third 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 third quarter 2008. All output from the Bruce B Units 5 to 8 were subject to a floor price of $48.76 per MWh in third quarter 2009 and $47.66 per MWh in third quarter 2008. Both the Bruce A and Bruce B contract prices are adjusted annually for inflation on April 1.
At September 30, 2009, Bruce B had sold forward approximately 1,000 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 $66 per MWh and $64 per MWh in the three and nine months ended September 30, 2009, respectively, reflects revenues recognized from both the floor price mechanism and contract sales, compared to $59 per MWh and $57 per MWh in the same periods in 2008 in which no revenues were recognized under the floor price mechanism.
As at September 30, 2009, Bruce A had incurred approximately $3.1 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 Nine months ended
(unaudited) September 30 September 30
(millions of dollars) 2009 2008 2009 2008
----------------------------------------------------------------------------
Revenues
Power 374 263 1,035 704
Other(3)(4) 114 81 364 258
----------------------------------------
488 344 1,399 962
----------------------------------------
Commodity Purchases Resold
Power (147) (121) (419) (360)
Other(5) (84) (77) (271) (239)
----------------------------------------
(231) (198) (690) (599)
----------------------------------------
Plant operating costs and
other(4) (177) (61) (511) (154)
General, administrative and
support costs (12) (9) (35) (28)
----------------------------------------
Comparable EBITDA(2) 68 76 163 181
----------------------------------------
----------------------------------------
(1) Includes Ravenswood effective August 26, 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 Nine months ended
September 30 September 30
(unaudited) 2009 2008 2009 2008
----------------------------------------------------------------------------
Sales Volumes (GWh)
Supply
Generation 2,021 1,217 4,593 2,847
Purchased 1,259 1,566 3,653 4,383
----------------------------------------
3,280 2,783 8,246 7,230
----------------------------------------
----------------------------------------
Sales
Contracted 2,800 2,751 7,265 7,032
Spot 480 32 981 198
----------------------------------------
3,280 2,783 8,246 7,230
----------------------------------------
----------------------------------------
Plant Availability(2) 97% 98% 78% 96%
----------------------------------------
----------------------------------------
(1) Includes Ravenswood effective August 26, 2008.
(2) Plant availability decreased in the nine months ended September 30, 2009
due to the impact of a forced outage affecting Unit 30 at Ravenswood,
which returned to service May 17, 2009.
U.S. Power's EBITDA for the three and nine months ended September 30, 2009 of $68 million and $163 million, respectively, decreased $8 million and $18 million, respectively, compared to the same periods in 2008. These decreases were due to reduced power prices and lower volumes of power sold to commercial and industrial customers in New England as a result of unseasonably cool summer weather, which resulted in a decrease in demand, partially offset by incremental revenue realized on contract sales in New England. While average spot market power prices in New England decreased in 2009 compared to 2008, the majority of U.S. Power's sales in New England are sold at contracted prices. These decreases were also partially offset by incremental EBITDA from the Ravenswood facility which was acquired in August 2008 and the impact of a stronger U.S. dollar in the first nine months of 2009.
U.S. Power's power revenues for the three and nine months ended September 30, 2009 of $374 million and $1,035 million, respectively, increased from $263 million and $704 million for the same periods in 2008 due to incremental revenues from the Ravenswood facility, an increase in financial contract sales and the impact of a stronger U.S. dollar, partially offset by lower volumes of power sold in New England.
Other Revenues of $114 million and $364 million for the three and nine months ended September 30, 2009, respectively, increased $33 million and $106 million, respectively, compared to the same periods in 2008 due to incremental revenues earned from a steam generating facility at Ravenswood, as well as an increase in the volume of natural gas sold and the impact of a stronger U.S. dollar in 2009.
Power Commodity Purchases Resold of $147 million and $419 million for the three and nine months ended September 30, 2009, respectively, increased from $121 million and $360 million in the same periods in 2008 primarily due to the incremental impact of financial contract purchases in New England and the impact of a stronger U.S. dollar in 2009. These increases were partially offset by lower volumes of power purchased for resale to commercial and industrial customers in New England.
Other Commodity Purchases Resold for the three and nine months ended September 30, 2009 of $84 million and $271 million, respectively, increased from $77 million and $239 million for the same periods in 2008 primarily due to higher volumes of natural gas purchased and resold as well as the impact of a stronger U.S. dollar, partially offset by a decrease in natural gas prices.
Plant Operating Costs and Other, which includes fuel gas consumed in generation, of $177 million and $511 million for the three and nine months ended September 30, 2009, respectively, increased $116 million and $357 million, respectively, from the same periods in 2008 due to incremental costs from the Ravenswood facility.
In the three and nine months ended September 30, 2009, 15 per cent and 12 per cent, respectively, of power sales volumes were sold into the spot market, compared to one and three 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 September 30, 2009, U.S. Power had entered into fixed-price power sales contracts to sell approximately 2,500 GWh for the remainder of 2009 and 7,600 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 nine months ended September 30, 2009 was $45 million and $115 million, respectively, compared to $31 million and $104 million for the same periods in 2008. The $14 million and $11 million increases in EBITDA in third quarter 2009 and nine months ended September 30, 2009 were primarily due to increased third party storage revenues.
Comparable EBITDA excluded net unrealized gains of $14 million and net unrealized losses of $6 million in the three and nine months ended September 30, 2009, respectively (2008 - losses of $2 million and $7 million, respectively), 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. The fair value of proprietary natural gas inventory held in storage has been measured using a weighted average of forward prices for the following four months less selling costs.
Depreciation and Amortization
Depreciation and Amortization for the three and nine months ended September 30, 2009 of $88 million and $261 million, respectively, increased $24 million and $83 million, respectively, compared to the same periods in 2008, primarily due to the acquisition of Ravenswood in August 2008.
Corporate
Corporate EBIT losses for the three and nine months ended September 30, 2009 were $28 million and $89 million, respectively, compared to losses of $23 million and $71 million for the same periods in 2008. These increases in EBIT losses were primarily due to higher support services costs in 2009, reflecting a growing asset base.
Other Income Statement Items
Interest Expense
Three months ended Nine months ended
(unaudited) September 30 September 30
(million of dollars) 2009 2008 2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Interest on long-term debt(1) 317 256 981 739
Other interest and amortization 12 (5) 19 (25)
Capitalized interest (113) (38) (230) (97)
----------------------------------------
216 213 770 617
----------------------------------------
----------------------------------------
(1) Includes interest for Junior Subordinated Notes.
Interest Expense for third quarter 2009 increased $3 million to $216 million from $213 million in third quarter 2008. Interest Expense for the nine months ended September 30, 2009, increased $153 million to $770 million from $617 million for the nine months ended September 30, 2008. These increases reflected 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, as well as higher losses from changes in the fair value of derivatives used to manage the Company's exposure to interest rate fluctuations. 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 primarily due to the construction of Keystone and the acquisition of the remaining 20 per cent ownership interest in Keystone from ConocoPhillips.
Interest Income and Other was $43 million and $99 million for the three and nine month periods ended September 30, 2009, respectively, compared to $22 million and $58 million for the same periods in 2008. The increase of $21 million and $41 million for the three and nine months ended September 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. An increase in interest income due to higher cash balances held in 2009 was more than offset by lower interest rates.
Income Taxes were $107 million in third quarter 2009 compared to $129 million for the same period in 2008. Income Taxes for the nine months ended September 30, 2009 were $320 million compared to $507 million for the same period in 2008. The decreases were primarily due to reduced earnings and higher income tax rate differentials and other positive income tax adjustments in 2009.
Non-Controlling Interests were $23 million for third quarter 2009 compared to $18 million for the same period in 2008. The increase of $5 million was primarily due to higher earnings in PipeLines LP, partially offset by lower earnings in Portland. Non-Controlling Interests of $71 million for the first nine months of 2009, decreased $35 million compared to $106 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, partially offset by higher PipeLines LP earnings in 2009.
Liquidity and Capital Resources
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, and 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, common and preferred share 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 $150 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 to eligible participants.
At September 30, 2009, the Company held cash and cash equivalents of $2.4 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 in 2009 of preferred shares in third quarter, common shares in second quarter and long-term debt in first quarter.
Operating Activities
Funds Generated from Operations(1)
Three months ended Nine months ended
(unaudited) September 30 September 30
(millions of dollars) 2009 2008 2009 2008
----------------------------------------------------------------------------
Cash Flows
Funds generated from operations(1) 772 711 2,230 2,309
(Increase)/decrease in operating
working capital (31) 114 362 16
----------------------------------------
Net cash provided by operations 741 825 2,592 2,325
----------------------------------------
----------------------------------------
(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 decreased $84 million and increased $267 million for the three and nine months ended September 30, 2009, respectively, compared to the same periods in 2008, primarily due to changes in operating working capital. Funds Generated from Operations (FGFO) for the three and nine months ended September 30, 2009, were $772 million and $2.2 billion, respectively, compared to $711 million and $2.3 billion for the same periods in 2008. FGFO for the three months ended September 30, 2009 increased primarily due to increased cash from earnings, partially offset by increased pension contributions in 2009. FGFO for the nine months ended September 30, 2009 decreased primarily due to $152 million of after tax proceeds received in 2008 from the Calpine bankruptcy settlements and increased pension contributions in 2009, partially offset by increased cash from earnings.
Investing Activities
Acquisitions, net of cash acquired, were $653 million in third quarter 2009 (2008 - $3.1 billion) and $902 million (2008 - $3.1 billion) for the nine months ended September 30, 2009. In August 2009, the Company acquired ConocoPhillips' remaining 20 per cent interest in Keystone. Acquisitions for the nine months ended September 30, 2009 also included the previous increases in ownership interest in Keystone pursuant to an agreement with ConocoPhillips that became effective December 2008.
TransCanada remains committed to executing its previously announced $22 billion capital expenditure program over the next four years. For the three and nine months ended September 30, 2009, capital expenditures totalled $1.6 billion and $3.9 billion, respectively (2008 - $0.8 billion and $1.9 billion, respectively), primarily related to construction of 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 September 30, 2009, TransCanada completed a public offering of 22 million cumulative redeemable first preferred shares under the September 21, 2009 prospectus, discussed below, for gross proceeds of $550 million. The holders of the preferred shares are entitled to receive fixed cumulative dividends at an annual rate of $1.15 per share, payable quarterly, yielding 4.6 per cent per annum, for the initial five-year period ending December 31, 2014, with the first dividend payment date scheduled for December 31, 2009. The dividend rate will reset on December 31, 2014 and every five years thereafter to a yield per annum equal to the then sum of the five-year Government of Canada bond yield and 1.92 per cent. The preferred shares are redeemable by TransCanada on or after December 31, 2014 at a price of $25 per share plus all accrued and unpaid dividends. The net proceeds of this offering are expected to be used to partially fund capital projects, for general corporate purposes and to repay short term indebtedness of TransCanada and its affiliates.
The preferred shareholders will have the right to convert their shares into Series 2 cumulative redeemable first preferred shares on December 31, 2014 and on December 31 of every fifth year thereafter. The holders of Series 2 preferred shares will be entitled to receive quarterly floating rate cumulative dividends at a yield per annum equal to the sum of the then 90-day Government of Canada treasury bill rate and 1.92 per cent.
On September 21, 2009, TransCanada filed a short form base shelf prospectus qualifying for issuance $3.0 billion of common shares, first or second preferred shares and/or subscription receipts in Canada and the U.S. until October 2011. This base shelf prospectus replaced the base shelf prospectus filed in July 2008, which was exhausted by the common share issue discussed below.
In June 2009, TransCanada completed a public offering of 58.4 million common shares, including full exercise of an underwriters' over-allotment option. Net proceeds from the common share offering and the over-allotment option totalled $1.8 billion and are expected to 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.
The Company is well positioned to fund its existing capital program through its growing internally-generated cash flow, its DRP and its continued access to capital markets. As demonstrated by the recent sale of North Baja to PipeLines LP, TransCanada will also continue to examine opportunities for portfolio management, including a greater role for PipeLines LP, in the financing of its capital program.
In the three and nine months ended September 30, 2009, TransCanada issued $207 million and $3.3 billion, respectively (2008 - $2.1 billion and $2.2 billion, respectively), and retired $9 million and $509 million, respectively (2008 - $15 million and $788 million, respectively), of long-term debt. TransCanada's notes payable increased $77 million and decreased $607 million in the three and nine months ended September 30, 2009, respectively, compared to a decrease of $258 million and an increase of $466 million for the same periods in 2008.
In April 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 has remaining capacity of US$1.0 billion.
On October 20, 2009, the Company retired $250 million of 10.625 per cent debentures.
Dividends
On November 3, 2009, TransCanada's Board of Directors declared a quarterly dividend of $0.38 per share for the quarter ending December 31, 2009 on the Company's outstanding common shares. It is payable on January 29, 2010 to shareholders of record at the close of business on December 31, 2009.
TransCanada's Board of Directors approved the issuance of common shares from treasury at a three per cent discount under TransCanada's DRP for the dividends payable on January 29, 2010. 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 nine months ended September 30, 2009, TransCanada issued 2.5 million and 6.0 million common shares, respectively, under its DRP, in lieu of making cash dividend payments of $73 million and $182 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 Regulatory 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 Regulatory Assets. 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 CICA 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 Steering Committee. 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 will 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 August 14, 2009, the Company acquired ConocoPhillips' remaining interest in Keystone. As a result, TransCanada assumed 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 September 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 September 30, 2009, there were no significant amounts past due or impaired.
As a level of uncertainty in the global financial markets remains, 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 September 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 $73 million (December 31, 2008 - $76 million).
The change in fair value of proprietary natural gas inventory in storage in the three and nine months ended September 30, 2009 resulted in a net pre-tax unrealized gain of $16 million and a net pre-tax unrealized loss of $13 million, respectively (2008 - unrealized losses of $108 million and $6 million, respectively), which were recorded to Revenues and Inventories. The net change in fair value of natural gas forward purchase and sales contracts in the three and nine months ended September 30, 2009 resulted in a net pre-tax unrealized loss of $2 million and a net pre-tax unrealized gain of $7 million, respectively (2008 - unrealized gain of $106 million and unrealized loss of $1 million), 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 September 30, 2009, the Company had designated as a net investment hedge U.S. dollar-denominated debt with a carrying value of $8.1 billion (US$7.6 billion) and a fair value of $9.2 billion (US$8.6 billion). At September 30, 2009, Other Assets included $51 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
September 30, 2009 December 31, 2008
--------------------------------------------
Notional Notional
Asset/(Liability) or or
(unaudited) Fair Principal Fair Principal
(millions of dollars) Value(1) Amount Value(1) Amount
----------------------------------------------------------------------------
U.S. dollar cross-currency swaps
(maturing 2009 to 2014)(2) 40 U.S. 1,650 (218) U.S. 1,650
U.S. dollar forward foreign
exchange contracts (maturing
2009 to 2010)(2) 7 U.S. 635 (42) U.S. 2,152
U.S. dollar options (maturing
2009)(2) 4 U.S. 400 6 U.S. 300
--------------------------------------------
51 U.S. 2,685 (254) U.S. 4,102
--------------------------------------------
--------------------------------------------
(1) Fair values equal carrying values.
(2) As at September 30, 2009.
Non-Derivative Financial Instruments Summary
The carrying and fair values of non-derivative financial instruments were as
follows:
September 30, 2009 December 31, 2008
----------------------------------------
(unaudited) Carrying Fair Carrying Fair
(millions of dollars) Amount Value Amount Value
----------------------------------------------------------------------------
Financial Assets(1)
Cash and cash equivalents 2,406 2,406 1,308 1,308
Accounts receivable and other
assets(2)(3) 983 983 1,404 1,404
Available-for-sale assets(2) 23 23 27 27
----------------------------------------
3,412 3,412 2,739 2,739
----------------------------------------
----------------------------------------
Financial Liabilities(1)(3)
Notes payable 1,324 1,324 1,702 1,702
Accounts payable and deferred
amounts(4) 1,606 1,606 1,372 1,372
Accrued interest 342 342 359 359
Long-term debt and junior
subordinated notes 18,469 21,388 17,367 16,152
Long-term debt of joint ventures 1,090 1,149 1,076 1,052
----------------------------------------
22,831 25,809 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 September 30, 2009, the Consolidated Balance Sheet included financial
assets of $834 million (December 31, 2008 - $1,257 million) in Accounts
Receivable and $172 million (December 31, 2008 - $174 million) in Other
Assets.
(3) Recorded at amortized cost.
(4) At September 30, 2009, the Consolidated Balance Sheet included financial
liabilities of $1,604 million (December 31, 2008 - $1,350 million) in
Accounts Payable and $2 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:
September 30, 2009
(unaudited)
(all amounts in millions Natural Oil Foreign
unless otherwise indicated) Power Gas Products Exchange Interest
----------------------------------------------------------------------------
Derivative Financial
Instruments Held for
Trading(1)
Fair Values(2)
Assets $ 126 $ 129 $ 4 $ 4 $ 35
Liabilities $ (71) $ (134) $ (3) $ (64) $ (81)
Notional Values
Volumes(3)
Purchases 9,876 204 180 - -
Sales 9,718 171 228 - -
Canadian dollars - - - - 699
U.S. dollars - - - U.S. 426 U.S. 1,425
Cross-currency - - - 227/U.S. -
157
Net unrealized
(losses)/gains in the
period(4)
Three months ended
September 30, 2009 $ (8) $ 21 $ (1) $ 2 $ (7)
Nine months ended
September 30, 2009 $ 11 $ (4) $ 1 $ 4 $ 20
Net realized gains/(losses)
in the period(4)
Three months ended
September 30, 2009 $ 23 $ (43) $ 1 $ 11 $ (5)
Nine months ended
September 30, 2009 $ 53 $ (56) - $ 28 $ (14)
Maturity dates 2009- 2009- 2009- 2009- 2009-
2014 2014 2010 2012 2018
Derivative Financial
Instruments in Hedging
Relationships(5)(6)
Fair Values(2)
Assets $ 229 $ 2 - - $ 6
Liabilities $ (154) $ (15) - $ (36) $ (67)
Notional Values
Volumes(3)
Purchases 13,597 24 - - -
Sales 14,806 - - - -
U.S. dollars - - - - 1,825
Cross-currency - - - 136/U.S. -
100
Net realized gains/(losses)
in the period(4)
Three months ended
September 30, 2009 $ 30 $ (8) - - $ (10)
Nine months ended
September 30, 2009 $ 108 $ (28) - - $ (27)
Maturity dates 2009- 2009- n/a 2009- 2010-
2015 2012 2013 2020
--------------------------------------------------
(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 $6 million and a notional amount of US$150
million. Net realized gains on fair value hedges for the three and nine
months ended September 30, 2009 were $1 million and $3 million,
respectively, and were included in Interest Expense. In third 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 nine months ended September 30, 2009
included gains of $1 million and $2 million, respectively, for the
changes in fair value of power and natural gas cash flow hedges that
were ineffective in offsetting the change in fair value of their related
underlying positions. There were no gains or losses included in Net
Income for the three and nine months ended September 30, 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
gains/(losses) in the
period(3)
Three months ended
September 30, 2008 $ 5 $ (1) - - $ 5
Nine months ended
September 30, 2008 - $ (12) - $ (7) $ 3
Net realized gains/(losses)
in the period(3)
Three months ended
September 30, 2008 $ 12 $ (11) - $ 2 $ 2
Nine months ended
September 30, 2008 $ 21 $ (6) - $ 12 $ 12
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 gains/(losses)
in the period(3)
Three months ended
September 30, 2008 $ 14 $ (1) - - $ (2)
Nine months ended
September 30, 2008 $ (24) $ 18 - - $ (4)
Maturity dates(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. Net realized gains on
fair value hedges for the three and nine months ended September 30, 2008
were $1 million and $1 million, respectively, and were included in
Interest Expense. In third 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 nine months ended September 30, 2008
included gains of $7 million and $4 million, respectively, for the
changes in fair value of power and natural gas cash flow hedges that
were ineffective in offsetting the change in fair value of their related
underlying positions. There were no gains or losses included in Net
Income for the three and nine months ended September 30, 2008 for
discontinued cash flow hedges. 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 September 30, December 31,
dollars) 2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Current
Other current assets 370 318
Accounts payable (359) (298)
Long-term
Other assets 216 191
Deferred amounts (266) (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 September 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 September 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
TransCanada does not expect the slowdown in the North American economy 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 $550 million of preferred shares in third quarter 2009, $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 $2.6 billion of cash provided by operations in the first nine months of 2009, they have contributed to a cash balance of $2.4 billion at September 30, 2009 and provided 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 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.
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 (S&P). On September 30, 2009, DBRS and S&P assigned ratings of Pfd-2 (low) and P-2, respectively, to TransCanada's cumulative redeemable first preferred shares, Series 1 and in connection with the offering, S&P assigned TransCanada an A- long-term corporate credit rating with a stable outlook.
Recent Developments
Pipelines
Keystone
On August 14, 2009, TransCanada purchased ConocoPhillips' remaining 20 per cent ownership interest in Keystone for US$553 million plus the assumption of US$197 million of short-term indebtedness. Following this acquisition TransCanada owns 100 per cent of Keystone and began consolidating Keystone into the Pipelines segment.
The first phase of Keystone is currently under construction, extending from Hardisty, Alberta to serve markets in Wood River and Patoka, Illinois with an initial nominal capacity of 435,000 barrels per day (bbl/d). Commissioning of this segment commenced in third quarter 2009 with commercial operations to follow in first quarter 2010. At September 30, 2009, the first phase was approximately 90 per cent complete. The second phase of Keystone will expand nominal capacity to 591,000 bbl/d and extend the pipeline to Cushing, Oklahoma. Commissioning of the Cushing segment is expected to commence in late 2010. At September 30, 2009, this phase of the project was approximately 20 per cent complete.
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 system that will provide additional capacity of 500,000 bbl/d from Western Canada to the Gulf Coast in 2012. In September 2009, the NEB held a hearing to review the application for the Canadian portion of the Keystone Gulf Coast expansion with a decision expected in early 2010. Permits for the U.S. portion of the expansion are expected by mid-2010. Construction of the expansion facilities is anticipated to commence in 2010 following the receipt of all the necessary regulatory approvals.
The total capital cost of Keystone is expected to be approximately US$12 billion. Approximately US$5 billion has been spent to date with the remaining US$7 billion to be invested between now and 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 were to 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 could be economically expanded from 1.1 million bbl/d to 1.5 million bbl/d in response to additional market demand.
Alberta System
On October 30, 2009, following discussions with stakeholders to migrate the 2008-2009 Revenue Requirement Settlement to NEB jurisdiction, TransCanada submitted an application to the NEB requesting that 2009 interim rates be made final.
In September 2009, the Company began construction on the final phase of the North Central Corridor expansion, which is expected to be complete in April 2010. The capital cost of this phase of the project is estimated to be approximately $400 million.
Ventures LP
In September 2009, the Alberta Court of Appeal granted Ventures LP leave to appeal the AUC Decision 2009-065 where the AUC announced that it would seek an Order in Council allowing it to establish a process for regulating rates on the Ventures LP pipeline. The appeal is expected to be heard during first quarter 2010.
Review of NEB ROE Formula
In July 2009, the NEB initiated a review of the RH-2-94 Decision by seeking comments on the continuing applicability of that decision. The RH-2-94 Decision pursuant to the National Energy Board Act (Canada) established an ROE formula tied to Government of Canada bond yields that has formed the basis of determining tolls for pipelines under NEB jurisdiction since January 1, 1995. In October 2009, the NEB issued a decision that the RH-2-94 Decision would not continue to be in effect. The NEB stated that instead of a multi-pipeline approach, the cost of capital will be determined by negotiations between pipeline companies and their shippers or by the NEB if a pipeline company files a cost of capital application. This decision impacts all of TransCanada's NEB regulated pipelines, which include the Canadian Mainline, Alberta System and Foothills. The Canadian Mainline is expected to continue to base its return on the result of the RH-2-94 NEB ROE formula for the years 2010 and 2011 in accordance with the terms of the current Canadian Mainline tolls settlement. TransCanada will be working with customers and interested parties to determine the cost of capital to be used in calculating tolls for 2010 on its other NEB regulated pipelines. If agreements cannot be reached, TransCanada will file applications with the NEB requesting an appropriate cost of capital component.
Energy
Bruce Power
Progress continues on the refurbishment and restart of Bruce A Units 1 and 2 with work now advanced to the re-assembly of the reactors. As at September 30, 2009, Bruce A had incurred approximately $3.1 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. TransCanada believes that the work on Units 1 and 2 is now approximately 75 per cent complete, with the bulk of the highly technical, high risk work now finished. Although a significant amount of work remains to be done, most of this work is conventional power plant construction activity.
The project has experienced delays and TransCanada now expects that Unit 2 will be restarted mid-2011, with Unit 1 expected to follow approximately four months thereafter. The impact of this delay is mitigated by the previously announced extension of the operating lives of Unit 3 to 2011 and Unit 4 to 2016, with further life extensions expected as additional reactor optimization activities proceed. TransCanada continues to work closely with Bruce Power to address productivity and overall project management and notes that there have been recent, significant successes in this area.
Oakville
On September 30, 2009, the OPA awarded TransCanada a 20-year Clean Energy Supply contract to build, own and operate the 900 MW Oakville generating station in Oakville, Ontario. TransCanada expects to invest approximately $1.2 billion in the natural gas-fired, combined-cycle plant which is scheduled to start producing power by the end of 2013. TransCanada expects this project will deliver an after-tax unlevered rate of return of nine per cent.
Kibby Wind
In September 2009, the first phase of the Kibby Wind power project, capable of producing 66 MW of power, entered the commissioning phase. The 22 turbines included in this first phase were placed in service on October 30, 2009 on time and on budget. Construction continues on the 66 MW second phase of the project, which includes the installation of an additional 22 turbines. This phase is expected to be in service in third quarter 2010.
Coolidge
In August, 2009, TransCanada began construction of the US$500 million Coolidge generating station located near Phoenix, Arizona. The 575 MW, simple-cycle, natural gas-fired peaking power facility is expected to be in service in second quarter 2011 on time and on budget. All of the power produced by the facility will be sold to the Phoenix, Arizona based utility Salt River Project under a 20-year PPA.
Cartier Wind
In third quarter 2009, construction activity began on the 212 MW Gros-Morne and 58.5 MW Montagne-Seche wind farms. The Montagne-Seche project and phase one of the Gros-Morne project (101 MW) are expected to be operational in 2011. Phase two of the Gros-Morne project (111 MW) is expected to be operational in 2012. These are the fourth and fifth Quebec-based wind farms either operating or under development by Cartier Wind, which is 62 per cent owned by TransCanada. These two wind farms are expected to have a capital cost of approximately $340 million. Once these two phases are complete, Cartier Wind will be capable of producing 590 MW of electricity. All of the power produced by Cartier Wind is sold to Hydro-Quebec Distribution under a 20-year PPA.
Power Transmission Line Projects
On October 13, 2009, TransCanada commenced open seasons on its proposed Zephyr and Chinook power transmission line projects. The open seasons are scheduled to end in fourth quarter 2009. Pending successful completion of the open seasons, regulatory work could commence in fourth quarter 2009, with construction commencing in 2012 and a potential in-service date of late 2014. Each project would cost approximately US$3 billion and be capable of delivering 3,000 MW of power originating in Wyoming and Montana, respectively, to Nevada.
Share Information
As at November 3, 2009, TransCanada had 684 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 November 3, 2009.
Selected Quarterly Consolidated Financial Data(1)
-------------------------------------------------
-------------------------------------------------
(unaudited) 2009 2008 2007
(millions of ------------------------------------------------------------
dollars except ------------------------------------------------------------
per share
amounts) Third Second First Fourth Third Second First Fourth
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenues 2,253 2,127 2,380 2,332 2,137 2,017 2,133 2,189
Net Income 345 314 334 277 390 324 449 377
Share Statistics
Net income per
common share $ 0.50 $ 0.50 $ 0.54 $ 0.47 $ 0.67 $ 0.58 $0.83 $ 0.70
- Basic
Net income per
common share $ 0.50 $ 0.50 $ 0.54 $ 0.46 $ 0.67 $ 0.58 $0.83 $ 0.70
- Diluted
Dividend
declared per
common share $ 0.38 $ 0.38 $ 0.38 $ 0.36 $ 0.36 $ 0.36 $0.36 $ 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, capacity payments, 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:
- Third quarter 2009, Energy's EBIT included net unrealized gains of $14 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.
- 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 did 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. 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 increased due to a $16 million pre-tax ($14 million after tax) gain on sale of land previously held for development. 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.
Consolidated Income
(unaudited)
(millions of dollars except Three months ended Nine months ended
number of shares and September 30 September 30
per share amounts) 2009 2008 2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenues 2,253 2,137 6,760 6,287
----------------------------------------
Operating and Other
Expenses/(Income)
Plant operating costs and other 879 750 2,544 2,181
Commodity purchases resold 371 324 1,100 1,053
Other income (5) (1) (20) (38)
Calpine bankruptcy settlements - - - (279)
Writedown of Broadwater LNG
project costs - - - 41
----------------------------------------
1,245 1,073 3,624 2,958
----------------------------------------
1,008 1,064 3,136 3,329
Depreciation and amortization 343 318 1,034 943
----------------------------------------
665 746 2,102 2,386
----------------------------------------
Financial Charges/(Income)
Interest expense 216 213 770 617
Financial charges of joint ventures 17 18 47 51
Interest income and other (43) (22) (99) (58)
----------------------------------------
190 209 718 610
----------------------------------------
Income before Income Taxes and
Non-Controlling Interests 475 537 1,384 1,776
----------------------------------------
Income Taxes
Current 14 127 103 479
Future 93 2 217 28
----------------------------------------
107 129 320 507
----------------------------------------
Non-Controlling Interests
Preferred share dividends of
subsidiary 6 6 17 17
Non-controlling interest in
PipeLines LP 19 12 51 46
Non-controlling interest in Portland (2) - 3 43
----------------------------------------
23 18 71 106
----------------------------------------
Net Income 345 390 993 1,163
----------------------------------------
----------------------------------------
Net Income Per Common Share -
Basic and Diluted $ 0.50 $ 0.67 $ 1.55 $ 2.07
----------------------------------------
----------------------------------------
Average Common Shares Outstanding
- Basic (millions) 681 579 641 560
----------------------------------------
----------------------------------------
Average Common Shares Outstanding
- Diluted (millions) 682 581 642 562
----------------------------------------
----------------------------------------
See accompanying notes to the consolidated financial statements.
Consolidated Cash Flows
Three months ended Nine months ended
September 30 September 30
(unaudited)(millions of dollars) 2009 2008 2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Cash Generated From Operations
Net income 345 390 993 1,163
Depreciation and amortization 343 318 1,034 943
Future income taxes 93 2 217 28
Non-controlling interests 23 18 71 106
Employee future benefits funding
(in excess of)/ lower than expense (22) 10 (79) 23
Writedown of Broadwater LNG
project costs - - - 41
Other (10) (27) (6) 5
----------------------------------------
772 711 2,230 2,309
(Increase)/decrease in operating
working capital (31) 114 362 16
----------------------------------------
Net cash provided by operations 741 825 2,592 2,325
----------------------------------------
Investing Activities
Capital expenditures (1,557) (806) (3,943) (1,899)
Acquisitions, net of cash acquired (653) (3,054) (902) (3,058)
Disposition of assets, net of
current income taxes - 21 - 21
Deferred amounts and other (190) 58 (529) 157
----------------------------------------
Net cash used in investing activities (2,400) (3,781) (5,374) (4,779)
----------------------------------------
Financing Activities
Dividends on common shares (186) (143) (535) (410)
Distributions paid to non-controlling
interests (25) (24) (76) (110)
Notes payable issued/(repaid), net 77 (258) (607) 466
Long-term debt issued, net of
issue costs 207 2,085 3,267 2,197
Reduction of long-term debt (9) (15) (509) (788)
Long-term debt of joint ventures
issued 93 123 201 157
Reduction of long-term debt of
joint ventures (52) (44) (108) (101)
Preferred shares issued, net of
issue costs 539 - 539 -
Common shares issued, net of
issue costs 2 6 1,805 1,252
----------------------------------------
Net cash provided by financing
activities 646 1,730 3,977 2,663
----------------------------------------
Effect of Foreign Exchange Rate
Changes on Cash and Cash
Equivalents (63) 19 (97) 39
----------------------------------------
(Decrease)/Increase in Cash and
Cash Equivalents (1,076) (1,207) 1,098 248
Cash and Cash Equivalents
Beginning of period 3,482 1,959 1,308 504
----------------------------------------
Cash and Cash Equivalents
End of period 2,406 752 2,406 752
----------------------------------------
----------------------------------------
Supplementary Cash Flow
Information
Income taxes (refunded)/paid (63) 106 50 418
Interest paid 297 177 834 658
----------------------------------------
----------------------------------------
See accompanying notes to the consolidated financial statements.
Consolidated Balance Sheet
September 30, December 31,
(unaudited)(millions of dollars) 2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
ASSETS
Current Assets
Cash and cash equivalents 2,406 1,308
Accounts receivable 834 1,280
Inventories 491 489
Other 505 523
---------------------------
4,236 3,600
Plant, Property and Equipment 32,289 29,189
Goodwill 3,855 4,397
Regulatory Assets 1,644 201
Other Assets 2,132 2,027
---------------------------
44,156 39,414
---------------------------
---------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Notes payable 1,324 1,702
Accounts payable 2,350 1,876
Accrued interest 342 359
Current portion of long-term debt 678 786
Current portion of long-term debt
of joint ventures 235 207
---------------------------
4,929 4,930
Regulatory Liabilities 430 551
Deferred Amounts 723 1,168
Future Income Taxes 2,784 1,223
Long-Term Debt 16,730 15,368
Long-Term Debt of Joint Ventures 855 869
Junior Subordinated Notes 1,061 1,213
---------------------------
27,512 25,322
---------------------------
Non-Controlling Interests
Non-controlling interest in
PipeLines LP 561 721
Preferred shares of subsidiary 389 389
Non-controlling interest in Portland 77 84
---------------------------
1,027 1,194
---------------------------
Shareholders' Equity 15,617 12,898
---------------------------
44,156 39,414
---------------------------
---------------------------
See accompanying notes to the consolidated financial statements.
Consolidated Comprehensive Income
Three months ended Nine months ended
September 30 September 30
(unaudited)(millions of dollars) 2009 2008 2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net Income 345 390 993 1,163
----------------------------------------
Other Comprehensive (Loss)/Income,
Net of
Income Taxes
Change in foreign currency
translation gains and
losses on investments in foreign
operations(1) (230) 107 (381) 146
Change in gains and losses on
hedges of investments in
foreign operations(2) 113 (79) 209 (103)
Change in gains and losses on
derivative instruments
designated as cash
flow hedges(3) 16 7 80 40
Reclassification to net income
of gains and losses
on derivative instruments
designated as cash flow
hedges pertaining to prior
periods(4) (1) (6) (6) (24)
----------------------------------------
Other Comprehensive (Loss)/Income (102) 29 (98) 59
----------------------------------------
Comprehensive Income 243 419 895 1,222
----------------------------------------
----------------------------------------
(1) Net of income tax expense of $68 million and $68 million for the three
and nine months ended September 30, 2009, respectively
(2008 - recovery of $23 million and $43 million, respectively).
(2) Net of income tax expense of $50 million and $102 million for the three
and nine months ended September 30, 2009, respectively
(2008 - recovery of $36 million and $50 million, respectively).
(3) Net of income tax expense of $4 million and $20 million for the three
and nine months ended September 30, 2009, respectively (2008 - $25
million recovery and $24 million expense, respectively).
(4) Net of income tax expense of $4 million and $4 million for the three
and nine months ended September 30, 2009, respectively
(2008 - recovery of $9 million and $20 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) (381) - (381)
Change in gains and losses on hedges of
investments in foreign operations(2) 209 - 209
Change in gains and losses on derivative
instruments designated as cash flow
hedges(3) - 80 80
Reclassification to net income of gains
and losses on derivative instruments
designated as cash flow hedges pertaining
to prior periods(4)(5) - (6) (6)
---------------------------
Balance at September 30, 2009 (551) (19) (570)
---------------------------
---------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Balance at December 31, 2007 (361) (12) (373)
Change in foreign currency translation
gains and losses on investments in
foreign operations(1) 146 - 146
Change in gains and losses on hedges of
investments in foreign operations(2) (103) - (103)
Change in gains and losses on derivative
instruments designated as cash flow hedges(3) - 40 40
Reclassification to net income of gains
and losses on derivative instruments
designated as cash flow hedges pertaining
to prior periods(4) - (24) (24)
---------------------------
Balance at September 30, 2008 (318) 4 (314)
---------------------------
---------------------------
(1) Net of income tax expense of $68 million for the nine months ended
September 30, 2009 (2008 - $43 million recovery).
(2) Net of income tax expense of $102 million for the nine months ended
September 30, 2009 (2008 - $50 million recovery).
(3) Net of income tax expense of $20 million for the nine months ended
September 30, 2009 (2008 - $24 million expense).
(4) Net of income tax expense of $4 million for the nine months ended
September 30, 2009 (2008 - $20 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 $30 million ($25
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
Nine months ended
September 30
(unaudited)(millions of dollars) 2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Common Shares
Balance at beginning of period 9,264 6,662
Proceeds from shares issued under public
offering, net of issue costs 1,792 1,235
Shares issued under dividend
reinvestment plan 182 177
Proceeds from shares issued on exercise
of stock options 13 17
---------------------------
Balance at end of period 11,251 8,091
Preferred Shares
Balance at beginning of period - -
Proceeds from shares issued under public
offering, net of issue costs 539 -
---------------------------
Balance at end of period 539 -
---------------------------
Contributed Surplus
Balance at beginning of period 279 276
Increased ownership in PipeLines LP (Note 8) 49 -
Issuance of stock options 3 2
---------------------------
Balance at end of period 331 278
---------------------------
Retained Earnings
Balance at beginning of period 3,827 3,220
Net income 993 1,163
Common share dividends (754) (612)
---------------------------
Balance at end of period 4,066 3,771
---------------------------
Accumulated Other Comprehensive Income
Balance at beginning of period (472) (373)
Other comprehensive income (98) 59
---------------------------
Balance at end of period (570) (314)
---------------------------
3,496 3,457
---------------------------
Total Shareholders' Equity 15,617 11,826
---------------------------
---------------------------
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, capacity payments, 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 Regulatory 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 Regulatory Assets. 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 CICA 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 $14 million and $43 million in the three and nine months ended September 30, 2009, respectively (2008 - $14 million and $43 million, respectively), for power purchase arrangements, which was previously included in Commodity Purchases Resold. Support services costs previously allocated to Pipelines and Energy of $25 million and $87 million in the three and nine months ended September 30, 2009, respectively (2008 - $24 million and $75 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 these changes. These changes had no impact on reported consolidated Net Income.
Three months
ended
September 30
(unaudited) Pipelines Energy Corporate Total
(millions --------------------------------------------------------------
of dollars) 2009 2008 2009 2008 2009 2008 2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenues 1,152 1,141 1,101 996 - - 2,253 2,137
Plant
operating
costs and
other (427) (421) (424) (306) (28) (23) (879) (750)
Commodity
purchases
resold - - (371) (324) - - (371) (324)
Other income/
(expense) 5 3 - (2) - - 5 1
---------------------------------------------------------------
730 723 306 364 (28) (23) 1,008 1,064
Depreciation
and
amortization (255) (254) (88) (64) - - (343) (318)
---------------------------------------------------------------
475 469 218 300 (28) (23) 665 746
------------------------------------------------
Interest expense (216) (213)
Financial charges
of joint ventures (17) (18)
Interest income
and other 43 22
Income taxes (107) (129)
Non-controlling
interests (23) (18)
--------------
Net Income 345 390
--------------
--------------
Nine months
ended
September 30
(unaudited) Pipelines Energy Corporate Total
(millions --------------------------------------------------------------
of dollars) 2009 2008 2009 2008 2009 2008 2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenues 3,558 3,417 3,202 2,870 - - 6,760 6,287
Plant
operating
costs and
other (1,227) (1,194) (1,227) (910) (90) (77) (2,544) (2,181)
Commodity
purchases
resold - - (1,100) (1,053) - - (1,100) (1,053)
Other income/
(expense) 17 33 2 (1) 1 6 20 38
Calpine
bankruptcy
settlements - 279 - - - - - 279
Writedown of
Broadwater LNG
project costs - - - (41) - - - (41)
---------------------------------------------------------------
2,348 2,535 877 865 (89) (71) 3,136 3,329
Depreciation
and
amortization (773) (765) (261) (178) - - (1,034) (943)
---------------------------------------------------------------
1,575 1,770 616 687 (89) (71) 2,102 2,386
Interest expense (770) (617)
Financial charges
of joint ventures (47) (51)
Interest income
and other 99 58
Income taxes (320) (507)
Non-controlling
interests (71) (106)
--------------
Net Income 993 1,163
--------------
--------------
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)(millions of September 30, December 31,
dollars) 2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Pipelines 28,895 25,020
Energy 12,078 12,006
Corporate 3,183 2,388
------------------------
44,156 39,414
------------------------
------------------------
4. Long-Term Debt
On October 20, 2009, the Company retired $250 million of 10.625 per cent debentures.
In April 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 has remaining capacity of US$1.0 billion.
In the three and nine months ended September 30, 2009, the Company capitalized interest related to capital projects of $113 million and $230 million, respectively (2008 - $38 million and $97 million, respectively).
5. Share Capital
On September 30, 2009, TransCanada completed a public offering of 22 million cumulative redeemable first preferred shares under the September 21, 2009 prospectus, discussed below, for gross proceeds of $550 million. The holders of the preferred shares are entitled to receive fixed cumulative dividends at an annual rate of $1.15 per share, payable quarterly, yielding 4.6 per cent per annum, for the initial five-year period ending December 31, 2014, with the first dividend payment date scheduled for December 31, 2009. The dividend rate will reset on December 31, 2014 and every five years thereafter to a yield per annum equal to the then sum of the five-year Government of Canada bond yield and 1.92 per cent. The preferred shares are redeemable by TransCanada on or after December 31, 2014 at a price of $25 per share plus all accrued and unpaid dividends.
The preferred shareholders will have the right to convert their shares into Series 2 cumulative redeemable first preferred shares on December 31, 2014 and on December 31 of every fifth year thereafter. The holders of Series 2 preferred shares will be entitled to receive quarterly floating rate cumulative dividends at a yield per annum equal to the sum of the then 90-day Government of Canada treasury bill rate and 1.92 per cent.
On September 21, 2009, TransCanada filed a short form base shelf prospectus qualifying for issuance $3.0 billion of common shares, first or second preferred shares and/or subscription receipts in Canada and the U.S. until October 2011. This base shelf prospectus replaced the base shelf prospectus filed in July 2008, which was exhausted by the common share issue discussed below.
In June 2009, TransCanada completed a public offering of 58.4 million common shares, including full 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 nine months ended September 30, 2009, TransCanada issued 2.5 million and 6.0 million common shares, respectively, under its Dividend Reinvestment and Share Purchase Plan (DRP), in lieu of making cash dividend payments totalling $73 million and $182 million, respectively. In the three and nine months ended September 30, 2008, TransCanada issued 1.7 million and 4.8 million common shares, respectively, under its DRP, in lieu of making cash dividend payments totalling $65 million and $177 million, respectively. 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 September 30, 2009, there were no significant amounts past due or impaired.
As a level of uncertainty in the global financial markets remains, 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. Although losses are not expected to exceed the statistically estimated VaR on 95 per cent of occasions, losses on the other five per cent of occasions could be substantially greater than the estimated VaR. TransCanada's consolidated VaR was $14 million at September 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 September 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 $73 million (December 31, 2008 - $76 million).
The change in fair value of proprietary natural gas inventory in storage in the three and nine months ended September 30, 2009 resulted in a net pre-tax unrealized gain of $16 million and a net pre-tax unrealized loss of $13 million, respectively (2008 - unrealized losses of $108 million and $6 million, respectively), which were recorded to Revenues and Inventories. The net change in fair value of natural gas forward purchase and sales contracts in the three and nine months ended September 30, 2009 resulted in a net pre-tax unrealized loss of $2 million and a net pre-tax unrealized gain of $7 million, respectively (2008 - unrealized gain of $106 million and unrealized loss of $1 million), 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 September 30, 2009, the Company had designated as a net investment hedge U.S. dollar-denominated debt with a carrying value of $8.1 billion (US$7.6 billion) and a fair value of $9.2 billion (US$8.6 billion). At September 30, 2009, Other Assets included $51 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
September 30, 2009 December 31, 2008
--------------------------------------------
--------------------------------------------
Notional Notional
Asset/(Liability) Fair or or
(unaudited) Value Principal Fair Principal
(millions of dollars) (1) Amount Value(1) Amount
----------------------------------------------------------------------------
----------------------------------------------------------------------------
U.S. dollar cross-currency swaps
(maturing 2009 to 2014)(2) 40 U.S. 1,650 (218) U.S. 1,650
U.S. dollar forward foreign
exchange contracts
(maturing 2009 to 2010)(2) 7 U.S. 635 (42) U.S. 2,152
U.S. dollar options
(maturing 2009)(2) 4 U.S. 400 6 U.S. 300
--------------------------------------------
51 U.S. 2,685 (254) U.S. 4,102
--------------------------------------------
--------------------------------------------
(1) Fair values equal carrying values.
(2) As at September 30, 2009.
Non-Derivative Financial Instruments Summary
The carrying and fair values of non-derivative financial instruments were as
follows:
September 30, 2009 December 31, 2008
----------------------------------------
(unaudited) Carrying Fair Carrying Fair
(millions of dollars) Amount Value Amount Value
----------------------------------------------------------------------------
Financial Assets(1)
Cash and cash equivalents 2,406 2,406 1,308 1,308
Accounts receivable and other 983 983 1,404 1,404
assets(2)(3)
Available-for-sale assets(2) 23 23 27 27
----------------------------------------
3,412 3,412 2,739 2,739
----------------------------------------
----------------------------------------
Financial Liabilities(1)(3)
Notes payable 1,324 1,324 1,702 1,702
Accounts payable and deferred
amounts(4) 1,606 1,606 1,372 1,372
Accrued interest 342 342 359 359
Long-term debt and junior
subordinated notes 18,469 21,388 17,367 16,152
Long-term debt of joint ventures 1,090 1,149 1,076 1,052
----------------------------------------
22,831 25,809 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 September 30, 2009, the Consolidated Balance Sheet included financial
assets of $834 million (December 31, 2008 - $1,257 million) in Accounts
Receivable and $172 million (December 31, 2008 - $174 million) in Other
Assets.
(3) Recorded at amortized cost.
(4) At September 30, 2009, the Consolidated Balance Sheet included financial
liabilities of $1,604 million (December 31, 2008 - $1,350 million) in
Accounts Payable and $2 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:
September 30, 2009
(unaudited)
(all amounts in millions Natural Oil Foreign
unless otherwise indicated) Power Gas Products Exchange Interest
----------------------------------------------------------------------------
Derivative Financial
Instruments Held for
Trading(1)
Fair Values(2)
Assets $ 126 $ 129 $ 4 $ 4 $ 35
Liabilities $ (71) $ (134) $ (3) $ (64) $ (81)
Notional Values
Volumes(3)
Purchases 9,876 204 180 - -
Sales 9,718 171 228 - -
Canadian dollars - - - - 699
U.S. dollars - - - U.S. U.S.
426 1,425
227/U.S.
Cross-currency - - - 157 -
Net unrealized
(losses)/gains
in the period(4)
Three months ended
September 30, 2009 $ (8) $ 21 $ (1) $ 2 $ (7)
Nine months ended
September 30, 2009 $ 11 $ (4) $ 1 $ 4 $ 20
Net realized gains/(losses)
in the period(4)
Three months ended
September 30, 2009 $ 23 $ (43) $ 1 $ 11 $ (5)
Nine months ended
September 30, 2009 $ 53 $ (56) - $ 28 $ (14)
2009- 2009- 2009- 2009- 2009-
Maturity dates 2014 2014 2010 2012 2018
Derivative Financial
Instruments in Hedging
Relationships(5)(6)
Fair Values(2)
Assets $ 229 $ 2 - - $ 6
Liabilities $ (154) $ (15) - $ (36) $ (67)
Notional Values
Volumes(3)
Purchases 13,597 24 - - -
Sales 14,806 - - - -
U.S. dollars - - - - 1,825
Cross-currency 136/U.S.
- - - 100 -
Net realized gains/(losses)
in the period(4)
Three months ended
September 30, 2009 $ 30 $ (8) - - $ (10)
Nine months ended
September 30, 2009 $ 108 $ (28) - - $ (27)
2009- 2009- n/a 2009- 2010-
Maturity dates 2015 2012 2013 2020
-------------------------------------------------
-------------------------------------------------
(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 $6 million and a notional amount of US$150
million. Net realized gains on fair value hedges for the three and nine
months ended September 30, 2009 were $1 million and $3 million,
respectively, and were included in Interest Expense. In third 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 nine months ended September 30, 2009
included gains of $1 million and $2 million, respectively, for the
changes in fair value of power and natural gas cash flow hedges that
were ineffective in offsetting the change in fair value of their related
underlying positions. There were no gains or losses included in Net
Income for the three and nine months ended September 30, 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
gains/(losses)
in the period(3)
Three months ended
September 30, 2008 $ 5 $ (1) - - $ 5
Nine months ended
September 30, 2008 - $ (12) - $(7) $ 3
Net realized
gains/(losses)
in the period(3)
Three months ended
September 30, 2008 $ 12 $ (11) - $ 2 $ 2
Nine months ended
September 30, 2008 $ 21 $ (6) - $ 12 $ 12
Maturity dates(4) 2009- 2009-2011 2009 2009-2012 2009-2018
2014
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
gains/(losses)
in the period(3)
Three months ended
September 30, 2008 $ 14 $ (1) - - $ (2)
Nine months ended
September 30, 2008 $ (24) $ 18 - - $ (4)
Maturity dates(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. Net realized gains on
fair value hedges for the three and nine months ended September 30, 2008
were $1 million and $1 million, respectively, and were included in
Interest Expense. In third 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 nine months ended September 30, 2008
included gains of $7 million and $4 million, respectively, for the
changes in fair value of power and natural gas cash flow hedges that
were ineffective in offsetting the change in fair value of their related
underlying positions. There were no gains or losses included in Net
Income for the three and nine months ended September 30, 2008 for
discontinued cash flow hedges. 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 September 30, December 31,
dollars) 2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Current
Other current assets 370 318
Accounts payable (359) (298)
Long-term
Other assets 216 191
Deferred amounts (266) (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 September 30 Plans Plans
---------------------------------------
---------------------------------------
(unaudited)(millions of dollars) 2009 2008 2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Current service cost 11 13 - -
Interest cost 22 20 2 2
Expected return on plan assets (24) (23) - -
Amortization of net actuarial
loss 2 4 1 1
Amortization of past service
costs 1 1 - -
---------------------------------------
Net benefit cost recognized 12 15 3 3
---------------------------------------
---------------------------------------
Pension Benefit Other Benefit
Nine months ended September 30 Plans Plans
---------------------------------------
---------------------------------------
(unaudited)(millions of dollars) 2009 2008 2009 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Current service cost 34 38 1 1
Interest cost 67 59 6 6
Expected return on plan assets (75) (69) (1) (1)
Amortization of transitional
obligation related to
regulated business - - 1 1
Amortization of net actuarial
loss 4 13 2 2
Amortization of past service
costs 3 3 - -
---------------------------------------
Net benefit cost recognized 33 44 9 9
---------------------------------------
---------------------------------------
8. Acquisitions and Dispositions
On August 14, 2009, TransCanada purchased ConocoPhillips' remaining 20 per cent ownership interest in Keystone for US$553 million plus the assumption of US$197 million of short-term indebtedness. The acquisition increased TransCanada's ownership interest in Keystone to 100 per cent. The purchase price reflects ConocoPhillips' capital contributions to date and includes an allowance for funds used during construction. TransCanada began fully consolidating Keystone in the Pipelines segment upon acquisition.
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 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. TransCanada's increased ownership in PipeLines LP resulted in a decrease in Non-Controlling Interests and an increase in Contributed Surplus.
9. Commitments, Guarantees and Contingencies
Commitments
On August 14, 2009, the Company acquired ConocoPhillips' remaining interest in Keystone. As a result, TransCanada assumed 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.
Guarantees
As a result of the acquisition of the remaining interest in Keystone, the Company's potential exposure to guarantees of jointly owned entities was reduced by an estimated $305 million to $678 million since December 31, 2008.
Contingencies
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 nine months of 2009 are expected to be repaid.
10. Subsequent Events
Subsequent events have been assessed up to November 3, 2009, which is the date the financial statements were available for issuance.
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: Terry Cunha/Cecily Dobson (403) 920-7859 or (800) 608-7859.
Visit the TransCanada website at: http://www.transcanada.com.