Published:
TransCanada Announces Second Quarter Results, Board Declares Dividend of $0.34 Per Common Share
TransCanada Corporation (TSX: TRP) (NYSE: TRP):
Second Quarter Highlights
(All financial figures are unaudited and in Canadian dollars unless noted otherwise)
- Net income for second quarter 2007 of $257 million ($0.48 per share) compared to $244 million ($0.50 per share) in second quarter 2006
- Comparable earnings for second quarter 2007 of $241 million ($0.45 per share) compared to $198 million ($0.41 per share) for the same period in 2006, an increase of approximately 10 per cent on a per share basis
- Funds generated from operations for second quarter 2007 of $596 million compared to $539 million for the same period in 2006, an increase of approximately 11 per cent
- Dividend of $0.34 per common share declared by the Board of Directors
TransCanada Corporation (TransCanada) today announced net income for second quarter 2007 was $257 million ($0.48 per share) compared to $244 million ($0.50 per share) for second quarter 2006.
Comparable earnings were $241 million ($0.45 per share) for second quarter 2007 compared to $198 million ($0.41 per share) in second quarter 2006. The $43 million ($0.04 per share) increase in comparable earnings in second quarter 2007 compared to second quarter 2006 is primarily due to income from the acquisition of American Natural Resources Company and ANR Storage Company (collectively, ANR) and the start-up of Becancour and higher income recorded due to a settlement on the Canadian Mainline approved by the National Energy Board (NEB). Comparable earnings excluded positive income tax adjustments of $16 million in second quarter 2007. In second quarter 2006, comparable earnings excluded $33 million favourable impact on future income taxes arising from a reduction in Canadian federal and provincial corporate income tax rates and a $13 million ($23 million pre-tax) gain on the sale of TransCanada's interest in Northern Border Partners, L.P.
Net income for the six months ended June 30, 2007 was $522 million ($1.00 per share) compared to $517 million ($1.06 per share) for the same period in 2006. Net income from continuing operations for the six months ended June 30, 2007 was $522 million ($1.00 per share) compared to $489 million ($1.00 per share) for the same period in 2006.
Comparable earnings for the six months ended June 30, 2007 were $491 million ($0.94 per share) compared to $425 million ($0.87 per share) for the same period in 2006. The $66 million ($0.07 per share) increase in comparable earnings for the six months ended June 30, 2007 compared to the same period in 2006 is primarily due to income from ANR and Becancour and higher income recorded due to the settlement on the Canadian Mainline approved by the NEB. Comparable earnings for the six months ended June 30, 2007 excluded positive income tax adjustments of $31 million. In the first six months of 2006, comparable earnings excluded a $33 million favourable impact on future income taxes, an $18 million ($29 million pre-tax) bankruptcy settlement with Mirant and the $13 million gain on the sale of TransCanada's interest in Northern Border Partners, L.P.
Net cash provided by operations in second quarter 2007 was $689 million compared to $448 million for the same period in 2006. Net cash provided by operations for the six months ended June 30, 2007 was $1,307 million compared to $963 million for the same period in 2006. The increase in net cash provided by operations was primarily due to an increase in funds generated from operations and a decrease in operating working capital.
Funds generated from operations in second quarter 2007 were $596 million compared to $539 million for the same period in 2006. Funds generated from operations for the six months ended June 30, 2007 were $1,178 million compared to $1,056 million for the same period in 2006.
"We continue to advance our large portfolio of Pipelines and Energy projects," said Hal Kvisle, TransCanada's president and chief executive officer. "Significant milestones in the second quarter include commercial support for the Keystone Oil Pipeline expansion and extension and favourable decisions from the Quebec and Federal governments on the Cacouna Energy LNG project. We also made progress with the Portlands Energy Centre, Halton Hills Generating Station, Cartier Wind project and the Bruce Power restart and refurbishment project."
Notable recent developments in Pipelines, Energy and Corporate include:
Pipelines:
- TransCanada announced a successful Open Season on the Keystone Oil Pipeline (Keystone) that supports an expansion to 590,000 barrels per day and extension of the pipeline to Cushing, Oklahoma. TransCanada has now secured long-term contracts for a total of 495,000 barrels per day with an average duration of 18 years. In addition, the NEB held a public hearing related to the construction and operation of Keystone's Canadian facilities. The public hearing ended on June 21, 2007 and a decision is expected in fourth quarter 2007.
- TransCanada's five-year settlement with interested stakeholders for years 2007 to 2011 on its Canadian Mainline was approved by the NEB in May 2007. The settlement reflects a cost of capital based on a rate of return on common equity determined by the NEB return-on-equity formula, on a deemed common equity ratio of 40 per cent, an increase from 36 per cent. The NEB also approved TransCanada's request that interim tolls be made final for 2007.
- ANR received regulatory approval to proceed with a 14 Bcf natural gas storage expansion project in Michigan. This capacity is fully contracted with an expected in service date of April 1, 2008 for injections and November 1, 2008 for withdrawals. This project is in addition to a natural gas storage enhancement and expansion program that will increase Michigan capacity available for sale by 13 Bcf. This program was also fully subscribed with injections commencing in April 2007. The expected capital cost of these projects is US$125 million.
- In June 2007, TransCanada made an application to the Alberta Energy and Utilities Board for approval to construct approximately $300 million of new facilities on the Alberta System to initially serve the growing demand for natural gas in the Fort McMurray region of Alberta.
- In July 2007, the NEB approved TransCanada's application to add Gros Cacouna as a receipt point on its integrated Canadian Mainline system and reaffirmed the existing rolled-in toll methodology. The effective date for these approvals is when the facilities required to connect the Gros Cacouna receipt point are approved and placed in service. Trans Quebec and Maritimes Pipeline (TQM) and TransCanada are preparing applications to the NEB for approval to construct those facilities required to connect the Cacouna Energy Liquefied Natural Gas (LNG) terminal at Gros Cacouna to the existing integrated TQM/Canadian Mainline infrastructure.
- TransCanada assumed operatorship at ANR, Great Lakes, and Northern Border natural gas transmission systems and commenced physical natural gas deliveries at the Tamazunchale pipeline in east-central Mexico.
Energy:
- The Cacouna Energy LNG project received federal cabinet approval pursuant to the Canadian Environmental Assessment Act. This approval is required for the issuance of permits under the Fisheries Act (Canada) and Navigable Waters Protection Act (Canada). Also, the Quebec government granted a decree pursuant to the Environment Quality Act approving the Cacouna regassification terminal.
- Construction is progressing on Bruce A, Portlands Energy Centre, and on the Cartier Wind Energy project. Pre-construction activities continue at the Halton Hills Generating Station.
- Becancour, one of TransCanada's largest co-generation facilities, is successfully operating and running as expected. Becancour supplies electricity to Hydro-Quebec Distribution and provides a source of competitively priced steam.
Corporate:
- In April 2007, US$1.0 billion of Junior Subordinated Notes were issued maturing in 2067 and bearing interest of 6.35 per cent until May 2017, at which time the interest on the Notes will convert to a floating rate reset quarterly to the three-month London Interbank Offered Rate plus 221 basis points.
Teleconference - Audio and Slide Presentation
TransCanada will hold a teleconference today at 11 a.m.(Mountain) / 1 p.m. (Eastern) to discuss the second quarter 2007 financial results and general developments and issues concerning the company. Analysts, members of the media and other interested parties wanting to participate should phone 1-866-898-9626 or 416-340-2216 (Toronto area) at least 10 minutes prior to the start of the teleconference. No passcode is required. A live audio and slide presentation webcast of the teleconference will also be available on TransCanada's website at www.transcanada.com.
The conference will begin with a short address by members of TransCanada's executive management, followed by a question and answer period for investment analysts. A question and answer period for members of the media will immediately follow.
A replay of the teleconference will be available two hours after the conclusion of the call until midnight (Eastern) August 3, 2007. Please call 1-800-408-3053 or 416-695-5800 (Toronto area) and enter passcode 3227683. The webcast will be archived and available for replay on www.transcanada.com.
About TransCanada
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 and LNG facilities. 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 360 billion cubic feet of storage capacity. A growing independent power producer, TransCanada owns, or has interests in, approximately 7,700 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.
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", "may", "should", "estimate", "project", "outlook", "forecast" or other similar words are used to identify such forward-looking information. All forward-looking statements are based on TransCanada's beliefs and assumptions based on information available at the time such statements were made. The results or events predicted in this information may differ from actual results or events. Factors which 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 availability and price of energy commodities, regulatory decisions, changes in environmental and other laws and regulations, competitive factors in the pipeline and energy industry sectors, construction and completion of capital projects, access to capital markets, interest and currency exchange rates, technological developments and the current economic conditions in North America. By its nature, such 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 other expectations expressed. For additional information on these and other factors, see the reports filed by TransCanada with Canadian securities regulators and with the U.S. Securities and Exchange Commission. Readers are cautioned not to 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 TransCanada undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, except as required by law.
NON-GAAP MEASURES
TransCanada uses the measures "comparable earnings", "comparable earnings per share" and "funds generated from operations" in this news release. These measures do not have any standardized meaning prescribed by generally accepted accounting principles (GAAP) and are therefore considered to be non-GAAP measures. These measures are unlikely to be comparable to similar measures presented by other entities. These measures have been used to provide readers with additional information on TransCanada's operating performance, liquidity and its ability to generate funds to finance its operations.
Comparable earnings is comprised of net income from continuing operations adjusted for specific items that are significant and not typical of the Company's operations. The identification of specific items is subjective and management uses judgement in determining the items to be excluded in calculating comparable earnings. Specific items may include, but are not limited to, certain income tax refunds and adjustments, gains or losses on sales of assets, legal settlements and bankruptcy settlements received from former customers. A reconciliation of comparable earnings to net income is presented in the Consolidated Results of Operation section in the Management's Discussion and Analysis accompanying this news release. Comparable earnings per share is calculated by dividing comparable earnings by the weighted average number of shares outstanding for the period.
Funds generated from operations is comprised of 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 Second Quarter 2007 Financial Highlights chart in this news release.
Second Quarter 2007 Financial Highlights
(unaudited)
Three months ended Six months ended
Operating Results June 30 June 30
(millions of dollars) 2007 2006 2007 2006
----------------------------------------------------------------------------
Revenues 2,212 1,685 4,461 3,579
Net Income
Continuing operations 257 244 522 489
Discontinued operations - - - 28
--------------------------------------------
257 244 522 517
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Comparable Earnings (1) 241 198 491 425
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Cash Flows
Funds generated from
operations (1) 596 539 1,178 1,056
Decrease/(increase) in
operating working capital 93 (91) 129 (93)
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Net cash provided by operations 689 448 1,307 963
--------------------------------------------
--------------------------------------------
Capital Expenditures 386 327 692 630
Acquisitions, Net of Cash
Acquired 4 358 4,224 358
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Three months ended Six months ended
June 30 June 30
Common Share Statistics 2007 2006 2007 2006
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Net Income Per Share - Basic
Continuing operations $ 0.48 $ 0.50 $ 1.00 $ 1.00
Discontinued operations - - - 0.06
--------------------------------------------
$ 0.48 $ 0.50 $ 1.00 $ 1.06
--------------------------------------------
--------------------------------------------
Comparable Earnings Per Share
- Basic (1) $ 0.45 $ 0.41 $ 0.94 $ 0.87
Dividends Declared Per Share $ 0.34 $ 0.32 $ 0.68 $ 0.64
Basic Common Shares
Outstanding (millions)
Average for the period 536 488 522 488
End of period 536 488 536 488
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(1) For a further discussion on comparable earnings, funds generated from
operations and comparable earnings per share, refer to the Non-GAAP
Measures section in Management's Discussion and Analysis of this Second
Quarter 2007 Quarterly Report to Shareholders.
Management's Discussion and Analysis
The Management's Discussion and Analysis (MD&A) dated July 26, 2007 should be read in conjunction with the accompanying unaudited Consolidated Financial Statements of TransCanada Corporation (TransCanada or the Company) for the three and six months ended June 30, 2007. It should also be read in conjunction with the audited Consolidated Financial Statements and notes thereto, and the MD&A contained in TransCanada's 2006 Annual Report for the year ended December 31, 2006. 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. 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 2006 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", "may", "should", "estimate", "project", "outlook", "forecast" or other similar words are used to identify such forward-looking information. All forward-looking statements are based on TransCanada's beliefs and assumptions based on information available at the time such statements were made. The results or events predicted in this information may differ from actual results or events. Factors which 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 availability and price of energy commodities, regulatory decisions, changes in environmental and other laws and regulations, competitive factors in the pipeline and energy industry sectors, construction and completion of capital projects, access to capital markets, interest and currency exchange rates, technological developments and the current economic conditions in North America. By its nature, such 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 other expectations expressed. For additional information on these and other factors, see the reports filed by TransCanada with Canadian securities regulators and with the U.S. Securities and Exchange Commission. Readers are cautioned not to place undue reliance on this forward-looking information, which is given as of the date it is expressed in this MD&A or otherwise, and 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
The Company uses the measures "comparable earnings", "comparable earnings per share", "funds generated from operations" and "operating income" in this MD&A. These measures do not have any standardized meaning prescribed by generally accepted accounting principles (GAAP) and are therefore considered to be non-GAAP measures. These measures are unlikely to be comparable to similar measures presented by other entities. These measures have been used to provide readers with additional information on the Company's operating performance, liquidity and its ability to generate funds to finance its operations.
Comparable earnings is comprised of net income from continuing operations adjusted for specific items that are significant and not typical of the Company's operations. The identification of specific items is subjective and management uses judgement in determining the items to be excluded in calculating comparable earnings. Specific items may include, but are not limited to, certain income tax refunds and adjustments, gains or losses on sales of assets, legal settlements and bankruptcy settlements received from former customers. A reconciliation of comparable earnings to net income is presented in the Consolidated Results of Operations section in this MD&A. Comparable earnings per share is calculated by dividing comparable earnings by the weighted average number of shares outstanding for the period.
Funds generated from operations is comprised of 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 in this MD&A.
Operating income is used in the Energy segment and is comprised of revenues less operating expenses as shown on the consolidated income statement. A reconciliation of operating income to net earnings is presented in the Energy section in this MD&A.
Acquisitions
ANR and Great Lakes
On February 22, 2007, TransCanada acquired American Natural Resources Company and ANR Storage Company (together ANR) and an additional 3.55 per cent interest in Great Lakes from El Paso Corporation for approximately US$3.4 billion, subject to certain post-closing adjustments, including US$491 million of assumed long-term debt. TransCanada began consolidating ANR and Great Lakes in the Pipelines segment subsequent to the acquisition date. The acquisition was financed with a combination of proceeds from an equity offering of the Company, cash on hand and funds drawn on loan facilities.
Great Lakes
On February 22, 2007, PipeLines LP acquired a 46.45 per cent interest in Great Lakes from El Paso Corporation for approximately US$945 million, including US$209 million of assumed long-term debt, subject to certain post-closing adjustments. The acquisition was financed with debt facilities and a private placement offering of Pipelines LP units, which included a US$312-million investment by TransCanada.
Consolidated Results of Operations
Reconciliation of Comparable Earnings to Net Income
(unaudited) Three months ended Six months ended
(millions of dollars except June 30 June 30
per share amounts) 2007 2006 2007 2006
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Pipelines
Comparable earnings 166 134 321 273
Specific items:
Bankruptcy settlement with
Mirant - - - 18
Gain on sale of Northern
Border Partners, L.P interest - 13 - 13
--------------------------------------------
Net earnings 166 147 321 304
--------------------------------------------
Energy
Comparable earnings 90 74 196 174
Specific item:
Income tax adjustments 4 23 4 23
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Net earnings 94 97 200 197
--------------------------------------------
Corporate
Comparable (expenses)/earnings (15) (10) (26) (22)
Specific item:
Income tax adjustments 12 10 27 10
--------------------------------------------
Net (expenses)/earnings (3) - 1 (12)
--------------------------------------------
Net Income
Continuing operations (1) 257 244 522 489
Discontinued operations - - - 28
--------------------------------------------
Net Income 257 244 522 517
--------------------------------------------
--------------------------------------------
Net Income Per Share
Continuing operations(2) $ 0.48 $ 0.50 $ 1.00 $ 1.00
Discontinued operations - - - 0.06
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Basic and Diluted $ 0.48 $ 0.50 $ 1.00 $ 1.06
--------------------------------------------
--------------------------------------------
(1) Comparable Earnings 241 198 491 425
Specific items (net of tax,
where applicable):
Income tax adjustments 16 33 31 33
Bankruptcy settlement with
Mirant - - - 18
Gain on sale of Northern
Border Partners, L.P.
interest - 13 - 13
Net Income from Continuing
--------------------------------------------
Operations 257 244 522 489
--------------------------------------------
--------------------------------------------
(2) Comparable Earnings Per
Share $ 0.45 $ 0.41 $ 0.94 $ 0.87
Specific items - per share
Income tax adjustments 0.03 0.06 0.06 0.06
Bankruptcy settlement
with Mirant - - - 0.04
Gain on sale of Northern
Border Partners, L.P.
interest - 0.03 - 0.03
Net Income Per Share from
--------------------------------------------
Continuing Operations $ 0.48 $ 0.50 $ 1.00 $ 1.00
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--------------------------------------------
TransCanada's net income and net income from continuing operations (net earnings) in second quarter 2007 were $257 million or $0.48 per share compared to $244 million or $0.50 per share in second quarter 2006. The $13-million increase in net earnings in second quarter 2007 compared to 2006 was primarily due to income from the acquisition of ANR in February 2007, higher income recorded due to a five-year settlement on the Canadian Mainline approved by the National Energy Board (NEB) in May 2007 and start-up of the Becancour cogeneration plant in September 2006. Net income and net earnings for second quarter 2007 also included positive income tax adjustments of $16 million resulting from changes in Canadian federal income tax legislation. These increases were partially offset by a $33-million favourable impact on future income taxes arising from a reduction in Canadian federal and provincial corporate income tax rates and a $13-million ($23 million pre-tax) gain on the sale of TransCanada's interest in Northern Border Partners, L.P. that were recorded in second quarter 2006. On a per share basis, net income reflects the above-mentioned items as well as an increased number of shares outstanding following the Company's $1.725 billion share issuance in first quarter 2007.
Comparable earnings for second quarter 2007 were $241 million or $0.45 per share, compared to $198 million or $0.41 per share for the same period in 2006. Comparable earnings excluded the positive income tax adjustments of $16 million in second quarter 2007. In second quarter 2006, comparable earnings excluded the $33-million favourable impact on future income taxes arising from a reduction in Canadian federal and provincial corporate income tax rates and the $13-million ($23 million pre-tax) gain on the sale of TransCanada's interest in Northern Border Partners, L.P.
Net income was $522 million or $1.00 per share for the first six months in 2007 compared to $517 million or $1.06 per share for the same period last year. Net earnings for the six months ended June 30, 2007 were $522 million or $1.00 per share compared to $489 million or $1.00 per share for the same period in 2006. The increase in net income and net earnings was due to factors discussed above as well as positive income tax adjustments of $15 million in first quarter 2007, which included the resolution of certain income tax matters and an internal restructuring. Net income and net earnings for the six months ended June 30, 2006 included an $18-million ($29 million pre-tax) bankruptcy settlement with Mirant Corporation and certain of its subsidiaries (Mirant). TransCanada's net income for the six months ended June 30, 2006 also included net income from discontinued operations of $28 million or $0.06 per share, reflecting bankruptcy settlements with Mirant received in first quarter 2006 related to TransCanada's Gas Marketing business divested in 2001. On a per share basis, net income decreased and net earnings remained unchanged primarily due to the above-mentioned items and an increased number of shares outstanding following the Company's $1.725 billion share issuance in first quarter 2007.
Comparable earnings for the first six months of 2007 were $491 million or $0.94 per share, compared to $425 million or $0.87 per share for the same period in 2006. Comparable earnings for the six months ended June 30, 2007 excluded positive income tax adjustments of $31 million recorded in the first six months of 2007. In the first six months of 2006, comparable earnings excluded the $33-million favourable impact on future income taxes, the $18-million ($29 million pre-tax) bankruptcy settlement with Mirant and the $13-million gain on the sale of TransCanada's interest in Northern Border Partners, L.P.
Results from each business segment for the three and six months ended June 30, 2007 are discussed further in the Pipelines, Energy and Corporate sections of this MD&A.
Funds generated from operations of $596 million and $1.2 billion for the three and six months ended June 30, 2007 increased $57 million and $122 million, respectively, when compared to the same periods in 2006.
Pipelines
The Pipelines business generated net earnings of $166 million for the three months ended June 30, 2007 compared to $147 million for the same period in 2006. Excluding the $13-million gain on the sale of TransCanada's interest in Northern Border Partners, L.P. in second quarter 2006, comparable earnings increased $32 million in second quarter 2007 compared to the same period in 2006.
Net earnings for the six months ended June 30, 2007 were $321 million compared to $304 million for the same six months in 2006. Excluding the gain on the sale of TransCanada's interest in Northern Border Partners, L.P. and an $18-million Mirant settlement in first quarter 2006, comparable earnings increased $48 million.
Pipelines Results-at-a-Glance
Three months ended Six months ended
(unaudited) June 30 June 30
(millions of dollars) 2007 2006 2007 2006
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Wholly Owned Pipelines
Canadian Mainline 75 61 132 120
Alberta System 34 34 65 67
ANR (1) 29 - 50 -
GTN 5 13 16 27
Foothills (2) 8 7 14 14
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151 115 277 228
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Other Pipelines
Great Lakes (3) 11 11 25 23
Iroquois 3 3 8 7
Portland 1 (2) 6 4
PipeLines LP (4) 4 3 6 4
Ventures LP 3 3 6 6
TQM 1 1 3 3
TransGas 5 2 8 5
Gas Pacifico/INNERGY - 3 2 4
Tamazunchale 2 - 5 -
Northern Development (1) (1) (2) (2)
General, administrative, support
costs and other (14) (4) (23) (9)
--------------------------------------------
15 19 44 45
--------------------------------------------
Comparable earnings 166 134 321 273
Bankruptcy settlement with
Mirant - - - 18
Gain on sale of Northern Border
Partners, L.P. interest - 13 - 13
--------------------------------------------
Net Earnings 166 147 321 304
--------------------------------------------
--------------------------------------------
(1) ANR includes results of operations since February 22, 2007.
(2) Foothills reflects the combined operations of Foothills and the BC
System since January 1, 2007. Effective April 1, 2007, Foothills and BC
System were integrated.
(3) Great Lakes' results reflect TransCanada's 53.55 per cent ownership in
Great Lakes since February 22, 2007.
(4) PipeLines LP's results include TransCanada's effective ownership of an
additional 15 per cent in Great Lakes as a result of TransCanada's 32.1
per cent interest in PipeLines LP since February 22, 2007.
Wholly Owned Pipelines
Canadian Mainline's net earnings increased $14 million and $12 million for the three and six months ended June 30, 2007, respectively, compared to the corresponding periods in 2006. These increases reflect the impact of a five-year tolls settlement (the Settlement) with interested stakeholders effective January 1, 2007 to December 31, 2011 on the Canadian Mainline. The Settlement was approved by the NEB in May 2007, and included an increase in the deemed common equity ratio from 36 per cent to 40 per cent. As a result of the Settlement, Canadian Mainline's net earnings for the three months ended June 30, 2007, compared to the same period in the prior year, increased $12 million as a result of the higher common equity ratio ($6 million related to first quarter 2007). In addition, Canadian Mainline's net earnings were positively impacted by certain performance-based incentive arrangements and operations, maintenance and administrative (OM&A) cost savings, some of which related to first quarter 2007. Partially offsetting these increases were the negative impacts of a lower rate of return on common equity (ROE) of 8.46 per cent in 2007 (8.88 per cent in 2006) and a lower average investment base.
Canadian Mainline's net earnings for the six months ended June 30, 2007, compared to the same period in the prior year, increased $12 million as a result of the higher common equity ratio, certain performance-based incentive arrangements and OM&A cost savings under the Settlement, partially offset by a lower ROE in 2007 and a lower average investment base.
The Alberta System's net earnings were $34 million in second quarter and $65 million for the first six months in 2007, respectively, compared to $34 million and $67 million for the same periods in 2006. Net earnings in 2007 reflect an ROE of 8.51 per cent in 2007 compared to an ROE of 8.93 per cent in 2006, on deemed common equity of 35 per cent.
For the three and six months ended June 30, 2007, ANR's net earnings were $29 million and $50 million, respectively, which are generally in line with the Company's expectations. TransCanada completed the acquisition of ANR on February 22, 2007 and included net earnings from this date. ANR's revenues are primarily derived from its interstate natural gas transmission, storage, gathering and related services. Due to the seasonal nature of the business, ANR's volumes, revenues and net earnings are generally higher in the winter months.
GTN's comparable earnings for the three and six months ended June 30, 2007 decreased $8 million and $11 million, respectively, from the same periods in 2006 primarily due to lower operating revenues as a result of lower volumes contracted on a long-term firm basis, higher maintenance costs and a higher provision taken for non-payment of contract transportation revenues from a subsidiary of Calpine Corporation that filed for bankruptcy protection. Pending resolution of GTN's current rate case filing, GTN is recording its 2007 revenues at 2006 rates. As a result, GTN has been recording a provision for rate refund equal to the difference in transportation revenue based on GTN's interim 2007 rates and the rates that were in effect in 2006.
Operating Statistics
Gas
ANR Transmission
Six months ended Canadian Alberta (3) Northwest Foothills
June 30 Mainline(1) System(2) (4) System(3) System (5)
(unaudited) 2007 2006 2007 2006 2007 2007 2006 2007 2006
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Average investment base
($ millions) 7,359 7,454 4,254 4,305 n/a n/a n/a 816 861
Delivery volumes (Bcf)
Total 1,614 1,534 2,004 2,026 498 371 349 676 656
Average per day 8.9 8.5 11.1 11.2 3.9 2.0 1.9 3.7 3.6
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(1) Canadian Mainline deliveries originating at the Alberta border and in
Saskatchewan for the six months ended June 30, 2007 were 1,110 Bcf
(2006 - 1,170 Bcf); average per day was 6.1 Bcf (2006 - 6.5 Bcf).
(2) Field receipt volumes for the Alberta System for the six months ended
June 30, 2007 were 2,039 Bcf (2006 - 2,070 Bcf); average per day was
11.3 Bcf (2006 - 11.4 Bcf).
(3) ANR and the Gas Transmission Northwest System operate under a fixed rate
model approved by the United States Federal Energy Regulatory Commission
(FERC) and, as a result, the systems' current results are not dependent
on average investment base.
(4) ANR includes results of pipeline operations since February 22, 2007.
(5) Foothills reflects the combined operations of Foothills and the BC
System since January 1, 2007. Effective April 1, 2007, Foothills and BC
System were integrated.
Other Pipelines
TransCanada's proportionate share of comparable earnings from Other Pipelines was $15 million for the three months ended June 30, 2007 compared to $19 million for the same period in 2006. The decrease was primarily due to higher project development and support costs as a result of growing the Pipelines business and decreased earnings from Gas Pacifico/INNERGY in second quarter 2007. These decreases were partially offset by earnings from Tamazunchale, which commenced operations in December 2006, and increased earnings from Portland and TransGas.
TransCanada's proportionate share of comparable earnings from Other Pipelines for the six months ended June 30, 2007 were $44 million compared to $45 million in the corresponding period in 2006. The $1 million decrease in earnings was primarily due to higher project development and support costs as a result of growing the Pipelines business, offset by earnings in 2007 from Tamazunchale and higher earnings from TransGas, Great Lakes, Portland and PipeLines LP in the first six months of 2007.
As at June 30, 2007, TransCanada had advanced $131 million to the Aboriginal Pipeline Group with respect to the Mackenzie Gas Pipeline Project (MGP) and had capitalized $65 million related to the Keystone oil pipeline. These amounts were included in Other Assets.
TransCanada and its co-venturers on the MGP continue to pursue the development of the project, focusing on the regulatory process and discussions with the Canadian federal government on fiscal framework. Project timing is uncertain and is conditional upon regulatory and fiscal matters. TransCanada's ability to recover its investment remains dependent on the successful outcome of the project.
Energy
Energy's net earnings of $94 million in second quarter 2007 decreased $3 million compared to $97 million in second quarter 2006. Excluding $4 million of income tax adjustments in second quarter 2007 and $23 million of income tax adjustments in second quarter 2006, comparable earnings of $90 million increased $16 million in second quarter 2007.
Energy's net earnings for the six months ended June 30, 2007 of $200 million increased $3 million compared to $197 million for the same period in 2006. Excluding the 2007 and 2006 income tax adjustments, comparable earnings for the six months ended June 30, 2007 increased $22 million.
Energy Results-at-a-Glance
Three months ended Six months ended
(unaudited) June 30 June 30
(millions of dollars) 2007 2006 2007 2006
----------------------------------------------------------------------------
Bruce Power 31 41 60 104
Western Power Operations 57 46 130 104
Eastern Power Operations 70 43 137 92
Natural Gas Storage 20 17 50 39
General, administrative,
support costs and other (39) (35) (75) (65)
------------------------------------------------
Operating income 139 112 302 274
Financial charges (6) (5) (10) (12)
Interest income and other 3 1 6 3
Income taxes (46) (34) (102) (91)
------------------------------------------------
Comparable Earnings 90 74 196 174
Income tax adjustments 4 23 4 23
------------------------------------------------
Net earnings 94 97 200 197
------------------------------------------------
Bruce Power
Bruce Power Results-at-a-Glance (1)
Three months ended Six months ended
June 30 June 30
(unaudited) 2007 2006 2007 2006
----------------------------------------------------------------------------
Bruce Power (100 per cent
basis)
(millions of dollars)
Revenues
Power 450 439 910 918
Other (2) 30 11 50 28
------------------------------------------------
480 450 960 946
------------------------------------------------
Operating expenses
Operations and maintenance (259) (226) (554) (446)
Fuel (28) (22) (53) (42)
Supplemental rent (42) (42) (85) (85)
Depreciation and
amortization (36) (34) (72) (65)
------------------------------------------------
(365) (324) (764) (638)
------------------------------------------------
Operating Income 115 126 196 308
------------------------------------------------
TransCanada's proportionate
share 37 39 68 101
Adjustments (6) 2 (8) 3
------------------------------------------------
TransCanada's operating
income from Bruce Power 31 41 60 104
------------------------------------------------
Bruce Power - Other
Information
Plant availability
Bruce A 74% 63% 82% 71%
Bruce B 91% 94% 84% 95%
Combined Bruce Power 85% 84% 83% 87%
Sales volumes (GWh) (3)
Bruce A - 100 per cent 2,410 2,070 5,320 4,590
Bruce B - 100 per cent 6,370 6,630 11,800 13,250
Combined Bruce Power - 100
per cent 8,780 8,700 17,120 17,840
TransCanada's proportionate
share 3,191 3,094 6,320 6,400
Results per MWh (4)
Bruce A power revenues $ 60 $ 59 $ 59 $ 58
Bruce B power revenues $ 48 $ 48 $ 51 $ 49
Combined Bruce Power
revenues $ 51 $ 51 $ 53 $ 51
Combined Bruce Power fuel $ 3 $ 2 $ 3 $ 2
Combined Bruce Power
operating expenses(5) $ 41 $ 37 $ 44 $ 35
Percentage of output sold
to spot market 47% 39% 41% 38%
------------------------------------------------
(1) All information in the table includes adjustments to eliminate the
effects of inter-partnership transactions between Bruce A and Bruce B.
(2) Includes fuel cost recoveries for Bruce A of $8 million and $17
million for the three and six months ended June 30, 2007,
respectively ($5 million and $11 million for the three and six months
ended June 30, 2006, respectively). Other income also includes fair
value changes of the cash flow hedges that have not been designated
for hedge accounting.
(3) Gigawatt hours.
(4) Megawatt hours.
(5) Net of fuel cost recoveries.
TransCanada's operating income of $31 million from its investment in Bruce Power decreased $10 million in second quarter 2007 compared to second quarter 2006, primarily due to higher post-employment benefit and other employee-related costs, as well as higher costs associated with changes in duration and scope of planned outages. These impacts were partially offset by higher revenues resulting from increased generation volumes.
TransCanada's share of Bruce Power's generation for second quarter 2007 increased 97 GWh to 3,191 GWh, compared to second quarter 2006 generation of 3,094 GWh, as a result of fewer planned maintenance outage days in second quarter 2007. Bruce Power prices achieved during second quarter 2007 and 2006 (excluding other revenues) were $51 per MWh. Bruce Power's combined operating expenses (net of fuel cost recoveries) in second quarter 2007 increased to $41 per MWh from $37 per MWh in second quarter 2006 primarily due to higher employee-related and planned outage costs, discussed above.
Approximately 44 reactor days of planned maintenance outages as well as approximately 24 reactor days of unplanned outages occurred on the six operating units in second quarter 2007. In second quarter 2006, Bruce Power experienced approximately 50 reactor days of planned maintenance outages and 24 reactor days of unplanned outages. The Bruce Power units ran at a combined average availability of 85 per cent in second quarter 2007, compared to an 84 per cent combined average availability in second quarter 2006.
TransCanada's operating income from its investment in Bruce Power for the six months ended June 30, 2007 was $60 million compared to $104 million for the same period in 2006. The decrease of $44 million was primarily due to higher costs and lower sales volumes as a result of higher planned outages, as well as higher post-employment benefit and other employee-related costs. Partially offsetting these decreases was the impact of higher realized prices.
The overall plant availability percentage in 2007 is expected to be in the low 90s for the four Bruce B units and in the high 70s for the two operating Bruce A units. Two planned outages were scheduled for Bruce A Unit 3 in 2007, with the first planned one month outage completed in second quarter 2007 and a second outage now expected to last approximately one and a half months beginning in late third quarter 2007. A planned one month outage for Bruce A Unit 4 and a planned two and a half month maintenance outage for Bruce B Unit 6 were both completed in April 2007. An additional outage on Bruce A Unit 4 is expected to occur in early fourth quarter 2007 lasting approximately one month.
Income from Bruce B is directly impacted by the fluctuations in wholesale spot market prices for electricity. Net earnings from both Bruce A and Bruce B units are impacted by overall plant availability, which in turn is impacted by scheduled and unscheduled maintenance. As a result of a contract with the Ontario Power Authority (OPA), all of the output from Bruce A in second quarter 2007 was sold at a fixed price of $59.69 per MWh (before recovery of fuel costs from the OPA) compared to $58.63 per MWh for second quarter 2006. In addition, sales from the Bruce B Units 5 to 8 were subject to a floor price of $46.82 per MWh in second quarter 2007 and $45.99 per MWh in second quarter 2006. Both of the Bruce A and Bruce B reference prices are adjusted annually for inflation on April 1. In first quarter 2007, the Bruce A fixed price was $58.63 per MWh (2006 - $57.37 per MWh) and the Bruce B floor price was $45.99 per MWh (2006 - $45.00 per MWh). Payments received pursuant to the Bruce B floor price mechanism are subject to a recapture payment dependent on annual spot prices over the term of the contract. Bruce B net earnings do not include any amounts received under this floor price mechanism to date. To further reduce its exposure to spot market prices, Bruce B has entered into fixed price sales contracts to sell forward approximately 4,200 GWh of output for the remainder of 2007 and 6,500 GWh for 2008.
The capital cost of Bruce A's four-unit, seven-year restart and refurbishment project is expected to total approximately $4.25 billion with TransCanada's share being approximately $2.125 billion. As at June 30, 2007, Bruce A had incurred capital costs of $1.63 billion with respect to the restart and refurbishment project.
Western Power Operations
Western Power Operations Results-at-a-Glance
Three months ended Six months ended
(unaudited) June 30 June 30
(millions of dollars) 2007 2006 2007 2006
----------------------------------------------------------------------------
Revenues
Power 221 221 507 496
Other (1) 21 38 49 102
------------------------------------------------
242 259 556 598
------------------------------------------------
Commodity purchases resold
Power (135) (150) (314) (340)
Other (1) (12) (28) (35) (76)
------------------------------------------------
(147) (178) (349) (416)
------------------------------------------------
Plant operating costs and other (34) (30) (68) (68)
Depreciation (4) (5) (9) (10)
------------------------------------------------
Operating income 57 46 130 104
------------------------------------------------
(1) Other includes Cancarb Thermax and natural gas.
Western Power Operations Sales Volumes
Three months ended Six months ended
(unaudited) June 30 June 30
(GWh) 2007 2006 2007 2006
----------------------------------------------------------------------------
Supply
Generation 531 438 1,123 1,023
Purchased
Sundance A & B and
Sheerness PPAs 2,877 2,846 6,130 6,237
Other purchases 416 519 865 1,005
------------------------------------------------
3,824 3,803 8,118 8,265
------------------------------------------------
Sales
Contracted 3,017 2,811 6,509 5,975
Spot 807 992 1,609 2,290
------------------------------------------------
3,824 3,803 8,118 8,265
------------------------------------------------
Western Power Operations' operating income of $57 million in second quarter 2007 increased $11 million compared to the $46 million earned in second quarter 2006. This increase was primarily due to increased margins from the Alberta power purchase arrangements (PPA) resulting from a combination of slightly higher realized power prices, increased volumes and lower PPA costs. Average spot market prices in Alberta decreased seven per cent to $50 per MWh in second quarter 2007 compared to the same quarter last year. During second quarter 2007, Western Power Operations reduced its exposure to lower spot market prices by contracting additional volumes and, as a result, sold fewer volumes into the spot market. Recontracting at higher prices also improved overall realized prices in second quarter 2007 compared to the same period in 2006.
Generation volumes of 531 GWh in second quarter 2007 increased 93 GWh compared to second quarter 2006 primarily due to the return to service of the Bear Creek facility in third quarter 2006 and a planned maintenance outage at the MacKay River facility in second quarter 2006.
Western Power Operations 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 Operations would otherwise have to purchase electricity in the open market to fulfill its contractual sales obligations. Approximately 21 per cent of power sales volumes were sold into the spot market in second quarter 2007 compared to 26 per cent in second quarter 2006. To reduce its exposure to spot market prices on uncontracted volumes, as at June 30, 2007, Western Power Operations had fixed-price power sales contracts to sell approximately 5,300 GWh for the remainder of 2007 and 7,400 GWh for 2008.
Western Power Operations' operating income for the six months ended June 30, 2007 increased $26 million to $130 million compared to the same period in 2006. This increase was primarily due to higher overall realized power prices and lower PPA costs.
Eastern Power Operations
Eastern Power Operations Results-at-a-Glance (1)
Three months ended Six months ended
(unaudited) June 30 June 30
(millions of dollars) 2007 2006 2007 2006
----------------------------------------------------------------------------
Revenue
Power 389 174 743 335
Other (2) 64 58 147 175
--------------------------------------------
453 232 890 510
--------------------------------------------
Commodity purchases resold
Power (183) (89) (360) (190)
Other (2) (67) (53) (125) (149)
--------------------------------------------
(250) (142) (485) (339)
--------------------------------------------
Plant operating costs and other (120) (40) (244) (65)
Depreciation (13) (7) (24) (14)
--------------------------------------------
Operating income 70 43 137 92
--------------------------------------------
--------------------------------------------
(1) Eastern Power Operations includes Becancour and Baie-des-Sables
effective September 17, 2006 and November 21, 2006, respectively.
(2) Other includes natural gas.
Eastern Power Operations Sales Volumes (1)
Three months ended Six months ended
(unaudited) June 30 June 30
(GWh) 2007 2006 2007 2006
----------------------------------------------------------------------------
Supply
Generation 2,028 949 4,051 1,654
Purchased 1,562 667 3,088 1,397
--------------------------------------------
3,590 1,616 7,139 3,051
--------------------------------------------
Sales
Contracted 3,437 1,503 6,794 2,886
Spot 153 113 345 165
--------------------------------------------
3,590 1,616 7,139 3,051
--------------------------------------------
--------------------------------------------
(1) Eastern Power Operations includes Becancour and Baie-des Sables
effective September 17, 2006 and November 21, 2006, respectively.
Eastern Power Operations' operating income of $70 million and $137 million for the three and six months ended June 30, 2007, respectively, increased $27 million and $45 million, compared to the same periods in 2006. The increase was primarily due to incremental income earned in 2007 from the startup of the 550 MW Becancour cogeneration plant in September 2006, payments received under the newly designed forward capacity market in New England and margins earned on incremental volumes sold to new customers.
Generation volumes in second quarter 2007 of 2,028 GWh increased 1,079 GWh compared to 949 GWh generated in second quarter 2006 primarily due to the placing into service of the Becancour and Baie-des-Sables facilities.
Eastern Power Operations' power revenues of $389 million increased $215 million in second quarter 2007, compared to second quarter 2006, primarily due to the placing into service of the Becancour facility and increased sales volumes to commercial and industrial customers. Power commodity purchases resold of $183 million and purchased power volumes of 1,562 GWh were significantly higher in second quarter 2007, compared to second quarter 2006, primarily due to the impact of increased purchases to supply increased sales volumes. Plant operating costs and other of $120 million, which includes fuel gas consumed in generation, increased in second quarter 2007 from the prior year primarily as a result of the startup of the Becancour facility.
In second quarter 2007, approximately four per cent of power sales volumes were sold into the spot market compared to approximately seven per cent in second quarter 2006. Eastern Power Operations 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, as at June 30, 2007, Eastern Power Operations had entered into fixed price power sales contracts to sell approximately 7,200 GWh for the remainder of 2007 and 11,000 GWh for 2008, although certain contracted volumes are dependent on customer usage levels.
Power Plant Availability
Weighted Average Power Plant Availability (1)
Three months ended Six months ended
June 30 June 30
(unaudited) 2007 2006 2007 2006
----------------------------------------------------------------------------
Bruce Power 85% 84% 83% 87%
Western Power Operations (2) 89% 74% 94% 82%
Eastern Power Operations (3) 93% 98% 96% 97%
All plants, excluding Bruce
Power 91% 93% 95% 93%
All plants 89% 85% 90% 88%
--------------------------------------------
(1) Plant availability represents the percentage of time in the period that
the plant is available to generate power, whether actually running or
not and is reduced by planned and unplanned outages.
(2) Western Power Operation's plant availability of 74 per cent for the
three months ended June 30, 2006 reflects planned maintenance outages at
the MacKay River, Bear Creek and Carseland cogeneration facilities.
(3) Eastern Operations includes Becancour and Baie-des-Sables effective
September 17, 2006 and November 21, 2006, respectively.
Natural Gas Storage
Natural Gas Storage operating income of $20 million in second quarter 2007 increased $3 million compared to $17 million in second quarter 2006. Natural Gas Storage operating income of $50 million for the six months ended June 30, 2007 increased $11 million compared to $39 million for the same period in 2006. These increases were primarily due to incremental income earned in 2007 from the startup of the Edson facility in December 2006.
TransCanada manages its natural gas storage assets' exposure to seasonal natural gas price spreads by hedging storage capacity with a portfolio of third party storage capacity leases and proprietary natural gas purchases and sales. Earnings from third party storage capacity leases are recognized evenly over the term of the lease. Earnings for proprietary natural gas sales, exclusive of unrealized gains or losses from changes in fair value, are recognized when the natural gas is sold which typically occurs during the winter withdrawal season.
Effective April 1, 2007, TransCanada adopted an accounting policy to record proprietary natural gas storage inventory at its fair value using the one-month forward price for natural gas. Changes in fair value of inventory are included in Revenues.
Back-to-back proprietary transactions are comprised of a forward purchase of natural gas at lower prices to be injected into storage and a simultaneous forward sale of natural gas at higher prices for withdrawal at a later period. By matching purchases and sales volumes, TransCanada locks in a margin effectively eliminating its exposure to the price movements of natural gas. These forward natural gas contracts, which meet the definition of a derivative, provide highly effective economic hedges. However, they do not meet the criteria for hedge accounting due to the Company's active management of these purchases and sales. As a result, these forward purchase and sale contracts are recorded at their fair values based on the forward market prices for the contracted month of delivery. The change in fair value of the purchase and sale contracts is included in Revenues.
Based on normal market price movements, the recording of natural gas storage inventory at its fair value is expected to create partially, but not completely, offsetting impacts to the changes in fair value of the forward contracts. Due to the locked-in margins on these back-to-back proprietary transactions, the net changes in fair value reflected in income at period ends may not be indicative of the operating results of the underlying business. The net change in the fair values of the proprietary natural gas storage inventory and forward contracts included in income in second quarter 2007 was not significant.
General, Administrative and Support Costs
General, administrative and support costs of $39 million and $75 million for the three and six months ended June 30, 2007 increased $4 million and $10 million, respectively, compared to the same periods in 2006. The increases were primarily due to higher business development costs associated with growing the Energy business.
As at June 30, 2007, TransCanada had capitalized $35 million related to the Broadwater liquefied natural gas project.
Corporate
Corporate net expenses for the three months ended June 30, 2007 were $3 million compared to nil for the same period in 2006. The increase in net expenses was primarily due to higher financial charges as a result of financing the ANR and Great Lakes acquisitions. Partially offsetting the increase in net expenses in second quarter 2007 were gains on derivatives used to manage the Company's exposure to foreign exchange rate fluctuations and favourable income tax adjustments of $12 million from changes in Canadian federal income tax legislation. In second quarter 2006, there was a $10-million favourable impact on earnings arising from a reduction in Canadian federal and provincial income tax rates. Excluding the $12 million and $10 million of income tax adjustments from net expenses in second quarter 2007 and 2006, respectively, Corporate's comparable expenses were $15 million and $10 million, respectively.
Net earnings from Corporate for the six months ended June 30, 2007 were $1 million compared to net expenses of $12 million for the same period in 2006. The $13-million increase in earnings for the six months ended June 30, 2007 was primarily due to $27 million of favourable income tax adjustments recorded in the first six months of 2007 as well as gains on derivatives used to manage the Company's exposure to foreign exchange rate fluctuations. Partially offsetting these increases were higher financial charges as a result of the ANR and Great Lakes acquisitions. Excluding the $27-million income tax adjustments from Corporate's net earnings for the six months ended June 30, 2007, and the $10-million income tax adjustments from Corporate's net expenses for the six months ended June 30, 2006 resulted in comparable expenses of $26 million and $22 million for the six months ended June 30, 2007 and 2006, respectively.
Liquidity and Capital Resources
Funds Generated from Operations
Three months ended Six months ended
(unaudited) June 30 June 30
(millions of dollars) 2007 2006 2007 2006
----------------------------------------------------------------------------
Cash Flows
Funds generated from
operations (1) 596 539 1,178 1,056
Decrease/(increase) in
operating working capital 93 (91) 129 (93)
--------------------------------------------
Net cash provided by operations 689 448 1,307 963
--------------------------------------------
--------------------------------------------
(1) For a further discussion on funds generated from operations refer to the
Non-GAAP Measures section in this MD&A.
Net cash provided by operations increased $241 million and $344 million in the second quarter and first six months of 2007, respectively, compared to the same periods in 2006. The increase in net cash provided by operations was primarily due to an increase in funds generated from operations and a decrease in operating working capital. Funds generated from operations were $596 million and $1.2 billion for the three and six months ended June 30, 2007, respectively, compared to $539 million and $1.1 billion for the same periods in 2006. The increase was mainly due to an increase in cash generated through earnings.
TransCanada expects that its ability to generate adequate amounts of cash in the short and long term, when needed, and to maintain financial capacity and flexibility to provide for planned growth remains substantially unchanged since December 31, 2006.
Investing Activities
Acquisitions, net of cash acquired, for the six months ended June 30, 2007 were $4.2 billion (2006 - $358 million) due to the acquisition of ANR and an additional 3.55 per cent interest in Great Lakes for approximately US$3.4 billion, including US$491 million of assumed long-term debt. Acquisitions also include PipeLines LP's 46.45 per cent interest in Great Lakes for approximately US$945 million, including US$209 million of assumed long-term debt. These acquisitions are discussed further in the Acquisitions section of this MD&A.
Acquisitions for each of the three and six months ended June 30, 2006 were $358 million, which related to the purchase of an additional 20 per cent general partnership interest in Northern Border Pipeline Company by PipeLines LP.
For the three and six months ended June 30, 2007, capital expenditures totalled $386 million (2006 - $327 million) and $692 million (2006 - $630 million) and related to the restart and refurbishment of Bruce A Units 1 and 2, the construction of new power plants and capital expenditures in Pipelines.
In the three and six months ended June 30, 2006, disposition of assets, net of current income tax, generated $23 million. The disposition in 2006 related to the sale of TransCanada's 17.5 per cent general partner interest in Northern Border Partners, L.P.
Financing Activities
TransCanada retired $470 million and $795 million of long-term debt in the three and six months ended June 30, 2007, respectively ($208 million and $348 million for the three and six months ended June 30, 2006, respectively) and issued $1.2 billion and $2.5 billion of long-term debt and junior subordinated notes for the three and six months ended June 30, 2007, respectively ($372 million and $1.3 billion for the three and six months ended June 30, 2006, respectively). TransCanada's notes payable decreased $804 million and increased $261 million in the three and six months ended June 30, 2007, respectively, compared to an increase of $180 million and a decrease of $453 million for the same periods in 2006, respectively.
On July 5, 2007, TransCanada redeemed, at par, all of the outstanding US$460 million 8.25 per cent Preferred Securities due 2047.
In second quarter 2007, TransCanada issued 1.3 million common shares under its Dividend Reinvestment Program, resulting in proceeds of approximately $51 million.
In April 2007, TransCanada issued US$1.0 billion of Junior Subordinated Notes ("Notes") maturing in 2067 and bearing interest of 6.35 per cent until May 15, 2017 at which time the interest on the Notes will convert to a floating rate reset quarterly to the three-month London Interbank Offered Rate (LIBOR) plus 221 basis points. The Notes' effective interest rate at June 30, 2007 was 6.51 per cent. TransCanada has the option to defer payment of interest for one or more periods of up to ten years without giving rise to an event of default and without permitting acceleration of payment under the terms of the Notes. If this were to occur, the Company would be prohibited from paying dividends during the deferral period. The Notes are subordinated in right of payment to existing and future senior indebtedness and are effectively subordinated to all indebtedness and obligations of TCPL. The Notes are callable at TransCanada's option at any time on or after May 15, 2017 at 100 per cent of the principal amount of the Notes plus accrued and unpaid interest to the date of redemption. Upon the occurrence of certain events, the Notes are callable earlier at TransCanada's option, in whole or in part, at an amount equal to the greater of 100 per cent of the principal amount of the Notes plus accrued and unpaid interest to the date of redemption or at an amount determined by formula in accordance with the terms of the Notes.
In April 2007, Northern Border established a US$250-million five-year bank facility. A portion of the bank facility was drawn to refinance US$150 million of senior notes that matured on May 1, 2007, with the balance available to fund Northern Border's ongoing operations.
In March 2007, the Company filed debt shelf prospectuses in Canada and the U.S. qualifying for issuance of $1.5 billion of medium-term notes and US$1.5 billion of debt securities, respectively. At June 30, 2007, the Company had issued no medium-term notes and US$1.0 billion of debt securities under these prospectuses.
In February 2007, the Company executed an agreement for a US$2.2-billion, committed, unsecured, one-year bridge loan facility with a floating interest rate based on the one-month LIBOR plus 25 basis points. The Company utilized $1.5 billion and US$700 million from this facility to partially finance the ANR and Great Lakes acquisitions. At June 30, 2007, the Company had an outstanding balance of US$488 million on this facility. The undrawn balance of this facility has been cancelled and is no longer available to the Company.
In February 2007, the Company established a US$1.0-billion committed, unsecured credit facility. A floating interest rate based on the three-month LIBOR plus 22.5 basis points is charged on the balance outstanding and a facility fee of 7.5 basis points is charged on the entire facility. The Company utilized US$1.0 billion from this facility and an additional US$100 million from an existing demand line to partially finance the ANR acquisition as well as its additional investment in PipeLines LP. At June 30, 2007, the Company had an outstanding balance of US$700 million on the credit facility and had repaid the demand line.
In February 2007, PipeLines LP increased the size of its syndicated revolving credit and term loan facility in connection with its Great Lakes acquisition. The amount available under the facility increased from US$410 million to US$950 million, consisting of a US$700 million senior term loan and a US$250 million senior revolving credit facility, with US$194 million of the senior term loan amount available being terminated upon closing of the Great Lakes acquisition. At June 30, 2007, US$506 million of the senior term loan and US$10 million of the senior revolving credit facility remained outstanding. A floating interest rate based on the three-month LIBOR plus 55 basis points is charged on the senior term loan and a floating interest rate based on the one-month LIBOR plus 35 basis points is charged on the senior revolving credit facility. A facility fee of 10 basis points is charged on the US$250 million senior revolving credit facility. The weighted average interest rate at June 30, 2007 was 5.94 per cent.
Other than the above-mentioned items and those discussed in TransCanada's 2006 Annual Report and First Quarter 2007 Quarterly Report to Shareholders, there have been no material changes to TransCanada's financing activities from December 31, 2006 to June 30, 2007.
Dividends
On July 26, 2007, TransCanada's Board of Directors declared a quarterly dividend of $0.34 per share for the quarter ending September 30, 2007 on the Company's outstanding common shares. This is the 176th consecutive quarterly dividend paid by TransCanada and its subsidiary on the common shares. It is payable on October 31, 2007 to shareholders of record at the close of business on September 28, 2007.
Directors also approved the issuance of common shares from treasury at a two per cent discount under TransCanada's Dividend Reinvestment and Share Purchase Plan for the dividend payable October 31, 2007. The Company reserves the right to alter the discount or return to purchasing shares on the open market at any time.
Changes in Accounting Policies
The Company's Changes in Accounting Policies have not changed materially from those described in TransCanada's 2006 Annual Report and First Quarter 2007 Quarterly Report to Shareholders MD&A except for the following.
Proprietary Natural Gas Storage Inventories and Revenue Recognition
The new Canadian Institute of Chartered Accountants (CICA) Handbook accounting requirements for Section 3031 "Inventories" will become effective January 1, 2008. However, the Company has chosen to adopt this standard as of April 1, 2007. Adjustments to second quarter 2007 consolidated financial statements have been made in accordance with the transitional provisions for this new standard.
Beginning April 1, 2007, TransCanada's proprietary natural gas storage inventory will be valued at its fair value, as measured by the one-month forward price for natural gas. In order to record inventory at fair value, TransCanada has designated its natural gas storage business as a "broker/trader business" that purchases and sells natural gas on a back-to-back basis. The Company did not have any proprietary natural gas inventory prior to April 1, 2007. The Company records its proprietary natural gas storage results in Revenues net of Commodity Purchases Resold.
At June 30, 2007, $81 million of proprietary natural gas storage inventory was included in Inventories on the Consolidated Balance Sheet. All changes in the fair value of the proprietary natural gas storage inventory will be recorded in Inventories and Revenues. During the three months ended June 30, 2007, unrealized pre-tax losses related to the change in fair value of the proprietary natural gas storage inventory were $23 million, which was essentially offset by the change in fair value of the forward proprietary natural gas storage purchase and sale contracts.
Contractual Obligations
As a result of TransCanada's acquisition of ANR, Pipelines' future purchase obligations, primarily consisting of operating lease and purchase obligations, increased $110 million at June 30, 2007, compared to December 31, 2006.
In July 2007, the Company entered into contracts to purchase pipe and supplies totaling approximately $300 million for the Keystone oil pipeline and other Pipeline projects.
Other than the above-mentioned commitments and future debt and interest payments on debt utilized to acquire ANR, there have been no material changes to TransCanada's contractual obligations from December 31, 2006 to June 30, 2007, 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 2006 Annual Report.
Financial Instruments and Risk Management
Energy Price, Interest Rate and Foreign Exchange Rate Risk Management
The Company enters into various contracts to mitigate its exposure to fluctuations in interest rates, foreign exchange rates and commodity prices. The contracts generally consist of the following.
- Forwards and futures contracts - contractual agreements to buy or sell a specific financial instrument or commodity at a specified price and date in the future. The Company enters into foreign exchange and commodity forwards and futures to mitigate volatility in changes in foreign exchange rates and power and gas prices, respectively.
- Swaps - contractual agreements between two parties to exchange streams of payments over time according to specified terms. The Company enters into interest rate, cross-currency and commodity swaps to mitigate changes in interest rates, foreign exchange rates and commodity prices, respectively.
- Options - contractual agreements to convey the right, but not the obligation, for the purchaser either to buy or sell a specific amount of a financial instrument or commodity at a fixed price, either at a fixed date or at any time within a specified period. The Company enters into option agreements to mitigate changes in interest rates, foreign exchange rates and commodity prices.
- Heat rate contracts - contracts for the sale or purchase of power that are priced based on a natural gas index.
Energy Price Risk
The Company is exposed to energy price movements as part of its normal business operations, particularly in relation to the prices of electricity and natural gas. The primary risk is that market prices for commodities will move adversely between the time that purchase and/or sales prices are fixed, potentially reducing expected margins.
To manage exposure to price risk, subject to the Company's overall risk management policies and procedures, the Company commits a significant portion of its supply to medium- to long-term sales contracts while reserving an amount of unsold supply to maintain flexibility in the overall management of its asset portfolio. The types of instruments used include forwards and futures contracts, swaps, options, and heat rate contracts.
TransCanada manages its exposure to seasonal gas price spreads in its natural gas storage business, by hedging storage capacity with a portfolio of third party storage capacity leases and back-to-back proprietary natural gas purchases and sales. By matching purchases and sales volumes, TransCanada locks in a margin and effectively eliminates its exposure to the price movements of natural gas.
The Company continually assesses its power contracts and derivative instruments used to manage energy price risk. Contracts, with the exception of leases, have been assessed to determine whether they meet the definition of a derivative. Certain commodity purchase and sale contracts are derivatives but are not within the scope of the Canadian Institute of Chartered Accountants Handbook Section 3855, as they were entered into and continue to be held for the purpose of receipt or delivery in accordance with the Company's expected purchase, sale or usage requirements ("normal purchases and sales exception"), are considered to be executory contracts or meet other exemption criteria listed in Section 3855.
Interest Rate Risk
The Company has fixed interest rate long-term debt, which subjects the Company to interest rate price risk, and has floating interest rate long-term debt, which subjects the Company to interest rate cash flow risk. To manage its exposure to these risks, the Company uses a combination of interest-rate swaps, forwards and options.
Investments in Foreign Operations
The Company hedges its net investment in self-sustaining foreign operations with U.S. dollar-denominated debt, cross-currency swaps, forward exchange contracts and options. At June 30, 2007, the Company had designated U.S. dollar-denominated debt with a carrying value of $4,104 million (US$3,859 million) and a fair value of $4,178 million (US$3,929 million) as a portion of this hedge and swaps, forwards and options with a fair value of $75 million (US$70 million) as net investment hedges.
Net Investment in Foreign Operations
Asset/(Liability)
(millions of dollars) June 30, 2007 December 31, 2006
----------------------------------------------------------------------------
Notional or Notional or
Fair Principal Fair Principal
Value(1) Amount Value(1) Amount
----------------------------------------------
Derivative financial
Instruments in hedging
relationships
U.S. dollar cross-currency
swaps (maturing 2007 to 2013) 75 U.S. 350 58 U.S. 400
U.S. dollar forward foreign
exchange contracts
(maturing 2007) - U.S. 75 (7) U.S. 390
U.S. dollar options
(maturing 2007) - U.S. 50 (6) U.S. 500
----------------------------------------------
75 U.S. 475 45 U.S. 1,290
----------------------------------------------
----------------------------------------------
(1) Fair values are equal to carrying values.
Fair Values
Fair values of financial instruments are determined by reference to quoted bid or asking price, as appropriate, in active markets. In the absence of an active market, the Company determines fair value by using valuation techniques that refer to observable market data or estimated market prices. These include comparisons with similar instruments where market observable prices exist, option pricing models and other valuation techniques commonly used by market participants. Fair values determined using valuation models require the use of assumptions concerning the amount and timing of estimated future cash flows and discount rates. In determining those assumptions, the Company looks primarily to external readily observable market input factors such as interest rate yield curves, currency rates, and price and rate volatilities as applicable.
Unrealized Gains and Losses
At June 30, 2007, there were unrealized gains from unsettled derivative financial instruments of $147 million (December 31, 2006 - $41 million) included in Other Current Assets and $120 million (December 31, 2006 - $39 million) included in Other Assets. At June 30, 2007, there were unrealized losses from unsettled derivative financial instruments of $220 million (December 31, 2006 - $144 million) included in Accounts Payable and $253 million (December 31, 2006 - $158 million) included in Deferred Amounts. At June 30, 2007, there were unrealized losses from the fair value adjustments of proprietary natural gas storage inventory of $23 million (December 31, 2006 - nil) included in Inventories.
Risk and Risk Management Related to Environmental Regulations
On July 1, 2007, the Government of Alberta's regulations to reduce greenhouse gas emissions (GHG) by 12 per cent of average 2003 to 2005 levels came into effect for large industrial emitters in Alberta. Under the new regulations, entities covered under this legislation will have until March 31, 2008 to provide compliance reports stating how their facilities have met their reduction targets. TransCanada anticipates that costs associated with GHG reduction targets impacting the Alberta System are to be recovered through future tolls paid by customers on the Alberta System. Recovery of GHG compliance costs related to the Company's power facilities in Alberta is ultimately dependent upon market prices for electricity. These GHG changes may have an impact on these market prices.
On April 26, 2007, the Canadian government released its Regulatory Framework for Air Emissions that includes "mandatory and enforceable reductions in emissions of greenhouse gases and air pollutants". Under this framework, industrial emitters will be required to reduce GHG intensities in 2010 by 18 percent from 2006 levels and this reduction target will increase by two per cent annually until 2020. However, many significant implementation and compliance elements of this framework are still evolving.
TransCanada continues to be engaged in policy discussions at all levels with provincial and federal governments. There are several processes taking place, including assessment of significant infrastructure requirements, further development of broad policy elements (for example, domestic offset systems and management of the federal technology fund) and submission of third party audited compliance reports. TransCanada is following developments in each of these processes. As these Alberta and Canadian federal government initiatives have the potential to significantly impact the energy industry, the Company continues to assess and monitor the implications to TransCanada's businesses.
Other Risks
Additional risks faced by the Company are discussed in the MD&A in TransCanada's 2006 Annual Report. TransCanada's market, financial and counterparty risks remain substantially unchanged since December 31, 2006.
Controls and Procedures
As of June 30, 2007, an evaluation was carried out under the supervision of, and with the participation of, management including the President and Chief Executive Officer and Chief Financial Officer, of the effectiveness of TransCanada's disclosure controls and procedures as defined under the rules adopted by the Securities Exchange Commission (SEC). Based on that evaluation, the President and Chief Executive Officer, and Chief Financial Officer concluded that the design and operation of TransCanada's disclosure controls and procedures were effective as at June 30, 2007.
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. With respect to the acquisitions in 2007, the Company has not yet determined whether or not to apply the acquisitions exemption allowed under the Sarbanes-Oxley Act of 2002.
Significant Accounting Policies and Critical Accounting Estimates
Since determining the value of certain assets, liabilities, revenues and expenses is dependent upon future events, the preparation of the Company's consolidated financial statements requires the use of estimates and assumptions, which have been made using careful judgment.
TransCanada's significant accounting policies and critical accounting estimates are the use of regulatory accounting for the Company's rate-regulated operations and the policies the Company adopts to account for derivatives and depreciation and amortization expense. Effective January 1, 2007, the Company adopted the new accounting standards for financial instruments and hedges. For further information on the Company's accounting policies and estimates refer to the MD&A in TransCanada's 2006 Annual Report and First Quarter 2007 Quarterly Report to Shareholders.
Outlook
Excluding the $31 million of income tax adjustments recorded in 2007 and the positive impact of the Settlement on the Canadian Mainline, the Company's outlook is relatively unchanged since the disclosure in TransCanada's 2006 Annual Report. For further information on outlook, refer to the MD&A in TransCanada's 2006 Annual Report.
TransCanada Corporation's issuer rating assigned by Moody's Investors Service (Moody's) is A3 with a stable outlook. TCPL's senior unsecured debt is rated A, with a stable outlook, by DBRS; A2, with a stable outlook, by Moody's; and A-, with a stable outlook, by Standard & Poor's.
Other Recent Developments
Pipelines
Canadian Mainline
In February 2007, TransCanada reached a five-year tolls settlement (the Settlement) with interested stakeholders for the years 2007 to 2011 on the Canadian Mainline. In March 2007, TransCanada applied to the NEB for approval of the Settlement. In May 2007, the NEB approved the application as filed, including TransCanada's request that interim tolls be made final for 2007. The terms of the Settlement are effective January 1, 2007 to December 31, 2011.
As part of the Settlement, TransCanada and its stakeholders agreed that the cost of capital will reflect an ROE as determined by the NEB's return on equity formula, on a deemed common equity ratio of 40 per cent, an increase from 36 per cent. The remaining capital structure will consist of senior debt following the agreed upon redemption on July 5, 2007 of the US$460 million 8.25 per cent Preferred Securities that underpinned the Canadian Mainline's investment base. The redemption crystallized a foreign exchange gain that will flow through to the Canadian Mainline's customers.
The Settlement also established the Canadian Mainline's fixed OM&A costs for each year of the Settlement. Any variance between actual OM&A costs and those agreed to in the Settlement will accrue to TransCanada from 2007 to 2009. Variances in OM&A costs will be shared equally between TransCanada and its customers in 2010 and 2011. All other cost elements of the revenue requirement will be treated on a flow through basis.
The Settlement also allows for performance-based incentive arrangements that will provide mutual benefits to both TransCanada and its customers.
Alberta System Expansion
In June 2007, TransCanada made an application to the Alberta Energy and Utilities Board for approval to construct approximately $300 million of new facilities on the Alberta System to initially serve the growing demand for natural gas in the Fort McMurray region of Alberta.
ANR Natural Gas Storage Expansion
In second quarter 2007, ANR received regulatory approval to proceed with a 14 Bcf natural gas storage expansion project in Michigan. This capacity is fully contracted with an expected in service date of April 1, 2008 for injections and November 1, 2008 for withdrawals. This project is in addition to a natural gas storage enhancement and expansion program that will increase Michigan capacity available for sale by 13 Bcf. This program was also fully subscribed with injections commencing in April 2007. The expected capital cost of these projects is US$125 million.
North Baja Pipeline Expansion
TransCanada's North Baja pipeline has filed an application with the FERC to expand and modify its existing system to facilitate the importation of regassified liquefied natural gas (LNG) from Mexico into the California and Arizona markets. The FERC has issued a preliminary determination approving all aspects of North Baja's proposal other than those related to environmental issues, which will be the subject of a future order.
An Environmental Impact Report (EIR) and an Environmental Impact Statement (EIS) have been prepared jointly by the California State Land Commission and the FERC, respectively, to assess the expansion's effect on the environment. The final EIR and EIS were completed in June 2007 and the California State Lands Commission certified the EIR for California's use on July 13, 2007. TransCanada expects that the FERC will issue its final order authorizing the project during third quarter 2007.
Cacouna Energy Facilities
In July 2007, the NEB approved TransCanada's application for a new LNG receipt point at Gros Cacouna, Quebec, on the integrated Canadian Mainline, and that tolls for service from that point be calculated on a rolled-in basis. The effective date for these approvals is when the facilities required to connect the Gros Cacouna receipt point are approved and placed in service. TransCanada and TQM are preparing applications to the NEB for approval to construct those facilities required to connect the LNG terminal at Gros Cacouna to the existing TQM and Canadian Mainline infrastructure.
Mackenzie Gas Pipeline Project
In second quarter 2007, the MGP filed additional project update and tolls and tariff information for the project with the NEB and a Joint Review Panel (JRP) resulting from increased capital cost estimates for the project. JRP hearings are scheduled for the third and fourth quarters of 2007 and NEB hearings, if required, are scheduled for mid-October 2007. TransCanada and its co-venturers on the MGP continue to pursue the development of the project, focusing on the regulatory process and discussions with the Canadian federal government on fiscal framework.
Alaska Highway Pipeline Project
TransCanada is continuing its discussions with the Alaska North Slope producers. The Government of Alaska Legislature approved the Alaska Gasline Inducement Act (AGIA) in May 2007. The Government of Alaska issued a Request for Applications on July 2, 2007, requesting applications from pipeline developers, under the AGIA, by October 1, 2007.
Keystone Oil Pipeline
Additional contracts for 155,000 barrels per day have been secured for the proposed Keystone oil pipeline through an Open Season to transport oil from Hardisty, Alberta to Cushing, Oklahoma. The contracts will have a duration averaging 16 years. The Open Season supports an expansion to 590,000 barrels per day and an extension of the pipeline to Cushing. TransCanada has now secured long term contracts for a total of 495,000 barrels per day with an average duration of 18 years.
An NEB public hearing concluded on June 21, 2007 to determine if the NEB will approve TransCanada's application to construct and operate Keystone's facilities in Canada. A decision on this application is expected in fourth quarter 2007. TransCanada has also submitted applications for U.S. regulatory approvals at federal and state levels. Provided that regulatory approvals are received, construction of the Keystone oil pipeline is expected to begin in 2008 and to be in service in fourth quarter 2009.
Energy
Cacouna Energy
On June 22, 2007, the Cacouna Energy LNG project received federal approvals pursuant to the Canadian Environmental Assessment Act. This approval is required for the issuance of permits under the Fisheries Act (Canada) and Navigable Waters Protection Act (Canada), which will outline detailed conditions required for construction. Concurrently, the Government of Quebec granted a decree approving the Cacouna regassification terminal in Quebec. The conditions are binding on the Quebec Minister of Environment and subsequent Certificates of Authorization required for construction.
Share Information
As at June 30, 2007, TransCanada had 536,326,020 issued and outstanding common shares. In addition, there were 9,247,805 outstanding options to purchase common shares, of which 6,727,050 were exercisable as at June 30, 2007.
Selected Quarterly Consolidated Financial Data(1)
(unaudited)
(millions of dollars except 2007 2006
per share amounts) Second First Fourth Third Second First
------------------------------------------ --------------------------------
Revenues 2,212 2,249 2,091 1,850 1,685 1,894
Net Income
Continuing operations 257 265 269 293 244 245
Discontinued operations - - - - - 28
------------------------------------------ --------------------------------
257 265 269 293 244 273
------------------------------------------ --------------------------------
------------------------------------------ --------------------------------
Share Statistics
Net income per
share - Basic
Continuing operations $ 0.48 $ 0.52 $ 0.55 $ 0.60 $ 0.50 $ 0.50
Discontinued operations - - - - - 0.06
----------------------------------------------------------------------------
$ 0.48 $ 0.52 $ 0.55 $ 0.60 $ 0.50 $ 0.56
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net income per
share - Diluted
Continuing operations $ 0.48 $ 0.52 $ 0.54 $ 0.60 $ 0.50 $ 0.50
Discontinued operations - - - - - 0.06
------------------------------------------ --------------------------------
$ 0.48 $ 0.52 $ 0.54 $ 0.60 $ 0.50 $ 0.56
------------------------------------------ --------------------------------
------------------------------------------ --------------------------------
Dividend declared per
common share $ 0.34 $ 0.34 $ 0.32 $ 0.32 $ 0.32 $ 0.32
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(unaudited) 2005
(millions of dollars except per share amounts) Fourth Third
---------------------------------------------------------- ----------------
Revenues 1,771 1,494
Net Income
Continuing operations 350 427
Discontinued operations - -
---------------------------------------------------------- ----------------
350 427
---------------------------------------------------------- ----------------
---------------------------------------------------------- ----------------
Share Statistics
Net income per share - Basic
Continuing operations $ 0.72 $ 0.88
Discontinued operations - -
---------------------------------------------------------- ----------------
$ 0.72 $ 0.88
---------------------------------------------------------- ----------------
---------------------------------------------------------- ----------------
Net income per share - Diluted
Continuing operations $ 0.71 $ 0.87
Discontinued operations - -
---------------------------------------------------------- ----------------
$ 0.71 $ 0.87
---------------------------------------------------------- ----------------
---------------------------------------------------------- ----------------
Dividend declared per common share $0.305 $0.305
---------------------------------------------------------- ----------------
---------------------------------------------------------- ----------------
(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 natural gas storage facilities, annual revenues and net earnings fluctuate over the long term based on regulators' decisions and negotiated settlements with shippers. Generally, quarter-over-quarter revenues and net earnings 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 on U.S. pipelines and items 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 earnings are affected by seasonal weather conditions, customer demand, market prices, planned and unplanned plant outages as well as items outside of the normal course of operations.
Significant items which impacted the last eight quarters' net earnings are as follows.
- In third quarter 2005, net earnings included a $193 million after-tax gain related to the sale of the Company's ownership interest in TransCanada Power, LP. In addition, Bruce Power's income from equity investments increased from prior quarters due to higher realized power prices and slightly higher generation volumes.
- In fourth quarter 2005, net earnings included a $115-million after-tax gain on the sale of P.T. Paiton Energy Company. In addition, Bruce A was formed and Bruce Power's results were proportionately consolidated, effective October 31, 2005.
- In first quarter 2006, net earnings included an $18-million after-tax bankruptcy claim settlement from a former shipper on the Gas Transmission Northwest System. In addition, Energy's net earnings included contributions from the December 31, 2005 acquisition of the 756 MW Sheerness PPA.
- In second quarter 2006, net earnings included $33 million of future income tax benefits ($23 million in Energy and $10 million in Corporate) as a result of reductions in Canadian federal and provincial corporate income tax rates. Pipelines' net earnings included a $13-million after-tax gain related to the sale of the Company's general partner interest in Northern Border Partners, L.P.
- In third quarter 2006, net earnings included an income tax benefit of $50 million on the resolution of certain income tax matters with taxation authorities and changes in estimates. Energy's net earnings included earnings from Becancour, which came in service September 17, 2006.
- In fourth quarter 2006, net earnings included $12 million related to income tax refunds and related interest.
- In first quarter 2007, net earnings included $15 million related to positive income tax adjustments. In addition, Pipelines' net earnings included contributions from the February 22, 2007 acquisition of ANR and additional interests in Great Lakes.
- In second quarter 2007, net earnings included $16 million ($12 million in Corporate and $4 million in Energy) related to positive income tax adjustments resulting from changes in Canadian federal income tax legislation. Pipeline's net earnings increased as a result of a settlement reached on the Canadian Mainline, which was approved by the NEB in May 2007.
Consolidated Income
Three months Six months
ended ended
(unaudited) June 30 June 30
(millions of dollars except per share amounts) 2007 2006 2007 2006
---------------------------------------------------- ------- ------- -------
Revenues 2,212 1,685 4,461 3,579
Operating Expenses
Plant operating costs and other 761 566 1,493 1,103
Commodity purchases resold 527 337 1,103 842
Depreciation 300 266 590 523
------- ------- ------- -------
1,588 1,169 3,186 2,468
------- ------- ------- -------
624 516 1,275 1,111
------- ------- ------- -------
Other Expenses/(Income)
Financial charges 264 207 501 409
Financial charges of joint ventures 19 24 40 45
Income from equity investments (5) (6) (11) (24)
Interest income and other (43) (15) (68) (64)
Gain on sale of Northern Border Partners,
L.P. interest - (23) - (23)
------- ------- ------- -------
235 187 462 343
------- ------- ------- -------
Income from Continuing Operations before
Income Taxes and Non-Controlling Interests 389 329 813 768
Income Taxes
Current 96 37 264 247
Future 16 37 (21) (4)
------- ------- ------- -------
112 74 243 243
------- ------- ------- -------
Non-Controlling Interests
Preferred share dividends of subsidiary 5 5 11 11
Non-controlling interest in PipeLines LP 14 8 31 21
Other 1 (2) 6 4
------- ------- ------- -------
20 11 48 36
------- ------- ------- -------
Net Income from Continuing Operations 257 244 522 489
Net Income from Discontinued Operations - - - 28
------- ------- ------- -------
Net Income 257 244 522 517
------- ------- ------- -------
------- ------- ------- -------
Net Income Per Share
Continuing operations $0.48 $0.50 $1.00 $1.00
Discontinued operations - - - 0.06
------- ------- ------- -------
Basic and Diluted $0.48 $0.50 $1.00 $1.06
------- ------- ------- -------
Average Shares Outstanding - Basic
(millions) 536 488 522 488
------- ------- ------- -------
------- ------- ------- -------
Average Shares Outstanding - Diluted
(millions) 538 490 525 490
------- ------- ------- -------
------- ------- ------- -------
See accompanying notes to the consolidated financial statements.
Consolidated Cash Flows
Three months Six months
ended ended
(unaudited) June 30 June 30
(millions of dollars) 2007 2006 2007 2006
---------------------------------------------------- ------- ------- -------
Cash Generated From Operations
Net income 257 244 522 517
Depreciation 300 266 590 523
Gain on sale of Northern Border Partners,
L.P. interest, net of current income tax - (11) - (11)
Income from equity investments lower
than/(in excess of) distributions received 1 (3) (5) (7)
Future income taxes 16 37 (21) (4)
Non-controlling interests 20 11 48 36
Funding of employee future benefits lower
than/(in excess of) expense 3 (13) 15 (15)
Other (1) 8 29 17
------- ------- ------- -------
596 539 1,178 1,056
Decrease/(increase) in operating working
capital 93 (91) 129 (93)
------- ------- ------- -------
Net cash provided by operations 689 448 1,307 963
------- ------- ------- -------
Investing Activities
Capital expenditures (386) (327) (692) (630)
Acquisitions, net of cash acquired (4) (358) (4,224) (358)
Disposition of assets, net of current income
taxes - 23 - 23
Deferred amounts and other (5) (7) (111) (16)
------- ------- ------- -------
Net cash used in investing activities (395) (669) (5,027) (981)
------- ------- ------- -------
Financing Activities
Dividends on common shares (182) (156) (338) (305)
Distributions paid to non-controlling
interests (29) (15) (45) (31)
Notes payable (repaid)/issued, net (804) 180 261 (453)
Long-term debt issued 52 372 1,414 1,250
Reduction of long-term debt (470) (208) (795) (348)
Long-term debt of joint ventures issued 98 22 110 24
Reduction of long-term debt of joint
ventures (107) (15) (119) (21)
Junior subordinated notes issued 1,107 - 1,107 -
Partnership units of subsidiary issued - - 348 -
Common shares issued 58 5 1,748 13
------- ------- ------- -------
Net cash (used in)/provided by financing
activities (277) 185 3,691 129
------- ------- ------- -------
Effect of Foreign Exchange Rate Changes on
Cash and Short-Term Investments (27) (11) (30) (9)
------- ------- ------- -------
------- ------- ------- -------
(Decrease)/Increase in Cash and Short-Term
Investments (10) (47) (59) 102
Cash and Short-Term Investments
Beginning of period 350 361 399 212
------- ------- ------- -------
Cash and Short-Term Investments
End of period 340 314 340 314
------- ------- ------- -------
------- ------- ------- -------
Supplementary Cash Flow Information
Income taxes paid 125 151 212 368
Interest paid 269 224 542 434
------- ------- ------- -------
------- ------- ------- -------
See accompanying notes to the consolidated financial statements.
Consolidated Balance Sheet
(unaudited) June 30, December 31,
(millions of dollars) 2007 2006
------------------------------------------------------------- --------------
ASSETS
Current Assets
Cash and short-term investments 340 399
Accounts receivable 983 1,004
Inventories 466 392
Other 187 297
-------------- --------------
1,976 2,092
Long-Term Investments 69 71
Plant, Property and Equipment 23,700 21,487
Goodwill 2,682 281
Other Assets 1,895 1,978
-------------- --------------
30,322 25,909
-------------- --------------
-------------- --------------
------------------------------------------------------------- --------------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Notes payable 728 467
Accounts payable 1,616 1,500
Accrued interest 265 264
Current portion of long-term debt 759 616
Current portion of long-term debt of joint
ventures 32 142
-------------- --------------
3,400 2,989
Deferred Amounts 1,143 1,029
Future Income Taxes 1,186 876
Long-Term Debt 11,766 10,887
Long-Term Debt of Joint Ventures 913 1,136
Junior Subordinated Notes 1,050 -
Preferred Securities 489 536
-------------- --------------
19,947 17,453
-------------- --------------
Non-Controlling Interests
Preferred shares of subsidiary 389 389
Non-controlling interest in PipeLines LP 574 287
Other 72 79
-------------- --------------
1,035 755
-------------- --------------
Shareholders' Equity
Common shares 6,542 4,794
-------------- --------------
Contributed surplus 275 273
-------------- --------------
Retained earnings 2,892 2,724
Accumulated other comprehensive loss (369) (90)
-------------- --------------
2,523 2,634
-------------- --------------
9,340 7,701
-------------- --------------
30,322 25,909
-------------- --------------
-------------- --------------
See accompanying notes to the consolidated financial statements.
Consolidated Comprehensive Income
Three months Six months
ended ended
(unaudited) June 30 June 30
(millions of dollars) 2007 2006 2007 2006
---------------------------------------------------- ------- ------- -------
Net income 257 244 522 517
------ ------- ------- -------
Other comprehensive loss, net of tax
Change in foreign currency translation
gains and losses on investments in foreign
operations(1) (184) (29) (221) (30)
Change in gains and losses on hedges of
investments in foreign operations(2) 46 27 55 24
Change in gains and losses on derivative
instruments designated as cash flow hedges(3) (36) - (37) -
Reclassification to net income of gains and
losses on derivative instruments designated
as cash flow hedges pertaining to prior
periods(4) 23 - 20 -
---------------------------------------------------- ------- ------- -------
Other comprehensive loss for the period (151) (2) (183) (6)
---------------------------------------------------- ------- ------- -------
Comprehensive income for the period 106 242 339 511
---------------------------------------------------- ------- ------- -------
---------------------------------------------------- ------- ------- -------
(1) Net of tax expense of $51 million and $56 million for the three and six
months ended June 30, 2007 (2006 - $23 million and $22 million expense,
respectively).
(2) Net of tax expense of $23 million and $28 million for the three and six
months ended June 30, 2007 (2006 - $14 million and $12 million expense,
respectively).
(3) Net of tax recovery of $15 million and $10 million for the three and six
months ended June 30, 2007.
(4) Net of tax expense of $7 million and $5 million for the three and six
months ended June 30, 2007.
See accompanying notes to the consolidated financial statements.
Consolidated Shareholders' Equity
Six months ended June 30
(unaudited)
(millions of dollars) 2007 2006
------------------------------------------------------------- --------------
Common Shares
Balance at beginning of period 4,794 4,755
Proceeds from shares issued under public offering(1) 1,683 -
Proceeds from shares issued under dividend
reinvestment plan 51 -
Proceeds from shares issued on exercise of stock
options 14 13
-------------- --------------
Balance at end of period 6,542 4,768
-------------- --------------
Contributed Surplus
Balance at beginning of period 273 272
Issuance of stock options 2 1
-------------- --------------
Balance at end of period 275 273
-------------- --------------
Retained Earnings
Balance at beginning of period 2,724 2,269
Transition adjustment resulting from adopting new
financial instruments accounting standards 4 -
Net income 522 517
Common share dividends (358) (312)
-------------- --------------
Balance at end of period 2,892 2,474
-------------- --------------
Accumulated Other Comprehensive Loss,
net of income taxes
Balance at beginning of period (90) (90)
Transition adjustment resulting from adopting new
financial instruments accounting standards (96) -
Other comprehensive loss (183) (6)
-------------- --------------
Balance at end of period (369) (96)
-------------- --------------
Total Shareholders' Equity 9,340 7,419
-------------- --------------
-------------- --------------
(1) Net of underwriting commissions and future income taxes.
See accompanying notes to the consolidated financial statements.
Accumulated Other Comprehensive Loss
Currency
(unaudited) Translation Cash Flow
(millions of dollars) Adjustment Hedges Total
---------------------------------------------------------- ---------- ------
Balance at December 31, 2006 (90) - (90)
Transition adjustment resulting from adopting
new financial instruments standards - (96) (96)
Change in foreign currency translation gains and
losses on investments in foreign operations(1) (221) - (221)
Change in gains and losses on hedge of
investments in foreign operations(2) 55 - 55
Change in gains and losses on derivative
instruments designated as cash flow hedges(3) - (37) (37)
Reclassification to net income of gains and
losses on derivative instruments designated as
cash flow hedges pertaining to prior periods(4)(5) - 20 20
------------ ---------- ------
Balance at June 30, 2007 (256) (113) (369)
------------ ---------- ------
------------ ---------- ------
---------------------------------------------------------- ---------- ------
Balance at December 31, 2005 (90) - (90)
Change in foreign currency translation gains and
losses on investments in foreign operations(1) (30) - (30)
Change in gains and losses on hedge of
investments in foreign operations(2) 24 - 24
------------ ---------- ------
Balance at June 30, 2006 (96) - (96)
------------ ---------- ------
------------ ---------- ------
(1) Net of tax expense of $56 million for the six months ended June 30, 2007
(2006 - $22 million expense).
(2) Net of tax expense of $28 million for the six months ended June 30, 2007
(2006 - $12 million expense).
(3) Net of tax recovery of $10 million for the six months ended June 30,
2007.
(4) Net of tax expense of $5 million for the six months ended June 30, 2007.
(5) During the next 12 months, the Company expects to reclassify to net
income an estimated $128 million ($88 million after tax) of net losses
reported in accumulated other comprehensive income for cash flow hedges.
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, 2006, except for the changes noted below. 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 2006 audited consolidated financial statements included in TransCanada's 2006 Annual Report. Amounts are stated in Canadian dollars unless otherwise indicated. Certain comparative figures have been reclassified to conform with current period's presentation.
In Pipelines, which consists primarily of the Company's investments in regulated pipelines and natural gas storage facilities, annual revenues and net earnings fluctuate over the long term based on regulators' decisions and negotiated settlements with shippers. Generally, quarter-over-quarter revenues and net earnings 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 on U.S. pipelines and items 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 earnings are affected by seasonal weather conditions, customer demand, market prices, planned and unplanned plant outages as well as items outside of the normal course of operations.
Since a determination of the value of many assets, liabilities, revenues and expenses is dependent upon future events, the preparation of these consolidated financial statements requires the use of 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
Changes for Second Quarter 2007
Proprietary Natural Gas Storage Inventories and Revenue Recognition
The new Canadian Institute of Chartered Accountants (CICA) Handbook accounting requirements for Section 3031 "Inventories" will become effective January 1, 2008. However, the Company has chosen to adopt this standard as of April 2007. Adjustments to second quarter 2007 consolidated financial statements have been made in accordance with the transitional provisions for this new standard.
Beginning April 1, 2007, TransCanada's proprietary natural gas storage inventory will be valued at its fair value, as measured by the one-month forward price for natural gas. In order to record inventory at fair value, TransCanada has designated its natural gas storage business as a broker/trader business that purchases and sells natural gas on a back-to-back basis. The Company did not have any proprietary natural gas inventory prior to April 1, 2007. The Company records its proprietary natural gas storage results in Revenues net of Commodity Purchases Resold.
At June 30, 2007, $81 million of proprietary natural gas storage inventory was included in Inventories on the Consolidated Balance Sheet. All changes in the fair value of the proprietary natural gas storage inventory will be recorded in Inventories and Revenues. During the three months ended June 30, 2007, unrealized pre-tax losses related to the change in fair value of the proprietary natural gas storage inventory were $23 million, which was essentially offset by the change in fair value of the forward proprietary natural gas storage purchase and sale contracts.
Changes for First Quarter 2007
Effective January 1, 2007, the Company adopted the CICA Handbook accounting requirements for Section 1506 "Accounting Changes", Section 1530 "Comprehensive Income", Section 3251 "Equity", Section 3855 "Financial Instruments - Recognition and Measurement", Section 3861 "Financial Instruments - Disclosure and Presentation", and Section 3865 "Hedges". Adjustments to the consolidated financial statements for the first six months in 2007 have been made in accordance with the transitional provisions for these new standards.
Comprehensive Income and Equity
The Company's financial statements include statements of Consolidated Comprehensive Loss and Accumulated Other Comprehensive Loss. In addition, as required by Section 3251, the Company now presents separately in its Consolidated Shareholders' Equity the changes for each of its components of Shareholders' Equity, including Accumulated Other Comprehensive Loss.
Financial Instruments
All financial instruments, including derivatives, are included on the balance sheet initially at fair value. The financial assets are classified as held for trading, held to maturity, loans and receivables, or available for sale. Financial liabilities are classified as held for trading or other financial liabilities. Subsequent measurement is determined by classification.
Held-for-trading financial assets and liabilities consist of swaps, options, forwards and futures and are entered into with the intention of generating a profit. These financial instruments are initially accounted for at their fair value and changes to fair value included in Revenues. Held-to-maturity financial assets are accounted for at their amortized cost using the effective interest method. The Company did not have any of these financial instruments at June 30, 2007. Loans and receivables are accounted for at their amortized cost using the effective interest method. The available-for-sale classification includes non-derivative financial assets that are designated as available for sale or are not included in the other three classifications. These instruments are initially accounted for at their fair value and changes to fair value are recorded through Other Comprehensive Income. Income earned from these assets is included in Interest Income and Other.
Other financial liabilities not classified as held for trading are accounted for at their amortized cost, using the effective interest method. Interest expense is included in Financial Charges and Financial Charges of Joint Ventures.
Derivatives embedded in other financial instruments or contracts (the host instrument) are recorded as separate derivatives and are measured at fair value if the economic characteristics of the embedded derivative are not closely related to the host instrument, the terms of the embedded derivative are the same as those of a stand-alone derivative and the total contract is not held for trading or accounted for at fair value. Changes in fair value of the embedded derivative are included in Revenues. All derivatives, other than those that meet the normal purchases and sales exceptions or are not within the scope of Section 3855, are carried on the balance sheet at fair value. The Company used January 1, 2003 as the transition date for embedded derivatives.
Transaction costs are incremental costs that are directly attributable to the acquisition, issue or disposal of a financial instrument. Effective January 1, 2007, the Company began offsetting long-term debt transaction costs against the associated debt and began amortizing these costs using the effective interest method. Previously, these costs were amortized on a straight-line basis over the life of the debt. There was no material effect on the Company's financial statements as a result of this change in policy. In second quarter and the first six months of 2007, the charge to Net Income for the amortization of transaction costs using the effective interest method was immaterial.
As part of the accounting for the Company's regulated operations, gains or losses from the changes in the fair value of financial instruments within the regulated operations are included in regulatory assets or regulatory liabilities.
Hedges
Section 3865 specifies the circumstances under which hedge accounting is permissible, how hedge accounting may be performed and where the impacts should be recorded. The standard introduces three specific types of hedging relationships: fair value hedges, cash flow hedges and hedges of a net investment in self-sustaining foreign operations.
As part of its asset and liability management, the Company uses derivatives for hedging positions to reduce its exposure to credit and market risk. The Company designates certain derivatives as hedges and prepares documentation at the inception of the hedging contract. The Company performs an assessment at inception and during the term of the contract to determine if the derivative used as a hedge is effective in offsetting the risks in the values or cash flows of the hedged financial instrument. All derivatives are initially recorded at fair value and adjusted to fair value at each reporting date.
Fair value hedges primarily consist of interest rate swaps used to mitigate the effect of changes in the fair value of fixed-rate long-term financial instruments due to movements in market interest rates. Changes in the value of fair value hedges and the corresponding underlying transactions are recorded in Financial Charges and Interest Income and Other, for hedges of interest rates and foreign exchange rates, respectively. Any gains or losses arising from ineffectiveness are recognized immediately in income in the same financial category as the underlying transaction.
The Company uses cash flow hedges for its anticipated transactions to reduce exposure to fluctuations in interest rates, foreign exchange rates and changes in commodity prices. The effective portion of changes in the value of cash flow hedges is recognized in Other Comprehensive Income. Ineffective portions and amounts excluded from effectiveness testing of hedges are included in income in the same financial category as the underlying transaction. Gains or losses from cash flow hedges that have been included in Accumulated Other Comprehensive Income are included in Net Income when the underlying transaction has occurred or becomes probable of not occurring. The maximum length of time the Company is hedging its exposure to variability in future cash flows is 10 years. The Company hedges its foreign currency exposure of investments in self-sustaining foreign operations with certain cross-currency swaps, forward exchange contracts and options. These financial instruments are adjusted to fair value and the effective portion of gains or losses associated with these adjustments are included in Other Comprehensive Income. In addition, the Company hedges its net investment with U.S. dollar-denominated debt, which is valued at period-end foreign exchange rates. Gains or losses arising from ineffective portions of the hedge are included in income. Gains or losses from these hedges that have been included in Accumulated Other Comprehensive Income are reclassified to Net Income in the event the Company settles or otherwise reduces its investment.
Net Effect of Accounting Policy Changes
The net effect to the Company's financial statements at January 1, 2007 resulting from the above-mentioned changes in accounting policies is as follows.
Increases/(decreases)
(unaudited)
(millions of dollars)
----------------------------------------------------------------------------
Other current assets (127)
Other assets (203)
Accounts payable (29)
Deferred amounts (75)
Future income taxes (42)
Long-term debt (85)
Long-term debt of joint ventures (7)
Accumulated other comprehensive loss (186)
Foreign exchange adjustment 90
Retained earnings 4
Future Accounting Changes
Section 1535 Capital Disclosures
Effective for interim and annual financial statements for fiscal years beginning on or after October 1, 2007, the new CICA Handbook Section 1535 "Capital Disclosures" requires the disclosure of qualitative and quantitative information about the Company's objectives, policies and processes for managing capital.
Section 3862 Financial Instruments - Disclosures and Section 3863 - Financial Instruments - Presentation
Effective for interim and annual financial statements for fiscal years beginning on or after October 1, 2007, the new CICA Handbook Sections 3862 and 3863 will replace Section 3861 to prescribe the requirements for presentation and disclosure of financial instruments.
3. Segmented Information
Three months ended
June 30 Pipelines Energy Corporate Total
(unaudited - millions ------------ ------------- ------------- -------------
of dollars) 2007 2006 2007 2006 2007 2006 2007 2006
--------------------------- ------ ------ ------ ------ ------ ------ ------
Revenues 1,228 969 984 716 - - 2,212 1,685
Plant operating
costs and other (417) (326) (343) (236) (1) (4) (761) (566)
Commodity purchases
resold (65) - (462) (337) - - (527) (337)
Depreciation (260) (235) (40) (31) - - (300) (266)
------ ------ ------ ------ ------ ------ ------ ------
486 408 139 112 (1) (4) 624 516
Financial charges
and non-controlling
interests (206) (184) - - (78) (34) (284) (218)
Financial charges of
joint ventures (13) (19) (6) (5) - - (19) (24)
Income from equity
investments 5 6 - - - - 5 6
Interest income and
other 11 2 3 1 29 12 43 15
Gain on sale of
Northern Border
Partners, L.P.
interest - 23 - - - - - 23
Income taxes (117) (89) (42) (11) 47 26 (112) (74)
------ ------ ------ ------ ------ ------ ------ ------
Income from
Continuing
Operations 166 147 94 97 (3) - 257 244
------ ------ ------ ------ ------ ------
Income from
Discontinued
Operations - -
------ ------
Net Income 257 244
------ ------
Six months ended
June 30 Pipelines Energy Corporate Total
(unaudited - millions ------------ ------------- ------------- -------------
of dollars) 2007 2006 2007 2006 2007 2006 2007 2006
--------------------------- ------ ------ ------ ------ ------ ------ ------
Revenues 2,352 1,946 2,109 1,633 - - 4,461 3,579
Plant operating
costs and other (800) (643) (690) (455) (3) (5)(1,493)(1,103)
Commodity purchases
resold (65) - (1,038) (842) - - (1,103) (842)
Depreciation (511) (461) (79) (62) - - (590) (523)
------ ------ ------ ------ ------ ------ ------ ------
976 842 302 274 (3) (5) 1,275 1,111
Financial charges
and non-controlling
interests (423) (376) 1 - (127) (69) (549) (445)
Financial charges of
joint ventures (29) (33) (11) (12) - - (40) (45)
Income from equity
investments 11 24 - - - - 11 24
Interest income and
other 18 34 6 3 44 27 68 64
Gain on sale of
Northern Border
Partners, L.P.
interest - 23 - - - - - 23
Income taxes (232) (210) (98) (68) 87 35 (243) (243)
------ ------ ------ ------ ------ ------ ------ ------
Income from
Continuing
Operations 321 304 200 197 1 (12) 522 489
------ ------ ------ ------ ------ ------
Income from
Discontinued
Operations - 28
------ ------
Net Income 522 517
------
Total Assets
(unaudited - millions of dollars) June 30, 2007 December 31, 2006
------------------------------------------------------- -------------------
Pipelines 22,753 18,320
Energy 6,509 6,500
Corporate 1,060 1,089
--------------- -------------------
30,322 25,909
4. Acquisitions and Dispositions
ANR and Great Lakes
In February 2007, TransCanada acquired American Natural Resources Company and ANR Storage Company (together ANR) and an additional 3.55 per cent interest in Great Lakes from El Paso Corporation for approximately US$3.4 billion, subject to certain post-closing adjustments, including US$491 million of assumed long-term debt. The acquisition was accounted for using the purchase method of accounting. TransCanada began consolidating ANR and Great Lakes in the Pipelines segment subsequent to the acquisition date. The preliminary allocation of the purchase price was as follows.
Purchase Price Allocation
(unaudited)
(millions of US dollars) ANR Great Lakes Total
----------------------------------------------------------------- ---------
Current assets 258 4 262
Plant, property and equipment 1,874 35 1,909
Other non-current assets 82 - 82
Goodwill 1,767 37 1,804
Current liabilities (177) (3) (180)
Long-term debt (475) (16) (491)
Other non-current liabilities (447) (22) (469)
--------- --------------- ---------
2,882 35 2,917
--------- --------------- ---------
A preliminary allocation of the purchase price has been made using fair values of the net assets at the date of acquisition. As ANR's and Great Lakes' tolls are subject to rate regulation based on historical costs, the regulated net assets, other than gas held for sale, were determined to have a fair value equal to their rate-regulated values.
Goodwill will be evaluated on an annual basis for impairment. Factors that contributed to goodwill included the opportunity to expand in the U.S. market and gaining a stronger competitive position in the North American gas transmission business. The goodwill recognized on this transaction is not amortizable for tax purposes.
PipeLines LP Acquisition of Great Lakes
In February 2007, PipeLines LP acquired a 46.45 per cent interest in Great Lakes from El Paso Corporation for approximately US$945 million, subject to certain post-closing adjustments, including US$209 million of assumed long-term debt. The acquisition was accounted for using the purchase method of accounting. TransCanada began consolidating Great Lakes in the Pipelines segment subsequent to the acquisition date. The preliminary allocation of the purchase price was as follows.
Purchase Price Allocation
(unaudited)
(millions of US dollars)
----------------------------------------------------------------------------
Current assets 42
Plant, property and equipment 465
Other non-current assets 1
Goodwill 460
Current liabilities (23)
Long-term debt (209)
--------
736
--------
A preliminary allocation of the purchase price has been made using fair values of the net assets at the date of acquisition. As Great Lakes' tolls are subject to rate regulation based on historical costs, the regulated net assets were determined to have a fair value equal to their rate-regulated values.
Goodwill will be evaluated on an annual basis for impairment. Factors that contributed to goodwill included the opportunity to expand in the U.S. market and gaining a stronger competitive position in the North American gas transmission business. The goodwill recognized on this transaction is amortizable for tax purposes.
PipeLines LP
In February 2007, PipeLines LP completed a private placement offering of 17,356,086 common units at a price of US$34.57 per unit, of which 50 per cent of the units were acquired by TransCanada for US$300 million. TransCanada also invested an additional US$12 million to maintain its general partnership ownership interest in PipeLines LP. As a result of these additional investments in PipeLines LP, TransCanada's ownership in PipeLines LP increased to 32.1 per cent on February 22, 2007. The total private placement plus TransCanada's additional investment resulted in gross proceeds to PipeLines LP of US$612 million, which were used to partially finance its Great Lakes acquisition.
5. Notes Payable and Long-Term Debt
In April 2007, TransCanada issued US$1.0 billion of Junior Subordinated Notes ("Notes") maturing in 2067 and bearing interest of 6.35 per cent until May 15, 2017 at which time the interest on the Notes will convert to a floating rate, reset quarterly to the three-month London Interbank Offered Rate (LIBOR) plus 221 basis points. The Notes' effective interest rate at June 30, 2007 was 6.51 per cent. TransCanada has the option to defer payment of interest for one or more periods of up to ten years without giving rise to an event of default and without permitting acceleration of payment under the terms of the Notes. If this were to occur, the Company would be prohibited from paying dividends during the deferral period. The Notes are subordinated in right of payment to existing and future senior indebtedness and are effectively subordinated to all indebtedness and obligations of TCPL. The Notes are callable at TransCanada's option at any time on or after May 15, 2017 at 100 per cent of the principal amount of the Notes plus accrued and unpaid interest to the date of redemption. Upon the occurrence of certain events, the Notes are callable earlier at TransCanada's option, in whole or in part, at an amount equal to the greater of 100 per cent of the principal amount of the Notes plus accrued and unpaid interest to the date of redemption or at an amount determined by formula in accordance with the terms of the Notes.
In April 2007, Northern Border established a US$250 million five-year bank facility. A portion of the bank facility was drawn to refinance US$150-million of senior notes that matured on May 1, 2007, with the balance available to fund Northern Border's ongoing operations.
In March 2007, the Company filed debt shelf prospectuses in Canada and the U.S. qualifying for issuance of $1.5 billion of medium-term notes and US$1.5 billion of debt securities, respectively. At June 30, 2007, the Company had issued no medium-term notes and US$1.0 billion of debt securities under these prospectuses.
In March 2007, ANR Pipeline Company voluntarily withdrew from the New York Stock Exchange the listing of its 9.625 per cent Debentures due 2021, 7.375 per cent Debentures due 2024, and 7.0 per cent Debentures due 2025. With the delisting, which became effective April 12, 2007, ANR Pipeline Company deregistered these securities from registration with the U.S. Securities Exchange Commission (SEC).
In February 2007, the Company executed an agreement for a US$2.2 billion, committed, unsecured, one-year bridge loan facility with a floating interest rate based on the one-month LIBOR plus 25 basis points. The Company utilized $1.5 billion and US$700 million from this facility to partially finance the ANR and Great Lakes acquisition. At June 30, 2007, the Company had an outstanding balance of US$488 million on this facility. The undrawn balance of this facility has been cancelled and is no longer available to the Company.
In February 2007, the Company established a US$1.0-billion committed, unsecured credit facility, consisting of a US$700-million five-year term loan and a US$300-million five-year, extendible revolving facility. A floating interest rate based on the three-month LIBOR plus 22.5 basis points is charged on the balance outstanding and a facility fee of 7.5 basis points is charged on the entire facility. The Company utilized US$1.0 billion from this facility and an additional US$100 million from an existing demand line to partially finance the ANR acquisition as well as its additional investment in PipeLines LP. At June 30, 2007, the Company had an outstanding balance of US$700 million on the credit facility and had repaid the demand line.
In February 2007, PipeLines LP increased the size of its syndicated revolving credit and term loan facility in connection with its Great Lakes acquisition. The amount available under the facility increased from US$410 million to US$950 million, consisting of a US$700-million senior term loan and a US$250-million senior revolving credit facility, with US$194 million of the senior term loan amount available being terminated upon closing of the Great Lakes acquisition. At June 30, 2007, US$506 million of the senior term loan and US$10 million of the senior revolving credit facility remained outstanding. A floating interest rate based on the three-month LIBOR plus 55 basis points is charged on the senior term loan and a floating interest rate based on the one-month LIBOR plus 35 basis points is charged on the senior revolving credit facility. A facility fee of 10 basis points is charged on the US$250 million senior revolving credit facility. The weighted average interest rate at June 30, 2007 was 5.94 per cent.
6. Preferred Securities
On July 5, 2007, TransCanada redeemed, at par, all of the outstanding US$460 million 8.25 per cent Preferred Securities due 2047. The redemption occurred as a result of a five-year tolls settlement reached on the Canadian Mainline. The redemption crystallized a foreign exchange gain that will flow through to the Canadian Mainline's customers.
7. Share Capital
In second quarter 2007, TransCanada issued 1.3 million common shares under its Dividend Reinvestment Program, resulting in proceeds of approximately $51 million.
In February and March 2007, TransCanada issued, through a subscription receipts offering, 45,390,500 common shares at a price of $38.00 each, resulting in gross proceeds of approximately $1.725 billion, which were used towards financing the acquisition of ANR and Great Lakes.
In January 2007, TransCanada filed a short form shelf prospectus with securities regulators in Canada and the U.S. to allow for the offering of up to $3.0 billion of common shares, preferred shares and/or subscription receipts in Canada and the U.S. until February 2009. As at June 30, 2007, the Company had issued $1.725 billion in common shares under this shelf prospectus, which were used towards financing the acquisition of ANR.
8. Financial Instruments and Risk Management
The fair values of non-derivative financial instruments at June 30, 2007 are as follows.
Non-Derivative Financial Instruments Summary (1)
(unaudited)
(millions of dollars) June 30, 2007
----------------------------------------------------------------------------
Fair
Value
--------
Financial Assets (2) (3)
Cash and cash equivalents (4) 340
Loans and receivables (4) 1,142
Available-for-sale assets 13
--------
1,495
--------
Financial Liabilities (3) (5) (6)
Notes payable 728
Trade and other payables 1,187
Long-term debt 14,520
Preferred securities 489
Other long-term liabilities 65
--------
16,989
--------
----------------------------------------------------------------------------
(1) Consolidated Net Income for the three months and six months ended June
30, 2007 included a $2 million unrealized loss for the fair value
adjustments to these financial instruments.
(2) At June 30, 2007, Current Assets on the Consolidated Balance Sheet
included financial assets of $932 million in Accounts Receivable and
$340 million in Cash and Cash Equivalents. The remainder of these
financial assets were included in Other Assets.
(3) Carrying value is not materially different from fair value, except for
available-for-sale financial assets, which have a carrying value equal
to fair value.
(4) Recorded at cost.
(5) Recorded at amortized cost.
(6) At June 30, 2007, Current Liabilities on the Consolidated Balance Sheet
included financial liabilities of $1,178 million in Accounts Payable and
$728 million in Notes Payable. Financial liabilities of $74 million were
included in Deferred Amounts, $14,520 million were included in Long-Term
Debt and $489 million were included in Preferred Securities.
The fair values of the Company's derivative financial instruments are as
follows.
Derivative Financial Instruments Summary (1)
(unaudited)
(millions of dollars) June 30, 2007
----------------------------------------------------------------------------
Fair
Value
--------
Derivative financial instruments held for trading
Power derivatives-assets (2) 38
Power derivatives-liabilities(2) (31)
Natural gas derivatives-assets(3) 67
Natural gas derivatives-liabilities(3) (34)
Interest rate derivatives-assets (4) 18
Interest rate derivatives-liabilities (4) (4)
Foreign exchange derivatives-assets (4) 3
Foreign exchange derivatives-liabilities(4) (67)
--------
(10)
--------
Derivative financial instruments in hedging relationships (5)
Power derivatives-assets (6) 102
Power derivatives-liabilities(6) (269)
Natural gas derivatives-assets(6) 30
Natural gas derivatives-liabilities(6) (9)
Interest rate derivatives-assets (7) 9
Interest rate derivatives-liabilities (7) (5)
Foreign exchange derivatives-assets (7) -
Foreign exchange derivatives-liabilities(7) (54)
--------
(196)
--------
Total Derivative Financial Instruments (206)
--------
----------------------------------------------------------------------------
(1) Fair value is equal to the carrying value of these derivatives except
for derivatives used in the Company's regulatory operations which are
carried at their regulatory values.
(2) Consolidated Net Income for the three and six months ended June 30, 2007
included a $15 million unrealized loss and a $4 million unrealized gain,
respectively, for the change in the fair value of held-for-trading power
derivatives.
(3) Consolidated Net Income for the three and six months ended June 30, 2007
included $4 million and $10 million, respectively, of unrealized gains
for the change in the fair value of held-for-trading natural gas
derivatives.
(4) Consolidated Net Income for the three and six months ended June 30, 2007
included a $6 million unrealized loss and a $1 million unrealized
gain, respectively, for the change in the fair value of held-for-trading
interest-rate and foreign exchange derivatives.
(5) All hedging relationships are designated cash flow hedges except for $4
million of interest-rate derivative financial instruments designated as
fair value hedges.
(6) Consolidated Net Income for the three and six months ended June 30, 2007
included nil and a $6 million gain, 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
underlyings.
(7) Consolidated Net Income for the three and six months ended June 30, 2007
included a $4 million loss for the change in fair value of
interest-rate and foreign exchange cash flow hedges and fair value
hedges that were ineffective in offsetting the change in fair value of
their related underlyings.
Unrealized Gains and Losses
At June 30, 2007, there were unrealized gains from unsettled derivative financial instruments of $147 million (December 31, 2006 - $41 million) included in Other Current Assets and $120 million (December 31, 2006 - $39 million) included in Other Assets. At June 30, 2007, there were unrealized losses from unsettled derivative financial instruments of $220 million (December 31, 2006 - $144 million) included in Accounts Payable and $253 million (December 31, 2006 - $158 million) included in Deferred Amounts. At June 30, 2007, there were unrealized losses from the fair value adjustments of proprietary natural gas storage inventory of $23 million (December 31, 2006 - nil) included in Inventories.
Energy Price, Interest Rate and Foreign Exchange Rate Risk Management
The Company enters into various contracts to mitigate its exposure to fluctuations in interest rates, foreign exchange rates and commodity prices. The contracts generally consist of the following.
- Forwards and futures contracts - contractual agreements to buy or sell a specific financial instrument or commodity at a specified price and date in the future. The Company enters into foreign exchange and commodity forwards and futures to mitigate volatility in changes in foreign exchange rates and power and gas prices, respectively.
- Swaps - contractual agreements between two parties to exchange streams of payments over time according to specified terms. The Company enters into interest rate, cross-currency and commodity swaps to mitigate changes in interest rates, foreign exchange rates and commodity prices, respectively.
- Options - contractual agreements to convey the right, but not the obligation, for the purchaser either to buy or sell a specific amount of a financial instrument or commodity at a fixed price, either at a fixed date or at any time within a specified period. The Company enters into option agreements to mitigate changes in interest rates, foreign exchange rates and commodity prices.
- Heat rate contracts - contracts for the sale or purchase of power that are priced based on a natural gas index.
Energy Price Risk
The Company is exposed to energy price movements as part of its normal business operations, particularly in relation to the prices of electricity and natural gas. The primary risk is that market prices for commodities will move adversely between the time that purchase and/or sales prices are fixed, potentially reducing expected margins.
To manage exposure to price risk, subject to the Company's overall risk management policies and procedures, the Company commits a significant portion of its supply to medium- to long-term sales contracts while reserving an amount of unsold supply to maintain flexibility in the overall management of its asset portfolio. The types of instruments used include forwards and futures contracts, swaps, options, and heat rate contracts.
TransCanada manages its exposure to seasonal gas price spreads in its natural gas storage business, by hedging storage capacity with a portfolio of third party storage capacity leases and back-to-back proprietary natural gas purchases and sales. By matching purchases and sales volumes, TransCanada locks in a margin and effectively eliminates its exposure to the price movements of natural gas.
The Company continually assesses its power contracts and derivative instruments used to manage energy price risk. Contracts, with the exception of leases, have been assessed to determine whether they meet the definition of a derivative. Certain commodity purchase and sale contracts are derivatives but are not within the scope of CICA Handbook Section 3855, as they were entered into and continue to be held for the purpose of receipt or delivery in accordance with the Company's expected purchase, sale or usage requirements ("normal purchases and sales exception"), are considered to be executory contracts or meet other exemption criteria listed in Section 3855.
Interest Risk
The Company has fixed interest rate long-term debt, which subjects the Company to interest rate price risk, and has floating interest rate long-term debt, which subjects the Company to interest rate cash flow risk. To manage its exposure to these risks, the Company uses a combination of interest-rate swaps, forwards and options.
Investments in Foreign Operations
The Company hedges its net investment in self-sustaining foreign operations with U.S. dollar-denominated debt, cross-currency swaps, forward exchange contracts and options. At June 30, 2007, the Company had designated U.S. dollar-denominated debt with a carrying value of $4,104 million (US$3,859 million) and a fair value of $4,178 million (US$3,929 million) as a portion of this hedge and swaps, forwards and options with a fair value of $75 million (US$70 million) as net investment hedges.
Net Investment in Foreign Operations
Asset/(Liability)
(millions of dollars) June 30, 2007 December 31, 2006
----------------------------------------------------------------------------
Notional or Notional or
Fair Principal Fair Principal
Value(1) Amount Value(1) Amount
-------------------- ---------------------
Derivative financial Instruments
in hedging relationships
U.S. dollar cross-currency swaps
(maturing 2007 to 2013) 75 U.S. 350 58 U.S. 400
U.S. dollar forward foreign
exchange contracts
(maturing 2007) - U.S. 75 (7) U.S. 390
U.S. dollar options
(maturing 2007) - U.S. 50 (6) U.S. 500
-------------------- ---------------------
75 U.S. 475 45 U.S. 1,290
-------------------- ---------------------
(1) Fair values are equal to carrying values.
Fair Values
Fair values of financial instruments are determined by reference to quoted bid or asking price, as appropriate, in active markets. In the absence of an active market, the Company determines fair value by using valuation techniques that refer to observable market data or estimated market prices. These include comparisons with similar instruments where market observable prices exist, option pricing models and other valuation techniques commonly used by market participants. Fair values determined using valuation models require the use of assumptions concerning the amount and timing of estimated future cash flows and discount rates. In determining those assumptions, the Company looks primarily to external readily observable market input factors such as interest rate yield curves, currency rates, and price and rate volatilities as applicable.
9. Income Taxes
In second quarter 2007, TransCanada recorded income tax benefits of approximately $16 million as a result of changes in Canadian federal income tax legislation.
In first quarter 2007, TransCanada recorded income tax benefits of approximately $10 million from the resolution of certain income tax matters, as well as a $5 million income tax benefit from an internal restructuring.
10. Employee Future Benefits
The net benefit plan expense for the Company's defined benefit pension plans and other post-employment benefit plans for the three and six months ended June 30, 2007 is as follows.
Three months ended June 30 Pension Benefit Plans Other Benefit Plans
(unaudited - millions of ----------------------- ---------------------
dollars) 2007 2006 2007 2006
------------------------------------------- ---------- ---------- ----------
Current service cost 11 9 1 1
Interest cost 18 16 2 2
Expected return on plan assets (20) (17) (1) (1)
Amortization of net actuarial
loss 6 7 - -
Amortization of past service
costs 1 1 (1) 1
------------ ---------- ---------- ----------
Net benefit cost recognized 16 16 1 3
------------ ---------- ---------- ----------
Six months ended June 30 Pension Benefit Plans Other Benefit Plans
(unaudited - millions of ----------------------- ---------------------
dollars) 2007 2006 2007 2006
------------------------------------------- ---------- ---------- ----------
Current service cost 22 18 1 1
Interest cost 35 33 3 4
Expected return on plan assets (39) (35) (1) (1)
Amortization of transitional
obligation related to
regulated business - - 1 1
Amortization of net actuarial
loss 12 14 1 1
Amortization of past service
costs 2 2 (1) 1
------------ ---------- ---------- ----------
Net benefit cost recognized 32 32 4 7
------------ ---------- ---------- ----------
----------------------------------------------------------------------------
TransCanada welcomes questions from shareholders and potential investors.
Please telephone:
Investor Relations, at 1-800-361-6522 (Canada and U.S. Mainland) or direct
dial David Moneta/Myles Dougan at (403) 920-7911. The investor fax line is
(403) 920-2457. Media Relations: Shela Shapiro at (403) 920-7859
Visit TransCanada's Internet site at: http://www.transcanada.com
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