TransCanada Announces Second Quarter Net Income of $324 Million
Comparable Earnings Per Share Increase 27 Percent
CALGARY, ALBERTA--(Marketwire - July 31, 2008) - 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 2008 of $324 million ($0.58 per share) compared to $257 million ($0.48 per share) for the same period in 2007, an increase of approximately 21 per cent on a per share basis
- Comparable earnings for second quarter 2008 of $316 million ($0.57 per share) compared to $241 million ($0.45 per share) for the same period in 2007, an increase of approximately 27 per cent on a per share basis
- Funds generated from operations for second quarter 2008 of $676 million compared to $596 million for the same period in 2007, an increase of approximately 13 per cent
- Dividend of $0.36 per common share declared by the Board of Directors
- Proceeded with plans for a 500,000 barrel per day expansion and extension of the Keystone crude oil pipeline system from western Canada to the U.S. Gulf Coast
- Construction began on the initial phase of Keystone that will serve markets in the U.S. Midwest
- Portlands Energy Centre went into service in simple-cycle mode on time and on budget
"The significant increase in second quarter earnings and cash flow demonstrates TransCanada's ability to deliver strong financial performance from its growing portfolio of high quality assets," said Hal Kvisle, TransCanada's president and chief executive officer. "Today we are in the midst of a $17 billion capital program that is expected to deliver significant value to our shareholders over the next five years. Preparing for the longer term, we continue to build and develop our portfolio of large scale energy infrastructure projects including oil and gas pipelines, power generating plants and natural gas storage facilities."
TransCanada Corporation (TransCanada) reported net income for second quarter 2008 of $324 million ($0.58 per share) compared to $257 million ($0.48 per share) for second quarter 2007.
Comparable earnings were $316 million ($0.57 per share) for second quarter 2008 compared to $241 million ($0.45 per share) in second quarter 2007. The $75 million ($0.12 per share) increase was due to strong earnings from the Company's Energy business and lower corporate costs. Higher realized power prices in Alberta was the primary reason for the significant increase in earnings in Energy's Western Power business. Corporate costs were lower in second quarter 2008 due to a reduction in financial charges. Comparable earnings in second quarter 2008 excluded a net unrealized gain of $8 million from fair value adjustments in the Natural Gas Storage business and in second quarter 2007 excluded $16 million of favourable income tax adjustments.
Funds generated from operations of $676 million in second quarter 2008 were $80 million higher than the $596 million generated in the same period in 2007 primarily due to higher earnings.
Notable recent developments in Pipelines, Energy and Corporate include:
Pipelines:
- The approximately US$7 billion Keystone Gulf Coast expansion project was announced, that is expected to provide additional capacity in 2012 of 500,000 barrels per day (bbl/d) from western Canada to the U.S. Gulf Coast, near existing terminals in Port Arthur, Texas. Keystone is a 50/50 partnership between TransCanada and ConocoPhillips. Construction of the facilities is anticipated to commence in 2010 following the receipt of the necessary regulatory approvals. When completed, the expansion will increase the commercial design of the Keystone pipeline system from 590,000 bbl/d to approximately 1.1 million bbl/d. Keystone has secured long-term commitments for approximately 830,000 bbl/d for an average term of 18 years.
Construction began on the initial phase of the Keystone pipeline including facilities in Canada and the U.S., which will transport 590,000 bbl/d of crude oil from Hardisty, Alberta to U.S. Midwest markets. Deliveries to Wood River and Patoka, Illinois are expected to commence in late 2009, with deliveries to Cushing, Oklahoma anticipated in late 2010. The initial phase is expected to cost approximately US$5.2 billion.
- The Alaska House of Representatives voted in favour of granting TransCanada a license to build the Alaska pipeline. A positive Alaska Senate vote is a necessary condition for the issuance of the license. A vote by the Senate is anticipated by August 2, 2008. This major natural gas pipeline project would connect stranded U.S. natural gas reserves to Alaskan and Lower 48 consumers.
- TransCanada filed an application with the National Energy Board (NEB) to establish federal jurisdiction over the Alberta System. The NEB announced it would hold an oral hearing commencing in November 2008 with a decision expected in first quarter 2009. Federal regulation would enable the Alberta System to extend across provincial borders, providing integrated service to Alberta and British Columbia customers, and Northern gas producers.
- TransCanada concluded a non-binding open season to gauge interest for new natural gas transportation service connecting the Horn River and Montney/Groundbirch areas in British Columbia to TransCanada's Alberta System. TransCanada has received requests for gas transmission service exceeding 1 bcf/d for each area by 2012. It is anticipated TransCanada will complete a binding open season in the next several months.
- TransCanada continued to pursue opportunities to move an increasing supply of natural gas from the U.S. Rocky Mountains to growing markets using existing assets through proposals like Sunstone, Pathfinder, and Northern Border's proposed Bison project.
Energy:
- TransCanada announced that the Salt River Project signed a 20-year power purchase agreement to secure 100 per cent of the output from TransCanada's planned 575 megawatt (MW) Coolidge Generating Station in Coolidge, Arizona. Subject to receipt of required permits, construction is scheduled to begin in late 2009. The simple-cycle natural gas-fired peaking power facility is expected to be in service in May 2011.
- The 132 MW Kibby Wind power project received unanimous final development plan approval from the State of Maine's Land Use Regulation Commission. Pending all remaining regulatory approvals, construction is expected to begin in third quarter 2008 and the project is expected to be fully commissioned in 2010.
- The Portlands Energy Centre natural gas-fired, combined-cycle power plant in Toronto, Ontario went into service in simple-cycle mode on time and on budget. It is currently able to provide 340 MW of electricity. In September 2008, the power plant is anticipated to return to the construction phase and to be fully commissioned in a 550 MW combined-cycle mode in second quarter 2009.
- The U.S. Federal Energy and Regulatory Commission issued an order authorizing TransCanada's acquisition of the 2,480 MW Ravenswood Generating Facility (Ravenswood) located in Queens, New York. This acquisition remains subject to New York Public Service Commission approval and is expected to close in third quarter 2008.
- Broadwater Energy filed an appeal with the U.S. Secretary of Commerce related to New York State's Department of State's rejection of a proposal to construct the Broadwater liquefied natural gas (LNG) facility.
Corporate:
- TransCanada closed a $1.27 billion common share offering with net proceeds designated to partially fund acquisitions and capital projects including the acquisition of Ravenswood, construction of Keystone, and for general corporate purposes.
- Following the common share offering, TransCanada filed a final short form base shelf prospectus with securities regulators in Canada and the U.S. The filing was done in normal course to allow for the potential future offering up to $3.0 billion of preferred shares, common shares and/or subscription receipts.
- TransCanada's 2007 Corporate Responsibility Report was released that shares information and statistics in the areas of business, environment and human resources. The report includes a high-level, cross-functional discussion of the policies, procedures and everyday practices followed to address the needs of our stakeholders, the protection of the environment, and the management of our business.
Teleconference - Audio and Slide Presentation
TransCanada will hold a teleconference today at 2:30 p.m. (Mountain) / 4:30 p.m. (Eastern) to discuss the second quarter 2008 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 7, 2008. Please call (800) 408-3053 or (416) 695-5800 (Toronto area) and enter pass code 3266671#. 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 355 billion cubic feet of storage capacity. A growing independent power producer, TransCanada owns, controls or is developing approximately 8,400 megawatts of power generation. 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 reflect TransCanada's beliefs and assumptions based on information available at the time the statements were made. Actual results or events may differ from those predicted in these forward-looking statements. Factors 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 operating performance of the Company's pipeline and energy assets, the availability and price of energy commodities, regulatory processes and decisions, changes in environmental and other laws and regulations, competitive factors in the pipeline and energy industry sectors, construction and completion of capital projects, labour, equipment and material costs, access to capital markets, interest and currency exchange rates, technological developments and the current economic conditions in North America. By its nature, 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 expectations expressed. Additional information on these and other factors is available in the reports filed by TransCanada with Canadian securities regulators and with the U.S. Securities and Exchange Commission. 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 to not use future-oriented information or financial outlooks for anything other than their intended purpose. TransCanada undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, except as required by law.
Non-GAAP Measures
TransCanada uses the measures "comparable earnings", "comparable earnings per share" and "funds generated from operations" in this News Release. These measures do not have any standardized meaning prescribed by Canadian Generally Accepted Accounting Principles (GAAP). They are, therefore, considered to be non-GAAP measures and are unlikely to be comparable to similar measures presented by other entities. Management of TransCanada uses non-GAAP measures to improve its ability to compare financial results among reporting periods and to enhance its understanding of operating performance, liquidity and ability to generate funds to finance operations. Non-GAAP measures are also provided to readers as additional information on TransCanada's operating performance, liquidity and ability to generate funds to finance operations.
Management uses the measure of comparable earnings to better evaluate trends in the Company's underlying operations. Comparable earnings comprise net income adjusted for specific items that are significant, but are not reflective of the Company's underlying operations. Specific items are subjective, however, management uses its judgement and informed decision-making when identifying items to be excluded in calculating comparable earnings, some of which may recur. Specific items may include but are not limited to certain income tax refunds and adjustments, gains or losses on sales of assets, legal and bankruptcy settlements, and fair value adjustments. The table in the Consolidated Results of Operations section of the Management's Discussion and Analysis presents a reconciliation of comparable earnings to net income. 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 comprises net cash provided by operations before changes in operating working capital. A reconciliation of funds generated from operations to net cash provided by operations is presented in the Second Quarter 2008 Financial Highlights chart in this News Release.
Second Quarter 2008 Financial Highlights
(unaudited)
Three months Six months
Operating Results ended June 30 ended June 30
(millions of dollars) 2008 2007 2008 2007
---------------------------------------------------------------------------
Revenues 2,017 2,208 4,150 4,452
Net Income 324 257 773 522
Comparable Earnings(1) 316 241 642 491
Cash Flows
Funds generated from operations(1) 676 596 1,598 1,178
(Increase)/decrease in operating working
capital (104) 93 (98) 129
-----------------------------
Net cash provided by operations 572 689 1,500 1,307
-----------------------------
-----------------------------
Capital Expenditures 633 386 1,093 692
Acquisitions, Net of Cash Acquired 2 4 4 4,224
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Common Share Statistics Three months Six months
ended June 30 ended June 30
2008 2007 2008 2007
---------------------------------------------------------------------------
Net Income Per Share - Basic $0.58 $0.48 $1.40 $1.00
Comparable Earnings Per Share - Basic(1) $0.57 $0.45 $1.17 $0.94
Dividends Declared Per Share $0.36 $0.34 $0.72 $0.68
Basic Common Shares Outstanding (millions)
Average for the period 561 536 551 522
End of period 578 536 578 536
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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 this News Release.
TRANSCANADA CORPORATION - SECOND QUARTER 2008
Quarterly Report to Shareholders
Management's Discussion and Analysis
Management's Discussion and Analysis (MD&A) dated July 31, 2008 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, 2008. It should also be read in conjunction with the audited Consolidated Financial Statements and notes thereto, and the MD&A contained in TransCanada's 2007 Annual Report for the year ended December 31, 2007. 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 2007 Annual Report.
Forward-Looking Information
This MD&A may contain certain information that is forward-looking and is subject to important risks and uncertainties. The words "anticipate", "expect", "believe", "may", "should", "estimate", "project", "outlook", "forecast" or other similar words are used to identify such forward-looking information. All forward-looking statements reflect TransCanada's beliefs and assumptions based on information available at the time the statements were made. Actual results or events may differ from those predicted in these forward-looking statements. Factors that could cause actual results or events to differ materially from current expectations include, among other things, the ability of TransCanada to successfully implement its strategic initiatives and whether such strategic initiatives will yield the expected benefits, the operating performance of the Company's pipeline and energy assets, the availability and price of energy commodities, regulatory processes and decisions, changes in environmental and other laws and regulations, competitive factors in the pipeline and energy industry sectors, construction and completion of capital projects, labour, equipment and material costs, access to capital markets, interest and currency exchange rates, technological developments and the current economic conditions in North America. By its nature, forward-looking information is subject to various risks and uncertainties, which could cause TransCanada's actual results and experience to differ materially from the anticipated results or expectations expressed. Additional information on these and other factors is available in the reports filed by TransCanada with Canadian securities regulators and with the U.S. Securities and Exchange Commission (SEC). Readers are cautioned to not place undue reliance on this forward-looking information, which is given as of the date it is expressed in this MD&A or otherwise, and to not use future-oriented information or financial outlooks for anything other than their intended purpose. TransCanada undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, except as required by law.
Non-GAAP Measures
TransCanada uses the measures "comparable earnings", "comparable earnings per share", "funds generated from operations" and "operating income" in this MD&A. These measures do not have any standardized meaning prescribed by Canadian generally accepted accounting principles (GAAP). They are, therefore, considered to be non-GAAP measures and are unlikely to be comparable to similar measures presented by other entities. Management of TransCanada uses non-GAAP measures to improve its ability to compare financial results among reporting periods and to enhance its understanding of operating performance, liquidity and ability to generate funds to finance operations. Non-GAAP measures are also provided to readers as additional information on TransCanada's operating performance, liquidity and ability to generate funds to finance operations.
Management uses the measure of comparable earnings to better evaluate trends in the Company's underlying operations. Comparable earnings comprise net income adjusted for specific items that are significant, but are not reflective of the Company's underlying operations. Specific items are subjective, however, management uses its judgement and informed decision-making when identifying items to be excluded in calculating comparable earnings, some of which may recur. Specific items may include but are not limited to certain income tax refunds and adjustments, gains or losses on sales of assets, legal and bankruptcy settlements, and fair value adjustments. The table in the Consolidated Results of Operations section of this MD&A presents a reconciliation of comparable earnings to net income. 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 comprises net cash provided by operations before changes in operating working capital. A reconciliation of funds generated from operations to net cash provided by operations is presented in the "Liquidity and Capital Resources" section of this MD&A.
Operating income is reported in the Company's Energy business segment and comprises revenues less operating expenses as shown on the Consolidated Income Statement. A reconciliation of operating income to net income is presented in the Energy section of this MD&A.
Consolidated Results of Operations
Reconciliation of Comparable Earnings to Net Income
Three months Six months
(unaudited) ended June 30 ended June 30
(millions of dollars except per share amounts) 2008 2007 2008 2007
----------------------------------------------------------------------------
Pipelines
Comparable earnings 158 166 357 321
Specific items (net of tax):
Calpine bankruptcy settlements - - 152 -
GTN lawsuit settlement - - 10 -
-----------------------------
Net income 158 166 519 321
Energy
Comparable earnings 143 90 292 196
Specific items (net of tax, where
applicable):
Writedown of Broadwater LNG project costs - - (27) -
Fair value adjustments of natural gas
storage inventory and forward contracts 8 - (4) -
Income tax adjustments - 4 - 4
-----------------------------
Net income 151 94 261 200
Corporate
Comparable earnings/(expenses) 15 (15) (7) (26)
Specific item:
Income tax adjustments - 12 - 27
-----------------------------
Net income/(expenses) 15 (3) (7) 1
-----------------------------
Net Income(1) 324 257 773 522
-----------------------------
-----------------------------
Net Income Per Share(2)
Basic and Diluted $0.58 $0.48 $1.40 $1.00
-----------------------------
-----------------------------
(1)Comparable Earnings 316 241 642 491
Specific items (net of tax, where
applicable):
Calpine bankruptcy settlements - - 152 -
GTN lawsuit settlement - - 10 -
Writedown of Broadwater LNG project costs - - (27) -
Fair value adjustments of natural gas
storage inventory and forward contracts 8 - (4) -
Income tax adjustments - 16 - 31
-----------------------------
Net Income 324 257 773 522
-----------------------------
-----------------------------
(2)Comparable Earnings Per Share $0.57 $0.45 $1.17 $0.94
Specific items - per share
Calpine bankruptcy settlements - - 0.27 -
GTN lawsuit settlement - - 0.02 -
Writedown of Broadwater LNG project costs - - (0.05) -
Fair value adjustments of natural gas
storage inventory and forward contracts 0.01 - (0.01) -
Income tax adjustments - 0.03 - 0.06
-----------------------------
Net Income Per Share $0.58 $0.48 $1.40 $1.00
-----------------------------
-----------------------------
TransCanada's net income in second-quarter 2008 was $324 million or $0.58 per share compared to $257 million or $0.48 per share in second-quarter 2007. The $67-million increase in net income was primarily due to increased second-quarter 2008 earnings in Energy and Corporate, partially offset by a decrease in earnings in Pipelines. Earnings from Energy were higher in second-quarter 2008 compared to second-quarter 2007 primarily due to increased Western Power and Eastern Power earnings. Energy's earnings in second-quarter 2008 also included net unrealized gains of $8 million after tax ($12 million pre-tax) resulting from changes in fair value of proprietary natural gas storage inventory and natural gas forward purchase and sale contracts. Corporate's earnings were higher in second-quarter 2008 compared to second-quarter 2007 primarily due to a reduction in financial charges. Pipelines' earnings were lower in second-quarter 2008 compared to second-quarter 2007 primarily due to reduced Canadian Mainline and ANR earnings, and increased general, administrative and support costs, partially offset by increased GTN earnings. Net income in second-quarter 2007 included favourable income tax adjustments of $16 million ($12 million in Corporate and $4 million in Energy) resulting from changes in Canadian federal income tax legislation.
Comparable earnings for second-quarter 2008 were $316 million or $0.57 per share compared to $241 million or $0.45 per share for the same period in 2007. On a per share basis, comparable earnings increased approximately 27 per cent in second-quarter 2008 compared to second-quarter 2007. Comparable earnings in second-quarter 2008 excluded the $8 million of net unrealized gains resulting from changes in fair value of proprietary natural gas storage inventory and natural gas forward purchase and sale contracts. Comparable earnings in second-quarter 2007 excluded the $16 million of favourable income tax adjustments.
Net income was $773 million or $1.40 per share for the first six months in 2008 compared to $522 million or $1.00 per share for the same period in 2007. The $251-million increase in net income for the first six months of 2008 compared to the same period in 2007 was primarily due to increased earnings in Pipelines and Energy, partially offset by a decrease in earnings in Corporate. Earnings in Pipelines were higher for the first six months of 2008 compared to the first six months of 2007 primarily due to increased earnings from ANR and GTN, a $152 million after-tax ($240 million pre-tax) gain on shares received by GTN and Portland for bankruptcy settlements from certain subsidiaries of Calpine Corporation (Calpine) and proceeds from a GTN lawsuit settlement of $10 million after tax ($17 million pre-tax). Earnings in Energy were higher for the first six months of 2008 compared to the same period last year primarily due to increased Western Power, Eastern Power and Natural Gas Storage earnings. Partially offsetting these increases to earnings in the first six months of 2008 was a $27 million after-tax ($41 million pre-tax) writedown of costs previously capitalized for the Broadwater liquefied natural gas (LNG) project and a reduction in earnings due to favourable income tax adjustments of $31 million ($27 million in Corporate and $4 million in Energy) recorded in the first six months of 2007 relating to the reduction in Canadian federal and provincial corporate income tax rates, the resolution of certain income tax matters with taxation authorities and a corporate restructuring.
Comparable earnings for the first six months of 2008 were $642 million or $1.17 per share compared to $491 million or $0.94 per share for the same period in 2007. On a per share basis, comparable earnings increased approximately 24 per cent for the first six months in 2008 compared to the same period in 2007. Comparable earnings for the first six months of 2008 excluded the Calpine bankruptcy settlements, the GTN lawsuit settlement, the writedown of the Broadwater LNG project costs and the net unrealized losses from the natural gas storage fair value adjustments. Comparable earnings for the first six months of 2007 excluded the favourable income tax adjustments of $31 million.
Results from each of the businesses for the three and six months ended June 30, 2008 are discussed further in the Pipelines, Energy and Corporate sections of this MD&A.
Funds generated from operations of $676 million and $1,598 million for the three and six months ended June 30, 2008, respectively, increased $80 million (or 13 per cent) and $420 million (or 36 per cent), respectively, compared to the same periods in 2007. For a further discussion on funds generated from operations, refer to the Liquidity and Capital Resources section in this MD&A.
Pipelines
The Pipelines business generated net income and comparable earnings of $158 million in second-quarter 2008, a decrease of $8 million compared to net income and comparable earnings of $166 million in second-quarter 2007.
Net income and comparable earnings for the six months ended June 30, 2008 were $519 million and $357 million, respectively, compared to $321 million for the same six months in 2007. Comparable earnings for the first six months of 2008 excluded the after-tax gains of $152 million on the Calpine shares received by GTN and Portland for the Calpine bankruptcy settlements, and proceeds received by GTN as a result of a $10 million after-tax lawsuit settlement with a software supplier.
Pipelines Results Three months Six months
(unaudited) ended June 30 ended June 30
(millions of dollars) 2008 2007 2008 2007
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Wholly Owned Pipelines
Canadian Mainline 70 75 138 132
Alberta System 33 34 65 65
ANR(1) 25 29 70 50
GTN 15 5 34 16
Foothills 6 8 13 14
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149 151 320 277
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Other Pipelines
Great Lakes(2) 11 11 23 25
PipeLines LP(3) 5 4 12 6
Iroquois 3 3 8 8
Tamazunchale 2 2 4 5
Other(4) 8 10 21 25
Northern Development (1) (1) (1) (2)
General, administrative, support costs and
other (19) (14) (30) (23)
-----------------------------
9 15 37 44
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Comparable Earnings 158 166 357 321
Specific items (net of tax):
Calpine bankruptcy settlements(5) - - 152 -
GTN lawsuit settlement - - 10 -
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Net Income 158 166 519 321
-----------------------------
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(1) ANR's results include earnings from the date of acquisition of February
22, 2007.
(2) Great Lakes' results reflect TransCanada's 53.6 per cent ownership in
Great Lakes since February 22, 2007 and 50 per cent ownership prior to
that date.
(3) PipeLines LP's results include TransCanada's effective ownership of an
additional 14.9 per cent interest in Great Lakes since February 22, 2007
as a result of PipeLines LP's acquisition of a 46.4 per cent interest in
Great Lakes and TransCanada's 32.1 per cent interest in PipeLines LP.
(4) Other includes results of Portland, Ventures LP, TQM, TransGas and Gas
Pacifico/INNERGY.
(5) GTN and Portland received shares of Calpine with an initial after-tax
value of $95 million and $38 million (TransCanada's share),
respectively, from the bankruptcy settlements with Calpine. These shares
were subsequently sold for an additional after-tax gain of $19 million.
Wholly Owned Pipelines
Canadian Mainline's second-quarter 2008 net income of $70 million decreased $5 million compared to $75 million in second-quarter 2007. In May 2007, a settlement effective January 1, 2007 to December 31, 2011 was approved by the National Energy Board (NEB), which included an increase in the deemed common equity ratio from 36 per cent to 40 per cent and certain performance-based incentive arrangements. A favourable $6-million adjustment was recorded in second-quarter 2007 that related to the first three months of 2007 as a result of the settlement. In addition, earnings in second-quarter 2008 reflected the negative impact of a lower average investment base. These decreases were partially offset by the positive impact of a higher rate of return on common equity (ROE), as determined by the NEB, of 8.71 per cent in 2008 compared to 8.46 per cent in 2007.
Canadian Mainline's net income for the six months ended June 30, 2008 increased $6 million to $138 million primarily as a result of the higher ROE and performance-based incentive arrangements, partially offset by a lower average investment base.
The Alberta System's net income was $33 million in second-quarter 2008 and $65 million for the first six months of 2008 compared to $34 million and $65 million for the same periods in 2007. Earnings in 2008 reflect an ROE of 8.75 per cent compared to 8.51 per cent in 2007, both on a deemed common equity of 35 per cent.
ANR's net income in second-quarter 2008 was $25 million compared to $29 million in second-quarter 2007. Net income for the first six months of 2008 was $70 million compared to $50 million for the period commencing on the acquisition date of February 22, 2007 to June 30, 2007. The decrease in second-quarter 2008 was primarily due to higher operations, maintenance and administrative (OM&A) costs, partially offset by increased revenues from new growth projects. The increase for the first six months of 2008 was primarily due to a full six months of earnings in 2008, higher revenues from new growth projects and increased firm transport revenues, partially offset by higher OM&A costs and the negative impact on earnings of a stronger Canadian dollar.
GTN's comparable earnings for the three and six months ended June 30, 2008 increased $10 million and $18 million, respectively, compared to the same periods in 2007. The increases were primarily due to the positive impact of a rate case settlement approved by the Federal Energy Regulatory Commission (FERC) in January 2008 and lower OM&A expenses. For the six months ended June 30, 2008, these increases were partially offset by the negative impact on earnings of a stronger Canadian dollar.
Operating Statistics
Six months ended Canadian Alberta GTN
June 30 Mainline(1) System(2) ANR(3)(4) System(3) Foothills
(unaudited) 2008 2007 2008 2007 2008 2007 2008 2007 2008 2007
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Average
investment base
($ millions) 7,123 7,359 4,286 4,254 n/a n/a n/a n/a 760 816
Delivery volumes
(Bcf)
Total 1,762 1,614 1,930 2,004 881 498 394 371 660 676
Average per day 9.7 8.9 10.6 11.1 4.8 3.9 2.2 2.0 3.6 3.7
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(1) Canadian Mainline's physical receipts originating at the Alberta border
and in Saskatchewan for the six months ended June 30, 2008 were 800
billion cubic feet (Bcf) (2007 - 1,086 Bcf); average per day was 4.4 Bcf
(2007 - 6.0 Bcf).
(2) Field receipt volumes for the Alberta System for the six months ended
June 30, 2008 were 1,919 Bcf (2007 - 2,039 Bcf); average per day was
10.5 Bcf (2007 - 11.3 Bcf).
(3) ANR's and the GTN System's results are not impacted by current average
investment base as these systems operate under a fixed rate model
approved by the FERC.
(4) TransCanada acquired ANR on February 22, 2007.
Other Pipelines
TransCanada's proportionate share of net income from Other Pipelines was $9 million for the three months ended June 30, 2008 compared to $15 million for the same period in 2007. The decrease was primarily due to increased project development costs and the negative impact on earnings of a stronger Canadian dollar.
TransCanada's proportionate share of net income from Other Pipelines was $37 million for the six months ended June 30, 2008 compared to $44 million for the same period in 2007. The decrease was primarily due to increased project development costs and the negative impact on earnings of a stronger Canadian dollar, partially offset by increased earnings from PipeLines LP, reflecting PipeLines LP's increased ownership in Great Lakes and TransCanada's increased ownership in PipeLines LP.
As at June 30, 2008, TransCanada had advanced $140 million to the Aboriginal Pipeline Group with respect to the Mackenzie Gas Pipeline (MGP) project. TransCanada and the other co-venture companies involved in the MGP continue to pursue approval of the proposed project, focusing on the regulatory process and discussions with the Canadian government on fiscal framework. Project timing is uncertain and is conditional upon resolution of regulatory and fiscal matters.
Energy
Energy's net income of $151 million in second-quarter 2008 increased $57 million compared to $94 million in second-quarter 2007. Comparable earnings in second-quarter 2008 of $143 million increased $53 million compared to the same period in 2007 and excluded net unrealized gains of $8 million after tax ($12 million pre-tax) resulting from changes in fair value of proprietary natural gas storage inventory and natural gas forward purchase and sale contracts. Comparable earnings of $90 million in second-quarter 2007 excluded $4 million of favourable income tax adjustments.
Energy's net income for the six months ended June 30, 2008 of $261 million increased $61 million compared to $200 million for the same period in 2007. For the first six months of 2008, comparable earnings of $292 million increased $96 million compared to the same period in 2007 and excluded a $27 million after-tax ($41 million pre-tax) writedown of costs previously capitalized for the Broadwater LNG project and net unrealized losses of $4 million after tax ($5 million pre-tax) resulting from natural gas storage fair value changes. Comparable earnings of $196 million for the first six months of 2007 excluded the $4 million of favourable income tax adjustments.
Energy Results Three months Six months
(unaudited) ended June 30 ended June 30
(millions of dollars) 2008 2007 2008 2007
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Western Power 116 57 194 130
Eastern Power 80 70 165 137
Bruce Power 31 31 68 60
Natural Gas Storage 18 20 66 50
General, administrative, support costs and
other (35) (39) (76) (75)
-----------------------------
Operating income 210 139 417 302
Financial charges (6) (6) (11) (10)
Interest income and other 3 3 4 6
Writedown of Broadwater LNG project costs - - (41) -
Income taxes (56) (42) (108) (98)
-----------------------------
Net Income 151 94 261 200
-----------------------------
-----------------------------
Comparable Earnings 143 90 292 196
Specific items (net of tax, where applicable):
Fair value adjustments of natural gas storage
inventory and forward contracts 8 - (4) -
Writedown of Broadwater LNG project costs - - (27) -
Income tax adjustments - 4 - 4
-----------------------------
Net Income 151 94 261 200
-----------------------------
Western Power
Western Power Results Three months Six months
(unaudited) ended June 30 ended June 30
(millions of dollars) 2008 2007 2008 2007
----------------------------------------------------------------------------
Revenues
Power 283 217 578 498
Other(1) 35 21 52 49
-----------------------------
318 238 630 547
-----------------------------
Commodity purchases resold
Power (124) (131) (294) (305)
Other(2) (21) (12) (34) (35)
-----------------------------
(145) (143) (328) (340)
-----------------------------
Plant operating costs and other (50) (34) (94) (68)
Depreciation (7) (4) (14) (9)
-----------------------------
Operating Income 116 57 194 130
-----------------------------
-----------------------------
(1) Other revenue includes sales of natural gas and thermal carbon black.
(2) Other commodity purchases resold includes the cost of natural gas sold.
Western Power Sales Volumes Three months Six months
(unaudited) ended June 30 ended June 30
(GWh) 2008 2007 2008 2007
---------------------------------------------------------------------------
Supply
Generation 506 531 1,135 1,123
Purchased
Sundance A & B and Sheerness PPAs(1) 2,835 2,877 6,194 6,130
Other purchases 178 416 447 865
------------------------------
3,519 3,824 7,776 8,118
------------------------------
------------------------------
Sales
Contracted 2,819 3,017 5,893 6,509
Spot 700 807 1,883 1,609
------------------------------
3,519 3,824 7,776 8,118
------------------------------
------------------------------
(1) Power purchase arrangements.
Western Power's operating income of $116 million in second-quarter 2008 increased $59 million compared to $57 million in second-quarter 2007. This increase was primarily due to increased margins from the Alberta power portfolio resulting from higher overall realized power prices and market heat rates on both contracted and uncontracted volumes of power sold in Alberta. The market heat rate is determined by dividing the average price of power per megawatt hour (MWh) by the average price of natural gas per gigajoule (GJ) for a given period.
Western Power's revenues increased in second-quarter 2008 compared to second-quarter 2007 as a result of higher overall realized prices, partially offset by slightly lower sales volumes.
Western Power manages the sale of its supply volumes on a portfolio basis. A portion of its supply is held for sale in the spot market for operational reasons and the amount of supply volumes eventually sold into the spot market is dependent upon the ability to transact in forward sales markets at acceptable contract terms. This approach to portfolio management assists in minimizing costs in situations where Western Power would otherwise have to purchase electricity in the open market to fulfill its contractual sales obligations. Approximately 20 per cent of power sales volumes were sold into the spot market in second-quarter 2008 compared to 21 per cent in second-quarter 2007. To reduce its exposure to spot market prices on uncontracted volumes, as at June 30, 2008, Western Power had fixed-price power sales contracts to sell approximately 5,400 gigawatt hours (GWh) for the remainder of 2008 and 7,800 GWh for 2009.
Western Power's operating income for the six months ended June 30, 2008 increased $64 million to $194 million compared to the same period in 2007, primarily due to higher overall realized power prices.
Eastern Power
Eastern Power Results(1) Three months Six months
(unaudited) ended June 30 ended June 30
(millions of dollars) 2008 2007 2008 2007
----------------------------------------------------------------------------
Revenue
Power 263 389 541 743
Other(2) 95 64 177 147
-----------------------------
358 453 718 890
-----------------------------
Commodity purchases resold
Power (105) (183) (241) (360)
Other(2) (96) (67) (162) (125)
-----------------------------
(201) (250) (403) (485)
-----------------------------
Plant operating costs and other (63) (120) (122) (244)
Depreciation (14) (13) (28) (24)
-----------------------------
Operating Income 80 70 165 137
-----------------------------
-----------------------------
(1) Includes Becancour for the six months ended June 30, 2007 and
Anse-a-Valleau effective November 10, 2007.
(2) Other revenue includes sales of natural gas and other commodity
purchases resold includes the cost of natural gas sold.
Eastern Power Sales Volumes(1) Three months Six months
(unaudited) ended June 30 ended June 30
(GWh) 2008 2007 2008 2007
----------------------------------------------------------------------------
Supply
Generation 1,056 2,028 2,142 4,051
Purchased 1,383 1,562 2,907 3,088
-----------------------------
2,439 3,590 5,049 7,139
-----------------------------
-----------------------------
Sales
Contracted 2,371 3,437 4,883 6,794
Spot 68 153 166 345
-----------------------------
2,439 3,590 5,049 7,139
-----------------------------
-----------------------------
(1) Includes Becancour for the six months ended June 30, 2007 and
Anse-a-Valleau effective November 10, 2007.
Eastern Power's operating income of $80 million and $165 million for the three and six months ended June 30, 2008, respectively, increased $10 million and $28 million, respectively, compared to the same periods in 2007. The increases were primarily due to the impact of higher realized power prices in New England and increased sales volumes to wholesale, commercial and industrial New England customers. The agreement to temporarily suspend generation at the Becancour facility beginning January 1, 2008 resulted in decreases to power revenues, plant operating costs and other, generation volumes and contracted sales in 2008. The agreement, however, has not materially affected Eastern Power's operating income due to capacity payments received pursuant to the agreement with Hydro-Quebec.
Eastern Power's power revenues of $263 million decreased $126 million in second-quarter 2008 compared to second-quarter 2007 due to the temporary suspension of generation at the Becancour facility. Power commodity purchases resold of $105 million and purchased power volumes of 1,383 GWh were lower in second-quarter 2008, compared to the same period in 2007. The reduced expense was due to a lower overall cost per GWh on purchased power volumes as well as the lower purchased power volumes. Plant operating costs and other of $63 million, which includes fuel gas consumed in generation, decreased in second-quarter 2008 from the prior year due to the temporary suspension of generation at the Becancour facility.
In second-quarter 2008, approximately three per cent of power sales volumes were sold into the spot market compared to approximately four per cent in second-quarter 2007. Eastern Power is focused on selling the majority of its power under contract to wholesale, commercial and industrial customers, while managing a portfolio of power supplies sourced from its own generation and wholesale power purchases. To reduce its exposure to spot market prices, as at June 30, 2008, Eastern Power had entered into fixed price power sales contracts to sell approximately 4,400 GWh for the remainder of 2008 and 5,700 GWh for 2009, although certain contracted volumes are dependent on customer usage levels.
Bruce Power
Three months Six months
Bruce Power Results ended June 30 ended June 30
(unaudited) 2008 2007 2008 2007
----------------------------------------------------------------------------
Bruce Power (100 per cent basis)
(millions of dollars)
Revenues
Power 492 450 960 910
Other(1) 20 30 37 50
-----------------------------
512 480 997 960
-----------------------------
Operating expenses
Operations and maintenance(2) (304) (259) (582) (554)
Fuel (35) (28) (63) (53)
Supplemental rent(2) (44) (42) (87) (85)
Depreciation and amortization (37) (36) (73) (72)
-----------------------------
(420) (365) (805) (764)
-----------------------------
Operating Income 92 115 192 196
-----------------------------
-----------------------------
TransCanada's proportionate share -
Bruce A 18 2 50 17
TransCanada's proportionate share -
Bruce B 18 35 28 51
-----------------------------
TransCanada's proportionate share 36 37 78 68
Adjustments (5) (6) (10) (8)
-----------------------------
TransCanada's combined operating
income from Bruce Power 31 31 68 60
-----------------------------
-----------------------------
Bruce Power - Other Information
Plant availability
Bruce A 85% 74% 91% 82%
Bruce B 81% 91% 77% 84%
Combined Bruce Power 82% 85% 81% 83%
Planned outage days
Bruce A 26 35 33 50
Bruce B 50 9 100 80
Unplanned outage days
Bruce A 1 7 2 7
Bruce B 15 17 48 21
Sales volumes (GWh)
Bruce A - 100 per cent 2,730 2,410 5,790 5,320
TransCanada's proportionate share 1,330 1,175 2,826 2,591
Bruce B - 100 per cent 5,710 6,370 10,850 11,800
TransCanada's proportionate share 1,804 2,016 3,428 3,729
Combined Bruce Power - 100 per cent 8,440 8,780 16,640 17,120
TransCanada's proportionate share 3,134 3,191 6,254 6,320
Results per MWh
Bruce A power revenues $63 $60 $61 $59
Bruce B power revenues $56 $48 $56 $51
Combined Bruce Power revenues $58 $51 $58 $53
Combined Bruce Power fuel $4 $3 $4 $3
Combined Bruce Power operating
expenses(3) $48 $41 $47 $44
Percentage of output sold to spot
market 22% 47% 25% 41%
-----------------------------
-----------------------------
(1) Other revenue includes Bruce A fuel cost recoveries of $15 million and
$28 million for the three and six months ended June 30, 2008,
respectively ($8 million and $16 million for the three and six months
ended June 30, 2007, respectively). Other revenue also includes losses
of $9 million and $18 million as a result of changes in fair value of
held-for-trading derivatives for the three and six months ended June 30,
2008, respectively (gains of $18 million for the three and six months
ended June 30, 2007).
(2) Includes adjustments to eliminate the effects of inter-partnership
transactions between Bruce A and Bruce B.
(3) Net of fuel cost recoveries.
TransCanada's combined operating income from its investment in Bruce Power was $31 million in second-quarter 2008, which was consistent with the same period in 2007.
TransCanada's proportionate share of operating income in Bruce A increased $16 million to $18 million in second-quarter 2008 compared to second-quarter 2007 as a result of higher output and higher realized prices. Bruce A power prices achieved during second-quarter 2008 were $63 per MWh compared to $60 per MWh in second-quarter 2007.
TransCanada's proportionate share of operating income in Bruce B decreased $17 million to $18 million in second-quarter 2008 compared to second-quarter 2007. Higher realized prices at Bruce B in second-quarter 2008 were more than offset by higher operating costs and lower output due to an increase in planned outage days, as well as an increase in unrealized losses from changes in fair value of electricity swaps and forwards in second-quarter 2008. Bruce B power prices achieved during second-quarter 2008 were $56 per MWh compared to $48 per MWh in second-quarter 2007. The increase was due to higher contract prices on a higher proportion of volumes sold under contract in the three and six months ended June 30, 2008 compared to the same periods in 2007. Also contributing to the increase were higher spot market prices in Ontario, partially offset by lower output for second-quarter 2008.
Bruce Power's combined operating expenses (net of fuel cost recoveries) increased to $48 per MWh in second-quarter 2008 from $41 per MWh in second-quarter 2007 primarily due to higher planned outage costs and lower output.
TransCanada's combined operating income from its investment in Bruce Power for the six months ended June 30, 2008 was $68 million compared to $60 million for the same period in 2007. The increase of $8 million was primarily due to higher realized prices, partially offset by higher operating costs associated with an increase in outage days in 2008 compared to 2007. Increases in TransCanada's combined interest in Bruce Power's operating income were partially offset by lower positive purchase price amortizations related to the expiry of power sales agreements in 2007.
TransCanada's share of Bruce Power's generation for second-quarter 2008 decreased slightly to 3,134 GWh compared to 3,191 GWh in second-quarter 2007. The Bruce units ran at a combined average availability of 82 per cent in second-quarter 2008, compared to an 85 per cent average availability in second-quarter 2007. The lower availability in second-quarter 2008 was the result of more planned maintenance outage days at Bruce B, partially offset by fewer unplanned outage days at both Bruce A and Bruce B. As a result of actual plant outages to date, the overall plant availability percentage in 2008 is currently expected to be in the high 80s for the four Bruce B units and the mid 80s for the two operating Bruce A units.
Pursuant to the terms of a contract with the Ontario Power Authority (OPA), all of the output from Bruce A in second-quarter 2008 was sold at a fixed price of $63.00 per MWh (before recovery of fuel costs from the OPA) compared to $59.69 per MWh in second-quarter 2007. In addition, sales from the Bruce B Units 5 to 8 were subject to a floor price of $47.66 per MWh in second-quarter 2008 and $46.82 per MWh in second-quarter 2007. Both the Bruce A and Bruce B reference prices are adjusted annually for inflation on April 1. 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 income has not included any amounts received under this floor price mechanism to date. To further reduce its exposure to spot market prices, as at June 30, 2008, Bruce B had entered into fixed price sales contracts to sell forward approximately 8,630 GWh for the remainder of 2008 and 9,680 GWh for 2009.
The capital cost of Bruce A's refurbishment and restart of Units 1 and 2 is currently estimated by Bruce Power to total approximately $3.1 billion to $3.4 billion, with TransCanada's share being approximately $1.55 billion to $1.7 billion. As at June 30, 2008, Bruce A had incurred $2.2 billion in costs with respect to the refurbishment and restart of Units 1 and 2, and approximately $0.2 billion for the refurbishment of Units 3 and 4.
Power Plant Availability
Weighted Average Power Plant Availability(1)
Three months Six months
ended June 30 ended June 30
(unaudited) 2008 2007 2008 2007
----------------------------------------------------------------------------
Western Power(2) 78% 89% 85% 94%
Eastern Power(3) 96% 93% 95% 96%
Bruce Power 82% 85% 81% 83%
All plants, excluding Bruce Power investment 92% 91% 93% 95%
All plants 88% 89% 88% 90%
-----------------------------
-----------------------------
(1) Plant availability represents the percentage of time in the period that
the plant is available to generate power, whether actually running or
not, reduced by planned and unplanned outages.
(2) Western Power plant availability decreased in the three and six months
ended June 30, 2008 due to an outage at the Cancarb power facility.
(3) Eastern Power includes Becancour for the six months ended June 30, 2007
and Anse-a-Valleau effective November 10, 2007.
Natural Gas Storage
Natural Gas Storage operating income of $18 million in second-quarter 2008 decreased $2 million compared to $20 million in second-quarter 2007. Operating income in second-quarter 2008 included $8 million after tax ($12 million pre-tax) of net unrealized gains resulting from the changes in fair value of proprietary natural gas inventory in storage and natural gas forward purchase and sale contracts. These unrealized gains were more than offset by the effects of lower realized seasonal natural gas price spreads at the Edson and CrossAlta facilities compared to the same period in 2007. Natural Gas Storage operating income of $66 million for the six months ended June 30, 2008, which included $4 million after tax ($5 million pre-tax) of net unrealized losses arising from fair value changes, was $16 million higher than the same period in 2007. The increase was primarily due to the Edson facility, which was fully operational in first-quarter 2008, but only in a commissioning phase in first-quarter 2007.
For the first six months of 2008, TransCanada excluded from Natural Gas Storage's comparable earnings changes in fair value of proprietary natural gas inventory and forward purchase and sale contracts. TransCanada simultaneously enters into a forward purchase of natural gas for injection into storage and an offsetting forward sale of natural gas for withdrawal at a later period, thereby locking in future positive margins and effectively eliminating exposure to price movements of natural gas. As a result, changes in fair value of proprietary natural gas inventory and these forward contracts do not reflect the amounts that will be realized upon settlement of the forward contracts. The natural gas storage business earns the majority of its revenues on proprietary inventories when the inventory is sold, which typically occurs during the winter withdrawal season.
Corporate
Corporate's net income for the three months ended June 30, 2008 was $15 million compared to net expenses of $3 million for the same period in 2007. The $18-million increase in second-quarter 2008 net income was primarily due to a reduction in financial charges as a result of lower average short-term debt balances, increased capitalization of interest to finance a larger capital spending program, higher interest income on short-term intersegment financings and higher gains on derivatives used to manage the Company's exposure to interest rate fluctuations. These increases were partially offset by lower gains on derivatives used to manage the Company's exposure to foreign exchange rate fluctuations and $12 million of favourable income tax adjustments in second-quarter 2007. Corporate's comparable expenses of $15 million in second-quarter 2007 excluded the $12 million of favourable income tax adjustments.
Corporate's net expenses for the six months ended June 30, 2008 were $7 million compared to net income of $1 million for the same period in 2007. Excluding $27 million of favourable income tax adjustments recorded in 2007, Corporate's comparable expenses were $7 million and $26 million for the six months ended June 30, 2008 and 2007, respectively. Corporate's comparable expenses for the six months ended June 30, 2008 decreased due to the factors discussed above.
Liquidity and Capital Resources
At June 30, 2008, the Company held cash and cash equivalents of $1.96 billion compared to $504 million at December 31, 2007. The increase in cash and cash equivalents was due primarily to approximately $1.27 billion of gross proceeds from the issuance of common shares in second-quarter 2008.
Funds Generated from Operations Three months Six months
(unaudited) ended June 30 ended June 30
(millions of dollars) 2008 2007 2008 2007
---------------------------------------------------------------------------
Cash Flows
Funds generated from operations(1) 676 596 1,598 1,178
(Increase)/decrease in operating
working capital (104) 93 (98) 129
--------------------------------
Net cash provided by operations 572 689 1,500 1,307
--------------------------------
--------------------------------
(1) For further discussion on funds generated from operations, refer to the
Non-GAAP Measures section in this MD&A.
Net cash provided by operations decreased $117 million in second-quarter 2008 and increased $193 million for the first six months of 2008 compared to the same periods in 2007. Funds generated from operations were $676 million and $1.6 billion for the three and six months ended June 30, 2008, respectively, compared to $596 million and $1.2 billion for the same periods in 2007. The increases were primarily due to gains from the Calpine bankruptcy settlements and higher earnings.
The Ravenswood Generating Facility (Ravenswood) acquisition, discussed further in the Other Recent Developments section in this MD&A, is expected to be financed in a manner consistent with TransCanada's current capital structure. TransCanada expects that both 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 remain substantially unchanged since December 31, 2007.
Investing Activities
Acquisitions, net of cash acquired, for the six months ended June 30, 2008 were $4 million compared to $4.2 billion for the same period in 2007. Acquisitions for the first six months of 2007 included TransCanada's acquisition of ANR and an additional 3.6 per cent interest in Great Lakes for approximately US$3.4 billion, including US$491 million of assumed long-term debt, as well as PipeLines LP's acquisition of a 46.4 per cent interest in Great Lakes for approximately US$942 million, including US$209 million of assumed long-term debt.
For the three and six months ended June 30, 2008, capital expenditures totalled $633 million (2007 - $386 million) and $1.1 billion (2007 - $692 million), respectively, and primarily related to the expansion of the Alberta System, refurbishment and restart of Bruce A Units 1 and 2, construction of new power plants in Energy and construction of the Keystone oil pipeline.
Financing Activities
In the three and six months ended June 30, 2008, TransCanada retired $379 million and $773 million of long-term debt, respectively ($470 million and $795 million in the three and six months ended June 30, 2007, respectively), and issued nil and $112 million of long-term debt, respectively ($1.2 billion and $2.6 billion of long-term debt and junior subordinated notes, respectively). TransCanada's notes payable increased $754 million and $724 million in the three and six months ended June 30, 2008, respectively, primarily due to an increase in commercial paper issued by the Company to finance general operations, compared to a decrease of $804 million and an increase of $261 million in the three and six months ended June 30, 2007, respectively.
On July 2, 2008, TransCanada filed a final short form base 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 August 2010. The filing was done in normal course similar to the filing of debt shelf prospectuses in Canada and the U.S. so as to expedite access to the capital markets depending on TransCanada's assessment of its requirements for funding and general market conditions. This new shelf prospectus replaces the previous $3.0 billion short form shelf prospectus filed in January 2007 under which the Company had issued approximately $3.0 billion of common shares.
On June 27, 2008, TransCanada executed an agreement with a syndicate of banks for a US$1.5 billion, committed, unsecured, one-year bridge loan facility, which will be at a floating interest rate based on the London Interbank Offered Rate. The facility is extendible at the option of the Company for an additional six-month term and is available to fund a portion of the pending Ravenswood acquisition. No funds have been drawn on this facility at this time.
On May 5, 2008, TransCanada entered into an agreement with a syndicate of underwriters under which the underwriters agreed to purchase 30,200,000 common shares from TransCanada and sell them to the public at a price of $36.50 each. The underwriters also fully exercised an over-allotment option which they were granted for an additional 4,530,000 common shares at the same price. The entire issue of the 34,730,000 common shares closed on May 13, 2008 and resulted in gross proceeds to TransCanada of approximately $1.27 billion. These proceeds will be used to partially fund acquisitions and capital projects of the Company, including the acquisition of Ravenswood and the construction of Keystone, and for general corporate purposes.
In the three and six months ended June 30, 2008, TransCanada issued 1.7 million and 3.1 million common shares, respectively, under its Dividend Reinvestment and Share Purchase Plan (DRP). In accordance with the DRP, dividends were paid with common shares issued from treasury in lieu of making cash dividend payments totalling $58 million and $112 million. In the three and six months ended June 30, 2007, TransCanada issued 1.3 million common shares under its DRP, in lieu of making cash dividend payments totalling $51 million.
Dividends
On July 31, 2008, TransCanada's Board of Directors declared a quarterly dividend of $0.36 per share for the quarter ending September 30, 2008 on the Company's outstanding common shares. It is payable on October 31, 2008 to shareholders of record at the close of business on September 30, 2008.
TransCanada's Board of Directors also approved the issuance of common shares from treasury at a two per cent discount under TransCanada's DRP for the dividends payable on October 31, 2008. 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 Accounting Policies have not changed materially from those described in TransCanada's 2007 Annual Report.
Future Accounting Changes
International Financial Reporting Standards
The Canadian Institute of Chartered Accountants' Accounting Standards Board (AcSB) announced that Canadian publicly accountable enterprises are required to adopt International Financial Reporting Standards (IFRS), as issued by the International Accounting Standards Board (IASB), effective January 1, 2011. In June 2008, the Canadian Securities Administrators (CSA) proposed that Canadian public companies which are also SEC registrants, such as TransCanada, could retain the option to prepare their financial statements under U.S. GAAP instead of IFRS. TransCanada is currently assessing its option to adopt IFRS as of January 1, 2011 and the impact that such a conversion would have on its accounting systems and financial statements. TransCanada's conversion planning includes an analysis of project structure and governance, resourcing and training, analysis of key GAAP differences and a phased approach to assess accounting policies under IFRS.
Under existing Canadian GAAP, TransCanada follows specific accounting policies unique to a rate-regulated business. TransCanada is actively monitoring ongoing discussions and developments of the IASB and its International Financial Reporting Interpretations Committee regarding potential future guidance to clarify the applicability of certain aspects of rate-regulated accounting under IFRS.
Contractual Obligations
The Company is committed to acquiring the Ravenswood power facility in New York City from National Grid plc (National Grid) for approximately US$2.8 billion plus closing adjustments, as discussed in the Other Recent Developments section of this MD&A. In addition, as at June 30, 2008, TransCanada had entered into agreements to purchase construction materials and services for the Kibby Wind and Coolidge power projects, totalling approximately $625 million. Other than these commitments, there have been no other material changes to TransCanada's contractual obligations from December 31, 2007 to June 30, 2008, 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 2007 Annual Report.
Contingencies
On April 3, 2008, the Ontario Court of Appeal dismissed an appeal filed by the Canadian Alliance of Pipeline Landowners' Associations (CAPLA). CAPLA filed the appeal as a result of a decision by the Ontario Superior Court in November 2006 to dismiss CAPLA's class action lawsuit against TransCanada and Enbridge Inc. for damages alleged to have arisen from the creation of a control zone within 30 metres of a pipeline pursuant to Section 112 of the National Energy Board Act. The Ontario Court of Appeal's decision is final and binding as CAPLA did not seek any further appeal within the time frame allowed.
Financial Instruments and Risk Management
Natural Gas Inventory
At June 30, 2008, $240 million of proprietary natural gas inventory held in storage was included in Inventories (December 31, 2007 - $190 million). Effective April 1, 2007, TransCanada began valuing its proprietary natural gas inventory at fair value, as measured by the one-month forward price for natural gas less selling costs. The Company did not have any proprietary natural gas inventory prior to April 1, 2007. The change in fair value of proprietary natural gas inventory in the three and six months ended June 30, 2008 resulted in net unrealized gains of $42 million and $102 million, respectively, which were recorded as an increase to Revenues and Inventory (three and six months ended June 30, 2007 - net unrealized losses of $23 million). The net change in fair value of natural gas forward purchase and sales contracts in the three and six months ended June 30, 2008 resulted in net unrealized losses of $30 million and $107 million, respectively (three and six months ended June 30, 2007 - net unrealized gains of $19 million and $16 million, respectively), which were included in Revenues.
Net Investment in Self-Sustaining Foreign Operations
Information for the derivatives used to hedge the Company's net investment in its foreign operations is as follows:
Derivatives Hedging Net Investment in Foreign Operations
Asset/(Liability)
(unaudited)
(millions of dollars) June 30, 2008 December 31, 2007
----------------------------------------------------------------------------
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 2009 to 2014) 75 U.S. 1,050 77 U.S. 350
U.S. dollar forward foreign
exchange contracts
(maturing 2008) (5) U.S. 730 (4) U.S. 150
U.S. dollar options
(maturing 2008) - U.S. 100 3 U.S. 600
-----------------------------------------
70 U.S. 1,880 76 U.S. 1,100
-----------------------------------------
-----------------------------------------
(1) Fair values are equal to carrying values.
Derivative Financial Instruments Summary
Information for the Company's derivative financial instruments is as follows:
June 30, 2008
(all amounts in millions unless Natural
otherwise indicated) Power Gas Interest
----------------------------------------------------------------------------
Derivative Financial Instruments
Held for Trading
Fair Values(1)
Assets $ 104 $ 169 $ 26
Liabilities $ (103) $ (258) $ (26)
Notional Values
Volumes(2)
Purchases 2,955 48 -
Sales 3,301 65 -
Canadian dollars - - 857
U.S. dollars - - U.S. 1,150
Unrealized (losses)/gains in the
period(3)
Three months ended June 30, 2008 $ (3) $ 7 $ 2
Six months ended June 30, 2008 $ (5) $ (11) $ (2)
Realized gains/(losses) in the
period(3)
Three months ended June 30, 2008 $ 7 $ (20) $ 7
Six months ended June 30, 2008 $ 9 $ 5 $ 10
Maturity dates 2008-2014 2008-2010 2008-2018
Derivative Financial Instruments
in Hedging Relationships(4)(5)
Fair Values(1)
Assets $ 250 $ 80 $ 3
Liabilities $ (236) $ - $ (17)
Notional Values
Volumes(2)
Purchases 6,126 23 -
Sales 17,727 - -
Canadian dollars - - 50
U.S. dollars - - U.S. 925
Realized (losses)/gains in the
period(3)
Three months ended June 30, 2008 $ (37) $ 11 $ (3)
Six months ended June 30, 2008 $ (38) $ 19 $ (2)
Maturity dates 2008-2014 2008-2011 2009-2013
(1) Fair value is equal to the carrying value of these derivatives.
(2) Volumes for power and natural gas derivatives are in Gwh and Bcf,
respectively.
(3) All realized and unrealized gains and losses are included in Net Income.
Realized gains and losses are included in Net Income after the financial
instrument has been settled.
(4) All hedging relationships are designated as cash flow hedges except for
$2 million (December 31, 2007 - $2 million) of interest-rate derivative
financial instruments designated as fair value hedges.
(5) Net Income for the three and six months ended June 30, 2008 included
losses of $3 million and $4 million, respectively (three and six months
ended June 30, 2007 - nil and $3 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
underlying positions. Net Income for the three and six months ended
June 30, 2007 included nil and a $4 million loss, respectively, for the
changes in fair value of an interest-rate cash flow hedge that was
reclassified as a result of discontinuance of cash flow hedge
accounting. Cash flow hedge accounting was discontinued when the
anticipated transaction was not probable of occurring by the end of the
originally specified time period. There were no gains or losses
included in Net Income for the three and six months ended June 30,
2008 for discontinued cash flow hedges.
2007
(all amounts in millions unless
Otherwise indicated) Power Natural Gas Interest
----------------------------------------------------------------------------
Derivative Financial Instruments
Held for Trading
Fair Values(1)(4)
Assets $ 55 $ 43 $ 23
Liabilities $ (44) $ (19) $ (18)
Notional Values(4)
Volumes(2)
Purchases 3,774 47 -
Sales 4,469 64 -
Canadian dollars - - 615
U.S. dollars - - U.S. 550
Unrealized gains/(losses)
in the period(3)
Three months ended
June 30, 2007 $ 5 $ 1 $ (2)
Six months ended June 30, 2007 $ 9 $ (16) $ 1
Realized (losses)/gains in the
period(3)
Three months ended
June 30, 2007 $ (3) $ 6 $ 1
Six months ended
June 30, 2007 $ (8) $ 18 $ 1
Maturity dates (4) 2008 - 2012 2008 - 2010 2008 - 2016
Derivative Financial Instruments
in Hedging Relationships(5)(6)
Fair Values(1)(4)
Assets $ 135 $ 19 $ 2
Liabilities $ (104) $ (7) $ (16)
Notional Values(4)
Volumes(2)
Purchases 7,362 28 -
Sales 16,367 4 -
Canadian dollars - - 150
U.S. dollars - - U.S. 875
Realized gains/(losses) in the
period(3)
Three months ended
June 30, 2007 $ 16 $ (1) $ 1
Six months ended June 30, 2007 $ 13 $ (3) $ 1
Maturity dates(4) 2008 - 2013 2008 - 2010 2008 - 2013
(1) Fair value is equal to the carrying value of these derivatives.
(2) Volumes for power and natural gas derivatives are in Gwh and Bcf,
respectively.
(3) All realized and unrealized gains and losses are included in Net Income.
Realized gains and losses are included in Net Income after the financial
instrument has been settled.
(4) As at December 31, 2007.
(5) All hedging relationships are designated as cash flow hedges except for
$2 million (December 31, 2007 - $2 million) of interest-rate derivative
financial instruments designated as fair value hedges.
(6) Net Income for the three and six months ended June 30, 2008 included
losses of $3 million and $4 million, respectively (three and six months
ended June 30, 2007 - nil and $3 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
underlying positions. Net Income for the three and six months ended
June 30, 2007 included nil and a $4 million loss, respectively, for the
changes in fair value of an interest-rate cash flow hedge that was
reclassified as a result of discontinuance of cash flow hedge
accounting. Cash flow hedge accounting was discontinued when the
anticipated transaction was not probable of occurring by the end of
the originally specified time period. There were no gains or
losses included in Net Income for the three and six months ended June
30, 2008 for discontinued cash flow hedges.
Other Risks
Additional risks faced by the Company are discussed in the MD&A in TransCanada's 2007 Annual Report. These risks remain substantially unchanged since December 31, 2007.
Controls and Procedures
As of June 30, 2008, an evaluation was carried out under the supervision of, and with the participation of management, including the President and Chief Executive Officer, and the Executive Vice-President and Chief Financial Officer, of the effectiveness of TransCanada's disclosure controls and procedures as defined under the rules adopted by the Canadian securities regulatory authorities and by the SEC. Based on this evaluation, the President and Chief Executive Officer, and the Executive Vice-President and Chief Financial Officer concluded that the design and operation of TransCanada's disclosure controls and procedures were effective as at June 30, 2008.
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.
Significant Accounting Policies and Critical Accounting Estimates
To prepare financial statements that conform with Canadian GAAP, TransCanada is required to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be dependent on future events. The Company uses the most current information available and exercises careful judgement in making these estimates and assumptions.
TransCanada's significant accounting policies and critical accounting estimates have remained unchanged since December 31, 2007 and are the use of regulatory accounting for the Company's rate-regulated operations and the policies the Company adopts to account for financial instruments and depreciation and amortization expense. For further information on the Company's accounting policies and estimates refer to the MD&A in TransCanada's 2007 Annual Report.
Outlook
Since the disclosure in TransCanada's 2007 Annual Report, the Company's earnings outlook is relatively unchanged except for the Calpine bankruptcy settlements, the writedown of the Broadwater LNG project costs and the anticipated effect on earnings for the recently-announced acquisition of Ravenswood, which the Company expects to close in third-quarter 2008. The Company expects Ravenswood to be modestly dilutive to TransCanada's earnings in the first two full years of ownership based on the near-term effects of a FERC order pertaining to the New York Independent System Operator (New York City) capacity market. TransCanada expects Ravenswood's contribution to TransCanada's earnings to be accretive in subsequent years. The Ravenswood acquisition is discussed further in the Other Recent Developments section of this MD&A. For further information on outlook, refer to the MD&A in TransCanada's 2007 Annual Report.
Following the announcement of the Ravenswood acquisition, Standard & Poor's (S&P), DBRS and Moody's Investors Service (Moody's) conducted and completed reviews of their various TransCanada group company credit ratings. The senior unsecured debt of TCPL and its rated subsidiaries was affirmed at 'A-' and 'A' by S&P and DBRS, respectively, but lowered by Moody's from 'A2' to 'A3'. Moody's also reduced their short-term debt rating of TCPL to 'Prime-2 (A)' and issuer rating of TransCanada Corporation to 'Baa1'. All three agencies have assigned a stable outlook to their TransCanada group ratings.
Other Recent Developments
Pipelines
Canadian Mainline
On June 27, 2008, the NEB approved TransCanada's application for 2008 final tolls on the Canadian Mainline, effective July 1, 2008.
Alberta System
In March 2008, TransCanada reached a settlement agreement with stakeholders on the Alberta System and filed a 2008-2009 Revenue Requirement Settlement Application with the AUC. TransCanada is currently responding to information requests from the AUC in regard to the settlement. TransCanada expects approval of the settlement in third-quarter 2008.
On July 25, 2008, the Alberta Utilities Commission (AUC) issued a Notice of Application and Hearing Order, which details the preliminary scope and minimum filing requirements for a Generic Cost of Capital proceeding to review the level of the generic ROE for 2009, the generic ROE adjustment mechanism and capital structure of utilities on a utility-specific basis. The hearing commencement date was set for February 23, 2009.
On June 17, 2008, TransCanada filed an application with the NEB to establish federal jurisdiction over the Alberta System. On July 18, 2008, the NEB announced it would hold an oral hearing to discuss this matter commencing November 18, 2008. A decision on the application is expected to be issued in first-quarter 2009. Currently, the provincial regulation of the Alberta System precludes TransCanada from acquiring, constructing or operating facilities that transport natural gas across Alberta provincial borders. Federal regulation would enable the Alberta System to extend across provincial borders, thereby providing integrated service to Alberta and British Columbia customers, and Northern natural gas producers.
In November 2007, TransCanada submitted an application to the Alberta Energy and Utilities Board for a permit to construct an approximately $1 billion North Central Corridor expansion, which comprises a 300-kilometre (km) natural gas pipeline and associated facilities on the northern section of the Alberta System. On April 14, 2008, the AUC held a pre-hearing meeting with all interested parties to discuss procedural matters including scope, purpose, timing and location of the hearing. On April 24, 2008, the AUC issued a decision on the pre-hearing meeting, which established a hearing date for this application that commenced on July 28, 2008.
Keystone Oil Pipeline
In May 2008, construction began on the initial phase of the Keystone oil pipeline project in both Canada and the U.S., which will transport crude oil from Hardisty, Alberta to U.S. Midwest markets at Wood River and Patoka, Illinois. Deliveries to Wood River and Patoka are expected to commence in late 2009. Deliveries for phase two of the project, which will provide service to Cushing, Oklahoma, are expected to commence in late 2010.
On June 23, 2008, the NEB issued a decision to approve TransCanada's application for additional pumping facilities required to expand the Canadian portion of the Keystone oil pipeline project from a nominal capacity of approximately 435,000 Bbl/d to 590,000 Bbl/d.
On July 16, 2008, TransCanada announced plans to expand and extend the Keystone crude oil pipeline system and provide additional capacity in 2012 of 500,000 barrels per day (Bbl/d) from Western Canada to the U.S. Gulf coast, near existing terminals in Port Arthur, Texas. The expansion is expected to cost approximately US$7.0 billion and, when completed, is expected to increase the Keystone oil pipeline system from 590,000 Bbl/d to approximately 1.1 million Bbl/d and is expected to result in a total capital investment of approximately US$12.2 billion. Construction of the expansion facilities is anticipated to commence in 2010 following the receipt of the necessary regulatory approvals. Keystone has secured long-term commitments for approximately 830,000 Bbl/d for an average term of 18 years.
The Keystone project is a 50/50 partnership between TransCanada and ConocoPhillips, however, certain parties who have agreed to make volume commitments to the Keystone expansion have an option to acquire up to a combined 15 per cent equity ownership in the Keystone partnerships.
Sunstone Pipeline Project
TransCanada and Williams Companies, Inc. (Williams) continue to evaluate the development of the Sunstone pipeline project, a proposed 943-km pipeline from Wyoming to Stanfield, Oregon, with capacity of up to 1.2 billion cubic feet per day (Bcf/d). In June 2008, the joint venture concluded an open season and executed a Memorandum of Understanding with Sempra Pipelines and Storage (Sempra) whereby Sempra may acquire 25 per cent of the equity of the Sunstone pipeline and a Sempra affiliate would become a shipper on the Sunstone pipeline. Assuming Sempra's participation, TransCanada and Williams would each hold 37.5 percent of the joint venture. The project is targeted to be placed in service in November 2011.
Pathfinder Pipeline Project
TransCanada is evaluating the development of the Pathfinder pipeline project, a proposed 1,030-km pipeline from Meeker, Colorado to the Northern Border system, with an initial capacity of 1.2 Bcf/d and an ultimate capacity of 2.0 Bcf/d. Enterprise Products Partners L.P. and Quicksilver Gas Services LP have agreed to ship a total of 500 million cubic feet per day (mmcf/d) for a 10-year term and to acquire up to an aggregate 50 percent ownership in the proposed Pathfinder pipeline project. TransCanada is currently reviewing bids received during a binding open season, for capacity on the Pathfinder pipeline, that concluded on June 27, 2008. The Pathfinder project is targeting to provide capacity exiting the U.S. Rocky Mountain Basin by the end of 2010.
Bison Pipeline Project
Northern Border is evaluating the development of the Bison pipeline project, a proposed 465-km pipeline from Dead Horse, Wyoming to the Northern Border system, with an initial capacity of 400 mmcf/d and an ultimate capacity of 660 mmcf/d. A binding open season for capacity on the Bison pipeline project concluded on May 23, 2008. Bison Pipeline Company LLC, a wholly owned subsidiary of Northern Border, is currently working to address bid contingencies. Northern Border will assess the project again once all bids have been finalized.
Portland Rate Case
On April 1, 2008, Portland filed a general rate case with the FERC proposing a rate increase of approximately six per cent, as well as other changes to its tariffs. The proposed tariffs are expected to go into effect on September 1, 2008, subject to refund, per the FERC's Suspension Order dated May 1, 2008. The hearing is scheduled to begin on March 10, 2009.
Alaska Pipeline Project
On July 23, 2008, TransCanada's application for a license to construct the Alaska pipeline project under the Alaska Gasline Inducement Act (AGIA) was approved by the Alaska House of Representatives. A positive Alaska Senate vote is a necessary condition for the issuance of the license. A vote by the Senate is anticipated by August 2, 2008. Although no other applicant met all the AGIA requirements, in April 2008, BP p.l.c. and ConocoPhillips proposed an alternative Alaska pipeline project. TransCanada continues to work with the State of Alaska and the Alaska producers to advance its Alaska pipeline project.
Energy
Ravenswood Acquisition
On March 31, 2008, TransCanada announced that a subsidiary of the Company entered into an agreement to acquire all of the outstanding membership interests of KeySpan-Ravenswood, LLC and all of the outstanding shares of KeySpan Ravenswood Services Corp. from National Grid. KeySpan-Ravenswood, LLC directly or indirectly owns or controls the 2,480-megawatt (MW) Ravenswood facility located in Queens, New York. The purchase price is approximately US$2.8 billion plus closing adjustments.
On June 18, 2008, the FERC issued an order authorizing the Company's acquisition of Ravenswood. On May 21, 2008, the U.S. Department of Justice and the U.S. Federal Trade Commission granted the Company's Request for Early Termination of the waiting period under the pre-merger notification rules. This acquisition remains subject to New York Public Service Commission approval and is expected to close in third-quarter 2008.
Coolidge Power Project
On May 12, 2008, TransCanada announced that the Phoenix, Arizona-based utility Salt River Project signed a 20-year PPA to secure 100 per cent of the output from TransCanada's planned Coolidge Generating Station.
The simple-cycle natural gas-fired peaking power facility is expected to be located in Coolidge, Arizona. This project is expected to have a capital cost of approximately US$500 million and a nominal capacity of 575 MW. TransCanada has filed a Notice of Application with the Arizona Corporation Commission and is expected to file a full application for a Certificate of Environmental Compatibility in third-quarter 2008. Subject to receipt of required permits, construction is scheduled to begin in late 2009, with an expected in-service date of May 2011, in time to meet peak power demand.
Kibby
On July 9, 2008, TransCanada announced that the Kibby Wind power project received unanimous final development plan approval from the State of Maine's Land Use Regulation Commission. Construction plans are now underway for the 132-MW wind project located in the Kibby and Skinner Townships in northwestern Franklin County, Maine. The project is expected to have a capital cost of approximately US$320 million. Pending all remaining regulatory approvals, construction is expected to begin in third-quarter 2008 and the project is expected to be fully commissioned in 2010.
Portlands Energy Centre
On May 30, 2008, the Portlands Energy Centre natural gas-fired combined-cycle power plant near downtown Toronto, Ontario went into service in simple-cycle mode on time and on budget. The power plant, which is 50 per cent owned by TransCanada, is currently able to provide 340 MW of electricity under long-term contract. In September 2008, the power plant is expected to return to the construction phase and is expected to be fully commissioned in combined-cycle mode in second-quarter 2009 with delivery capabilities of 550 MW of power.
Becancour Power Plant Temporary Suspension
On July 4, 2008, Hydro-Quebec notified the Regie de l'energie that it will exercise its option to extend the temporary suspension of all electricity generation from TransCanada's Becancour power plant through 2009. The extension of the temporary suspension, which is subject to the approval of the Regie de l'energie, will result in TransCanada receiving payments under the agreement in 2009 similar to those that would have been received under the normal course of operations.
Broadwater
On June 6, 2008, Broadwater Energy, LLC (Broadwater) filed an appeal with the U.S. Secretary of Commerce related to New York State's Department of State's (NYSDOS) April 10, 2008 rejection of a proposal to construct the Broadwater LNG facility. Broadwater's appeal was filed based on the view that the NYSDOS relied on improper considerations in making its determination. The appeal asks the Secretary of Commerce to override the NYSDOS determination on the grounds that the project meets the criteria for approval under the Coastal Zone Management Act and applicable regulations.
Share Information
As at June 30, 2008, TransCanada had 578 million issued and outstanding common shares. In addition, there were 9 million outstanding options to purchase common shares, of which 7 million were exercisable as at June 30, 2008.
Selected Quarterly Consolidated Financial Data(1)
(unaudited)
(millions
of
dollars
except
per
share 2008 2007 2006
amounts) Second First Fourth Third Second First Fourth Third
----------------------------------------------------------------------------
Revenues 2,017 2,133 2,189 2,187 2,208 2,244 2,091 1,850
Net Income 324 449 377 324 257 265 269 293
Share
Statistics
Net income
per share
- Basic $ 0.58 $ 0.83 $ 0.70 $ 0.60 $ 0.48 $ 0.52 $ 0.55 $ 0.60
Net income
per share
- Diluted $ 0.58 $ 0.83 $ 0.70 $ 0.60 $ 0.48 $ 0.52 $ 0.54 $ 0.60
Dividend
declared
per common
share $ 0.36 $ 0.36 $ 0.34 $ 0.34 $ 0.34 $ 0.34 $ 0.32 $ 0.32
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The selected quarterly consolidated financial data has been prepared in
accordance with Canadian GAAP. Certain comparative figures have been
reclassified to conform with the current year's presentation.
Factors Impacting Quarterly Financial Information
In Pipelines, which consists primarily of the Company's investments in regulated pipelines and regulated natural gas storage facilities, annual revenues and net income fluctuate over the long term based on regulators' decisions and negotiated settlements with shippers. Generally, quarter-over-quarter revenues and net income during any particular fiscal year remain relatively stable with fluctuations resulting from adjustments being recorded due to regulatory decisions and negotiated settlements with shippers, seasonal fluctuations in short-term throughput on U.S. pipelines, acquisitions and divestitures, and developments outside of the normal course of operations.
In Energy, which consists primarily of the Company's investments in electrical power generation plants and non-regulated natural gas storage facilities, quarter-over-quarter revenues and net income are affected by seasonal weather conditions, customer demand, market prices, planned and unplanned plant outages, acquisitions and divestitures, and developments outside of the normal course of operations.
Significant developments that impacted the last eight quarters' net income are as follows:
- Third-quarter 2006 net income included an income tax benefit of approximately $50 million as a result of the resolution of certain income tax matters with taxation authorities and changes in estimates. Energy's net income included earnings from Becancour, which came into service September 17, 2006.
- Fourth-quarter 2006, net income included approximately $12 million related to income tax refunds and related interest.
- First-quarter 2007 net income included $15 million related to favourable income tax adjustments. In addition, Pipelines' net income included contributions from the February 22, 2007 acquisitions of ANR and additional ownership interests in Great Lakes. Energy's net income included earnings from the Edson natural gas facility, which was placed in service on December 31, 2006.
- Second-quarter 2007 net income included $16 million ($12 million in Corporate and $4 million in Energy) related to favourable income tax adjustments resulting from reductions in Canadian federal income tax rates. Pipelines' net income increased as a result of a settlement reached on the Canadian Mainline, which was approved by the NEB in May 2007.
- Third-quarter 2007 net income included $15 million of favourable income tax reassessments and associated interest income relating to prior years.
- Fourth-quarter 2007 net income included $56 million ($30 million in Energy and $26 million in Corporate) of favourable income tax adjustments resulting from reductions in Canadian federal income tax rates and other legislative changes, and a $14 million after-tax ($16 million pre-tax) gain on sale of land previously held for development. Pipelines' net income increased as a result of recording incremental earnings related to the rate case settlement reached for the GTN System, effective January 1, 2007.
- First-quarter 2008, Pipelines' net income included $152 million after tax ($240 million pre-tax) from the Calpine bankruptcy settlements received by GTN and Portland, and proceeds from a lawsuit settlement of $10 million after tax ($17 million pre-tax). Energy's net income included a writedown of costs related to the Broadwater LNG project of $27 million after tax ($41 million pre-tax) and net unrealized losses of $12 million after tax ($17 million pre-tax) due to changes in fair value of proprietary natural gas storage inventory and natural gas forward purchase and sale contracts. Beginning in first-quarter 2008, the temporary suspension of generation at the Becancour facility reduced Eastern Power's revenues, however, net income was not materially impacted due to capacity payments received pursuant to an agreement with Hydro-Quebec.
- Second-quarter 2008, Energy's net income included net unrealized gains of $8 million after tax ($12 million pre-tax) due to changes in fair value of proprietary natural gas storage inventory and natural gas forward purchase and sale contracts. In addition, Western Power's revenues and operating income increased due to higher overall realized prices and market heat rates in Alberta.
Consolidated Income
(unaudited) Three months Six months
(millions of dollars except per share ended June 30 ended June 30
amounts) 2008 2007 2008 2007
----------------------------------------------------------------------------
Revenues 2,017 2,208 4,150 4,452
Operating Expenses
Plant operating costs and other 733 761 1,431 1,493
Commodity purchases resold 347 523 757 1,094
Depreciation 301 300 597 590
-----------------------------------
1,381 1,584 2,785 3,177
-----------------------------------
636 624 1,365 1,275
-----------------------------------
Other Expenses/(Income)
Financial charges 186 264 404 501
Financial charges of joint ventures 17 19 33 40
Interest income and other (34) (48) (73) (79)
Calpine bankruptcy settlements - - (279) -
Writedown of Broadwater LNG project costs - - 41 -
-----------------------------------
169 235 126 462
-----------------------------------
Income before Income Taxes and
Non-Controlling Interests 467 389 1,239 813
Income Taxes
Current 105 96 352 264
Future 21 16 26 (21)
-----------------------------------
126 112 378 243
-----------------------------------
Non-Controlling Interests
Preferred share dividends of subsidiary 5 5 11 11
Non-controlling interest in PipeLines LP 13 14 34 31
Other (1) 1 43 6
-----------------------------------
17 20 88 48
-----------------------------------
Net Income 324 257 773 522
-----------------------------------
-----------------------------------
Net Income Per Share
Basic and Diluted $0.58 $0.48 $1.40 $1.00
-----------------------------------
-----------------------------------
Average Shares Outstanding
- Basic (millions) 561 536 551 522
-----------------------------------
-----------------------------------
Average Shares Outstanding
- Diluted (millions) 563 538 553 525
-----------------------------------
-----------------------------------
See accompanying notes to the consolidated financial statements.
Consolidated Cash Flows
Three months Six months
(unaudited) ended June 30 ended June 30
(millions of dollars) 2008 2007 2008 2007
----------------------------------------------------------------------------
Cash Generated From Operations
Net income 324 257 773 522
Depreciation 301 300 597 590
Future income taxes 21 16 26 (21)
Non-controlling interests 17 20 88 48
Employee future benefits funding
(in excess of)/ lower than expense (7) 3 13 15
Writedown of Broadwater LNG project costs - - 41 -
Other 20 - 60 24
-----------------------------------
676 596 1,598 1,178
(Increase)/decrease in operating
working capital (104) 93 (98) 129
-----------------------------------
Net cash provided by operations 572 689 1,500 1,307
-----------------------------------
Investing Activities
Capital expenditures (633) (386)(1,093) (692)
Acquisitions, net of cash acquired (2) (4) (4) (4,224)
Deferred amounts and other (13) (42) 99 (148)
-----------------------------------
Net cash used in investing activities (648) (432) (998) (5,064)
-----------------------------------
Financing Activities
Dividends on common shares (137) (131) (267) (287)
Distributions paid to non-controlling
interests (65) (29) (86) (45)
Notes payable issued/(repaid), net 754 (804) 724 261
Long-term debt issued - 89 112 1,451
Reduction of long-term debt (379) (470) (773) (795)
Long-term debt of joint ventures issued 17 98 34 110
Reduction of long-term debt of joint
ventures (28) (107) (57) (119)
Common shares issued, net of issue costs 1,237 7 1,246 1,697
Junior subordinated notes issued - 1,107 - 1,107
Partnership units of subsidiary issued - - - 348
-----------------------------------
Net cash provided by/(used in) financing
activities 1,399 (240) 933 3,728
-----------------------------------
Effect of Foreign Exchange Rate Changes
on Cash and Cash Equivalents (3) (27) 20 (30)
-----------------------------------
Increase /(Decrease) in Cash and Cash
Equivalents 1,320 (10) 1,455 (59)
Cash and Cash Equivalents
Beginning of period 639 350 504 399
-----------------------------------
Cash and Cash Equivalents
End of period 1,959 340 1,959 340
-----------------------------------
-----------------------------------
Supplementary Cash Flow Information
Income taxes paid 312 125 479 212
Interest paid 277 269 481 542
-----------------------------------
-----------------------------------
See accompanying notes to the consolidated financial statements.
Consolidated Balance Sheet
(unaudited) June 30, December 31,
(millions of dollars) 2008 2007
----------------------------------------------------------------------------
ASSETS
Current Assets
Cash and cash equivalents 1,959 504
Accounts receivable 1,145 1,116
Inventories 549 497
Other 401 188
----------------------
4,054 2,305
Plant, Property and Equipment 24,149 23,452
Goodwill 2,813 2,633
Other Assets 1,839 1,940
----------------------
32,855 30,330
----------------------
----------------------
----------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Notes payable 1,133 421
Accounts payable and accrued liabilities 1,989 1,767
Accrued interest 252 261
Current portion of long-term debt 537 556
Current portion of long-term debt of joint ventures 30 30
----------------------
3,941 3,035
Deferred Amounts 1,283 1,107
Future Income Taxes 1,195 1,179
Long-Term Debt 11,945 12,377
Long-Term Debt of Joint Ventures 875 873
Junior Subordinated Notes 1,006 975
----------------------
20,245 19,546
----------------------
Non-Controlling Interests
Non-controlling interest in PipeLines LP 603 539
Preferred shares of subsidiary 389 389
Other 73 71
----------------------
1,065 999
----------------------
Shareholders' Equity 11,545 9,785
----------------------
32,855 30,330
----------------------
----------------------
See accompanying notes to the consolidated financial statements.
Consolidated Comprehensive Income
Three months Six months
(unaudited) ended June 30 ended June 30
(millions of dollars) 2008 2007 2008 2007
----------------------------------------------------------------------------
Net Income 324 257 773 522
------------------------------
Other Comprehensive Income/(Loss), Net of
Income Taxes
Change in foreign currency translation
gains and losses on investments in
foreign operations(1) (14) (184) 39 (221)
Change in gains and losses on hedges of
investments in foreign operations(2) 17 46 (24) 55
Change in gains and losses on derivative
instruments designated as cash
flow hedges(3) 29 (36) 33 (37)
Reclassification to net income of gains
and losses on derivative instruments
designated as cash flow hedges
pertaining to prior periods(4) 1 23 (18) 20
----------------------------------------------------------------------------
Other Comprehensive Income/(Loss) 33 (151) 30 (183)
----------------------------------------------------------------------------
Comprehensive Income 357 106 803 339
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Net of income tax expense of $5 million and recovery of $20 million for
the three months and six months ended June 30, 2008, respectively
(2007 - $51 and $56 million expense, respectively).
(2) Net of income tax expense of $8 million and recovery of $14 million for
the three months and six months ended June 30, 2008, respectively
(2007 - $23 and $28 million expense, respectively).
(3) Net of income tax expense of $37 million and $49 million for the three
months and six months ended June 30, 2008, respectively
(2007 - $15 million and $10 million recovery, respectively).
(4) Net of income tax recovery of $2 million and $11 million for the three
months and six months ended June 30, 2008, respectively
(2007 - $7 million and $5 million expense, respectively).
See accompanying notes to the consolidated financial statements.
Consolidated Accumulated Other Comprehensive Income
Currency
(unaudited) Translation Cash Flow
(millions of dollars) Adjustment Hedges Total
----------------------------------------------------------------------------
Balance at December 31, 2007 (361) (12) (373)
Change in foreign currency translation
gains and losses on investments in
foreign operations (1) 39 - 39
Change in gains and losses on hedges
of investments in foreign operations(2) (24) - (24)
Change in gains and losses on derivative
instruments designated as cash flow
hedges(3) - 33 33
Reclassification to net income of gains
and losses on derivative instruments
designated as cash flow hedges pertaining
to prior periods(4)(5) - (18) (18)
----------------------------------
Balance at June 30, 2008 (346) 3 (343)
----------------------------------
----------------------------------
Balance at December 31, 2006 (90) - (90)
Transition adjustment resulting from
adopting new financial instruments
standards(6) - (96) (96)
Change in foreign currency translation
gains and losses on investments in
foreign operations(1) (221) - (221)
Change in gains and losses on hedges 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) - 20 20
----------------------------------
Balance at June 30, 2007 (256) (113) (369)
----------------------------------
----------------------------------
(1) Net of income tax recovery of $20 million for the six months ended
June 30, 2008 (2007 - $56 million expense).
(2) Net of income tax recovery of $14 million for the six months ended
June 30, 2008 (2007 - $28 million expense).
(3) Net of income tax expense of $49 million for the six months ended
June 30, 2008 (2007 - $10 million recovery).
(4) Net of income tax recovery of $11 million for the six months ended
June 30, 2008 (2007 - $5 million expense).
(5) The amount of gains and losses related to cash flow hedges reported in
accumulated other comprehensive income that will be reclassified to net
income in the next 12 months is estimated to be net gains of $10
million ($7 million net losses, net of tax). These estimates assume
constant gas and power prices, interest rates and foreign exchange
rates over time, however, the actual amounts that will be reclassified
will vary based on changes in these factors.
(6) Net of income tax expense of $44 million.
See accompanying notes to the consolidated financial statements.
Consolidated Shareholders' Equity
(unaudited) Six months ended June 30
(millions of dollars) 2008 2007
----------------------------------------------------------------------------
Common Shares
Balance at beginning of period 6,662 4,794
Shares issued under dividend reinvestment plan 112 51
Proceeds from shares issued on exercise of stock
options 11 14
Proceeds from shares issued under public
offering, net of issue costs 1,235 1,683
-------------------------
Balance at end of period 8,020 6,542
-------------------------
Contributed Surplus
Balance at beginning of period 276 273
Issuance of stock options 2 2
-------------------------
Balance at end of period 278 275
-------------------------
Retained Earnings
Balance at beginning of period 3,220 2,724
Transition adjustment resulting from adopting new
financial instruments accounting standards - 4
Net income 773 522
Common share dividends (403) (358)
-------------------------
Balance at end of period 3,590 2,892
-------------------------
Accumulated Other Comprehensive Income
Balance at beginning of period (373) (90)
Transition adjustment resulting from adopting new
financial instruments standards - (96)
Other comprehensive income 30 (183)
-------------------------
Balance at end of period (343) (369)
-------------------------
Total Shareholders' Equity 11,545 9,340
-------------------------
-------------------------
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, 2007. 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 2007 audited Consolidated Financial Statements included in TransCanada's 2007 Annual Report. Amounts are stated in Canadian dollars unless otherwise indicated.
In Pipelines, which consists primarily of the Company's investments in regulated pipelines and regulated natural gas storage facilities, annual revenues and net income fluctuate over the long term based on regulators' decisions and negotiated settlements with shippers. Generally, quarter-over-quarter revenues and net income during any particular fiscal year remain relatively stable with fluctuations resulting from adjustments being recorded due to regulatory decisions and negotiated settlements with shippers, seasonal fluctuations in short-term throughput on U.S. pipelines, acquisitions and divestitures, and developments outside of the normal course of operations.
In Energy, which consists primarily of the Company's investments in electrical power generation plants and non-regulated natural gas storage facilities, quarter-over-quarter revenues and net income are affected by seasonal weather conditions, customer demand, market prices, planned and unplanned plant outages, acquisitions and divestitures, and developments outside of the normal course of operations.
In preparing these financial statements, TransCanada is required to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be dependent on future events. The Company uses the most current information available and exercises careful judgement in making these estimates. In the opinion of management, these consolidated financial statements have been properly prepared within reasonable limits of materiality and within the framework of the significant accounting policies.
2. Changes in Accounting Policies
Future Accounting Changes
International Financial Reporting Standards
The Canadian Institute of Chartered Accountants' Accounting Standards Board (AcSB) announced that Canadian publicly accountable enterprises are required to adopt International Financial Reporting Standards (IFRS), as issued by the International Accounting Standards Board (IASB), effective January 1, 2011. In June 2008, the Canadian Securities Administrators (CSA) proposed that Canadian public companies which are also SEC registrants, such as TransCanada, could retain the option to prepare their financial statements under U.S. GAAP instead of IFRS. TransCanada is currently assessing its option to adopt IFRS as of January 1, 2011 and the impact that such a conversion would have on its accounting systems and financial statements. TransCanada's conversion planning includes an analysis of project structure and governance, resourcing and training, analysis of key GAAP differences and a phased approach to assess accounting policies under IFRS.
Under existing Canadian GAAP, TransCanada follows specific accounting policies unique to a rate-regulated business. TransCanada is actively monitoring ongoing discussions and developments of the IASB and its International Financial Reporting Interpretations Committee regarding potential future guidance to clarify the applicability of certain aspects of rate-regulated accounting under IFRS.
3. Segmented Information
Three months
ended
June 30
(unaudited -
millions Pipelines Energy Corporate Total
of -------------------------------------------------------------
dollars) 2008 2007 2008 2007 2008 2007 2008 2007
----------------------------------------------------------------------------
Revenues 1,100 1,228 917 980 - - 2,017 2,208
Plant
operating
costs and
other (415) (417) (316) (343) (2) (1) (733) (761)
Commodity
purchases
resold - (65) (347) (458) - - (347) (523)
Depreciation (257) (260) (44) (40) - - (301) (300)
--------------------------------------------------------------
428 486 210 139 (2) (1) 636 624
Financial
charges and
non-controlling
interests (169) (206) - - (34) (78) (203) (284)
Financial
charges of
joint ventures (11) (13) (6) (6) - - (17) (19)
Interest income
and other 15 16 3 3 16 29 34 48
Income taxes (105) (117) (56) (42) 35 47 (126) (112)
--------------------------------------------------------------
Net Income 158 166 151 94 15 (3) 324 257
--------------------------------------------------------------
--------------------------------------------------------------
Six months
ended
June 30
(unaudited -
millions Pipelines Energy Corporate Total
of ------------------------------------------------------------
dollars) 2008 2007 2008 2007 2008 2007 2008 2007
----------------------------------------------------------------------------
Revenues 2,276 2,352 1,874 2,100 - - 4,150 4,452
Plant
operating
costs and
other (814) (800) (614) (690) (3) (3) (1,431) (1,493)
Commodity
purchases
resold - (65) (757) (1,029) - - (757) (1,094)
Depreciation (511) (511) (86) (79) - - (597) (590)
--------------------------------------------------------------
951 976 417 302 (3) (3) 1,365 1,275
Financial
charges and
non-controlling
interests (404) (423) - 1 (88) (127) (492) (549)
Financial
charges of
joint ventures (22) (29) (11) (11) - - (33) (40)
Interest income
and other 47 29 4 6 22 44 73 79
Calpine
bankruptcy
settlements 279 - - - - - 279 -
Writedown of
Broadwater LNG
project costs - - (41) - - - (41) -
Income taxes (332) (232) (108) (98) 62 87 (378) (243)
--------------------------------------------------------------
Net Income 519 321 261 200 (7) 1 773 522
--------------------------------------------------------------
--------------------------------------------------------------
Total Assets June 30, December 31,
(unaudited - millions of dollars) 2008 2007
----------------------------------------------------------------------------
Pipelines 22,510 22,024
Energy 7,698 7,037
Corporate 2,647 1,269
-----------------------
32,855 30,330
-----------------------
-----------------------
4. Share Capital
On July 2, 2008, TransCanada filed a final short form base 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 August 2010. The filing was done in normal course similar to the filing of debt shelf prospectuses in Canada and the U.S. so as to expedite access to the capital markets depending on TransCanada's assessment of its requirements for funding and general market conditions. This new shelf prospectus replaces the previous $3.0 billion short form shelf prospectus filed in January 2007 under which the Company had issued approximately $3.0 billion of common shares.
On May 5, 2008, TransCanada entered into an agreement with a syndicate of underwriters under which the underwriters agreed to purchase 30,200,000 common shares from TransCanada and sell them to the public at a price of $36.50 each. The underwriters also fully exercised an over-allotment option which they were granted for an additional 4,530,000 common shares at the same price. The entire issue of the 34,730,000 common shares closed on May 13, 2008 and resulted in gross proceeds to TransCanada of approximately $1.27 billion. These proceeds will be used to partially fund acquisitions and capital projects of the Company, including the acquisition of Ravenswood and the construction of Keystone, and for general corporate purposes.
In the three and six months ended June 30, 2008, TransCanada issued 1.7 million and 3.1 million common shares, respectively, under its Dividend Reinvestment and Share Purchase Plan (DRP). In accordance with the DRP, dividends were paid with common shares issued from treasury in lieu of making cash dividend payments totalling $58 million and $112 million. In the three and six months ended June 30, 2007, TransCanada issued 1.3 million common shares under its DRP, in lieu of making cash dividend payments totalling $51 million.
5. Long-Term Debt
On June 27, 2008, TransCanada executed an agreement with a syndicate of banks for a US$1.5 billion, committed, unsecured, one-year bridge loan facility, which will be at a floating interest rate based on the London Interbank Offered Rate. The facility is extendible at the option of the Company for an additional six-month term and is available to fund a portion of the pending Ravenswood acquisition. No funds have been drawn on this facility at this time.
In the three and six months ended June 30, 2008, the Company capitalized interest related to capital projects of $33 million and $59 million, respectively.
6. Financial Instruments and Risk Management
Natural Gas Inventory
At June 30, 2008, $240 million of proprietary natural gas inventory held in storage was included in Inventories (December 31, 2007 - $190 million). Effective April 1, 2007, TransCanada began valuing its proprietary natural gas inventory at fair value, as measured by the one-month forward price for natural gas less selling costs. The Company did not have any proprietary natural gas inventory prior to April 1, 2007. The change in fair value of proprietary natural gas inventory in the three and six months ended June 30, 2008 resulted in net unrealized gains of $42 million and $102 million, respectively, which were recorded as an increase to Revenues and Inventory (three and six months ended June 30, 2007 - net unrealized losses of $23 million). The net change in fair value of natural gas forward purchase and sales contracts in the three and six months ended June 30, 2008 resulted in net unrealized losses of $30 million and $107 million, respectively (three and six months ended June 30, 2007 - net unrealized gains of $19 million and $16 million, respectively), which were included in Revenues.
Net Investment in Self-Sustaining Foreign Operations
Information for the derivatives used to hedge the Company's net investment in its foreign operations is as follows:
Derivatives Hedging Net Investment in Foreign Operations
Asset/(Liability)
(unaudited)
(millions of dollars) June 30, 2008 December 31, 2007
----------------------------------------------------------------------------
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 2009 to 2014) 75 U.S. 1,050 77 U.S. 350
U.S. dollar forward foreign
exchange contracts
(maturing 2008) (5) U.S. 730 (4) U.S. 150
U.S. dollar options
(maturing 2008) - U.S. 100 3 U.S. 600
-------------------------------------------
70 U.S. 1,880 76 U.S. 1,100
-------------------------------------------
-------------------------------------------
(1) Fair values are equal to carrying values.
Derivative Financial Instruments Summary
Information for the Company's derivative financial instruments is as
follows:
June 30, 2008
(all amounts in millions unless Natural
otherwise indicated) Power Gas Interest
----------------------------------------------------------------------------
Derivative Financial Instruments
Held for Trading
Fair Values(1)
Assets $ 104 $ 169 $ 26
Liabilities $ (103) $ (258) $ (26)
Notional Values
Volumes(2)
Purchases 2,955 48 -
Sales 3,301 65 -
Canadian dollars - - 857
U.S. dollars - - U.S. 1,150
Unrealized (losses)/gains
in the period(3)
Three months ended
June 30, 2008 $ (3) $ 7 $ 2
Six months ended June 30, 2008 $ (5) $ (11) $ (2)
Realized gains/(losses)
in the period(3)
Three months ended
June 30, 2008 $ 7 $ (20) $ 7
Six months ended June 30, 2008 $ 9 $ 5 $ 10
Maturity dates 2008-2014 2008-2010 2008-2018
Derivative Financial Instruments
in Hedging Relationships(4)(5)
Fair Values(1)
Assets $ 250 $ 80 $ 3
Liabilities $ (236) $ - $ (17)
Notional Values
Volumes(2)
Purchases 6,126 23 -
Sales 17,727 - -
Canadian dollars - - 50
U.S. dollars - - U.S. 925
Realized (losses)/gains
in the period(3)
Three months ended
June 30, 2008 $ (37) $ 11 $ (3)
Six months ended June 30, 2008 $ (38) $ 19 $ (2)
Maturity dates 2008-2014 2008-2011 2009-2013
(1) Fair value is equal to the carrying value of these derivatives.
(2) Volumes for power and natural gas derivatives are in gigawatt hours
(Gwh) and billion cubic feet (Bcf), respectively.
(3) All realized and unrealized gains and losses are included in Net Income.
Realized gains and losses are included in Net Income after the financial
instrument has been settled.
(4) All hedging relationships are designated as cash flow hedges except
for $2 million (December 31, 2007 - $2 million) of interest-rate
derivative financial instruments designated as fair value hedges.
(5) Net Income for the three and six months ended June 30, 2008 included
losses of $3 million and $4 million, respectively (three and six months
ended June 30, 2007 - nil and $3 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 underlying positions. Net Income for the three and six months
ended June 30, 2007 included nil and a $4 million loss, respectively,
for the changes in fair value of an interest-rate cash flow hedge that
was reclassified as a result of discontinuance of cash flow hedge
accounting. Cash flow hedge accounting was discontinued when the
anticipated transaction was not probable of occurring by the end of the
originally specified time period. There were no gains or losses
included in Net Income for the three and six months ended June 30,
2008 for discontinued cash flow hedges.
2007
(all amounts in millions unless
otherwise indicated) Power Natural Gas Interest
----------------------------------------------------------------------------
Derivative Financial Instruments Held
for Trading
Fair Values(1)(4)
Assets $ 55 $ 43 $ 23
Liabilities $ (44) $ (19) $ (18)
Notional Values(4)
Volumes(2)
Purchases 3,774 47 -
Sales 4,469 64 -
Canadian dollars - - 615
U.S. dollars - - U.S. 550
Unrealized gains/(losses) in the
period(3)
Three months ended June 30, 2007 $ 5 $ 1 $ (2)
Six months ended June 30, 2007 $ 9 $ (16) $ 1
Realized (losses)/gains in the
period(3)
Three months ended June 30, 2007 $ (3) $ 6 $ 1
Six months ended June 30, 2007 $ (8) $ 18 $ 1
Maturity dates(4) 2008 - 2012 2008 - 2010 2008 - 2016
Derivative Financial Instruments in Hedging
Relationships(5)(6)
Fair Values(1)(4)
Assets $ 135 $ 19 $ 2
Liabilities $ (104) $ (7) $ (16)
Notional Values(4)
Volumes(2)
Purchases 7,362 28 -
Sales 16,367 4 -
Canadian dollars - - 150
U.S. dollars - - U.S. 875
Realized gains/(losses) in the
period(3)
Three months ended June 30, 2007 $ 16 $ (1) $ 1
Six months ended June 30, 2007 $ 13 $ (3) $ 1
Maturity dates(4) 2008 - 2013 2008 - 2010 2008 - 2013
(1) Fair value is equal to the carrying value of these derivatives.
(2) Volumes for power and natural gas derivatives are in Gwh and Bcf,
respectively.
(3) All realized and unrealized gains and losses are included in Net Income.
Realized gains and losses are included in Net Income after the financial
instrument has been settled.
(4) As at December 31, 2007.
(5) All hedging relationships are designated as cash flow hedges except for
$2 million (December 31, 2007 - $2 million) of interest-rate derivative
financial instruments designated as fair value hedges.
(6) Net Income for the three and six months ended June 30, 2008 included
losses of $3 million and $4 million, respectively (three and six months
ended June 30, 2007 - nil and $3 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
underlying positions. Net Income for the three and six months ended June
30, 2007 included nil and a $4 million loss, respectively, for the
changes in fair value of an interest-rate cash flow hedge that was
reclassified as a result of discontinuance of cash flow hedge
accounting. Cash flow hedge accounting was discontinued when the
anticipated transaction was not probable of occurring by the end of the
originally specified time period. There were no gains or losses included
in Net Income for the three and six months ended June 30, 2008 for
discontinued cash flow hedges.
7. 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, 2008 is as follows:
Pension Other
Benefit Plans Benefit Plans
Three months ended June 30 ------------------------------
(unaudited - millions of dollars) 2008 2007 2008 2007
----------------------------------------------------------------------------
Current service cost 12 11 1 1
Interest cost 20 18 2 2
Expected return on plan assets (23) (20) (1) (1)
Amortization of transitional obligation
related to regulated business - - 1 -
Amortization of net actuarial loss 5 6 1 -
Amortization of past service costs 1 1 - (1)
----------------------------
Net benefit cost recognized 15 16 4 1
----------------------------
----------------------------
Pension Other
Benefit Plans Benefit Plans
Six months ended June 30 ------------------------------
(unaudited - millions of dollars) 2008 2007 2008 2007
----------------------------------------------------------------------------
Current service cost 25 22 1 1
Interest cost 39 35 4 3
Expected return on plan assets (46) (39) (1) (1)
Amortization of transitional obligation
related to regulated business - - 1 1
Amortization of net actuarial loss 9 12 1 1
Amortization of past service costs 2 2 - (1)
----------------------------
Net benefit cost recognized 29 32 6 4
----------------------------
----------------------------
8. Calpine Bankruptcy Settlements
Certain subsidiaries of Calpine Corporation (Calpine) filed for bankruptcy protection in both Canada and the U.S. in 2005. Gas Transmission Northwest Corporation (GTNC) and Portland reached agreements with Calpine for allowed unsecured claims in the Calpine bankruptcy. In February 2008, GTNC and Portland received initial distributions of 9.4 million shares and 6.1 million shares, respectively, which represented approximately 85 per cent of their agreed-for claims. These shares were subsequently sold into the open market and resulted in total pre-tax income of $279 million.
9. Writedown of Development Costs
On March 24, 2008, the U.S. Federal Energy Regulatory Committee authorized the construction and operation of the Broadwater liquefied natural gas (LNG) project, subject to the conditions reflected in the authorization. On April 10, 2008, the New York State Department of State rejected a proposal to construct the Broadwater facility. As a result of this unfavourable decision, TransCanada wrote down $27 million after tax ($41 million pre-tax) of costs that had been previously capitalized for the Broadwater LNG project to March 31, 2008.
10. Commitments and Contingencies
Commitments
On March 31, 2008, TransCanada entered into an agreement with National Grid plc to acquire, for approximately US$2.8 billion plus closing adjustments, 100 per cent of KeySpan-Ravenswood, LLC, which owns the Ravenswood Generating Facility in Queens, New York. The acquisition is expected to be financed in a manner that is consistent with TransCanada's current capital structure. In addition, as at June 30, 2008 TransCanada has entered into agreements to purchase construction materials and services for the Kibby Wind and Coolidge power projects, totalling approximately $625 million.
Contingencies
On April 3, 2008, the Ontario Court of Appeal dismissed an appeal filed by the Canadian Alliance of Pipeline Landowners' Associations (CAPLA). CAPLA filed the appeal as a result of a decision by the Ontario Superior Court in November 2006 to dismiss CAPLA's class action lawsuit against TransCanada and Enbridge Inc. for damages alleged to have arisen from the creation of a control zone within 30 metres of a pipeline pursuant to Section 112 of the National Energy Board Act. The Ontario Court of Appeal's decision is final and binding as CAPLA did not seek any further appeal within the time frame allowed.
TransCanada welcomes questions from shareholders and potential investors. Please telephone:
Investor Relations, at 1-800-361-6522 (Canada and U.S. Mainland) or direct dial David Moneta/Myles Dougan/Terry Hook at (403) 920-7911. The investor fax line is (403) 920-2457. Media Relations: Cecily Dobson/Shela Shapiro at (403) 920-7859 or 1-800-608-7859.
Visit the TransCanada website at: http://www.transcanada.com.