TransCanada Reports an Increase in Third Quarter Comparable Earnings to $417 Million or $0.59 Per Share
(firmenpresse) - CALGARY, ALBERTA -- (Marketwire) -- 11/01/11 -- TransCanada Corporation (TSX: TRP) (NYSE: TRP) (TransCanada or the Company) today announced comparable earnings for third quarter 2011 of $417 million or $0.59 per share. Net income attributable to common shares was $384 million or $0.55 per share. TransCanada's Board of Directors also declared a quarterly dividend of $0.42 per common share for the quarter ending December 31, 2011, equivalent to $1.68 per share on an annualized basis.
"TransCanada experienced another strong quarter driven by earnings from our new assets and the Company's diverse and high-quality energy infrastructure portfolio," said Russ Girling, TransCanada's president and chief executive officer. "Comparable earnings for the first nine months of 2011 were $1.71 per share, a 20 per cent increase over the same period last year."
Since the spring of 2010, TransCanada has brought $10 billion of growth projects into service including the first and second phases of the Keystone Pipeline System, the Bison and Guadalajara natural gas pipelines, extensions and expansions of the Alberta System, phase two of the Kibby Wind farm in Maine, the Halton Hills Generating Station in Ontario and the Coolidge Generating Station in Arizona.
The Company is positioned to complete another $11 billion of new projects that will come into service by 2013 including the Keystone U.S. Gulf Coast Expansion (Keystone XL), additional extensions and expansions of the Alberta System, the Bruce Power restart program in Ontario and the final two phases of the Cartier Wind power project in Quebec. TransCanada expects these projects will generate sustained earnings and cash flow growth and deliver superior returns to our shareholders.
Third Quarter Highlights
(All financial figures are unaudited and in Canadian dollars unless noted otherwise)
Comparable earnings for third quarter 2011 were $417 million ($0.59 per share) compared to $374 million ($0.54 per share) in the same period in 2010. Contributions from recently commissioned pipeline and power generation assets, combined with higher realized power prices in Alberta, were the primary reasons for the year over year increase in comparable earnings. Partially offsetting these increases were higher interest expense and lower contributions from the U.S. Power and Alberta Gas Storage businesses. Comparable earnings in third quarter 2010 included the positive impact of recognizing the Alberta System 2010-2012 Revenue Requirement Settlement retroactive to its January 1, 2010 effective date.
Notable recent developments in Oil Pipelines, Natural Gas Pipelines, Energy and Corporate include:
Oil Pipelines:
Natural Gas Pipelines:
Energy:
Corporate:
Teleconference and Webcast - Audio and Slide Presentation:
TransCanada will hold a teleconference and webcast to discuss its 2011 third quarter financial results. Russ Girling, TransCanada president and chief executive officer and Don Marchand, executive vice-president and chief financial officer, along with other members of the TransCanada executive leadership team, will discuss the financial results and company developments before opening the call to questions from analysts and members of the media.
Event:
TransCanada 2011 third quarter financial results teleconference and webcast
Date:
Tuesday, November 1, 2011
Time:
9:00 a.m. mountain daylight time (MDT) / 11:00 a.m. eastern daylight time (EDT)
How:
Analysts, members of the media and other interested parties are invited to participate by calling 866.223.7781 or 416.340.8018 (Toronto area). Please dial in 10 minutes prior to the start of the call. No pass code is required. A live webcast of the teleconference will be available at .
A replay of the teleconference will be available two hours after the conclusion of the call until midnight (EDT) November 8, 2011. Please call 800.408.3053 or 905.694.9451 (Toronto area) and enter pass code 2786260.
With more than 60 years experience, TransCanada is a leader in the responsible development and reliable operation of North American energy infrastructure including natural gas and oil pipelines, power generation and gas storage facilities. TransCanada's network of wholly owned natural gas pipelines extends more than 57,000 kilometres (35,500 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 380 billion cubic feet of storage capacity. A growing independent power producer, TransCanada owns, or has interests in, over 10,800 megawatts of power generation in Canada and the United States. TransCanada is developing one of North America's largest oil delivery systems. TransCanada's common shares trade on the Toronto and New York stock exchanges under the symbol TRP. For more information visit: and follow us on Twitter (at)TransCanada.
Forward-Looking Information
This news release may contain certain information that is forward-looking and is subject to important risks and uncertainties. The words "anticipate", "expect", "believe", "may", "should", "estimate", "project", "outlook", "forecast" or other similar words are used to identify such forward-looking information. Forward-looking statements in this document are intended to provide TransCanada security holders and potential investors with information regarding TransCanada and its subsidiaries, including management's assessment of TransCanada's and its subsidiaries' future financial and operational plans and outlook. Forward-looking statements in this document may include, among others, statements regarding the anticipated business prospects, projects and financial performance of TransCanada and its subsidiaries, expectations or projections about the future, strategies and goals for growth and expansion, expected and future cash flows, costs, schedules (including anticipated construction and completion dates), operating and financial results and expected impact of future commitments and contingent liabilities, including future abandonment costs. All forward-looking statements reflect TransCanada's beliefs and assumptions based on information available at the time the statements were made. Actual results or events may differ from those predicted in these forward-looking statements. Factors that could cause actual results or events to differ materially from current expectations include, among others, the ability of TransCanada to successfully implement its strategic initiatives and whether such strategic initiatives will yield the expected benefits, the operating performance of the Company's pipeline and energy assets, the availability and price of energy commodities, capacity payments, regulatory processes and decisions, outcomes of litigation and arbitration proceedings, changes in environmental and other laws and regulations, competitive factors in the pipeline and energy sectors, construction and completion of capital projects, labour, equipment and material costs, access to capital markets, interest and currency exchange rates, technological developments and economic conditions in North America. By its nature, forward-looking information is subject to various risks and uncertainties, which could cause TransCanada's actual results and experience to differ materially from the anticipated results or expectations expressed.
Additional information on these and other factors is available in the reports filed by TransCanada with Canadian securities regulators and with the U.S. Securities and Exchange Commission. 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 specified, and not to use future-oriented information or financial outlooks for anything other than their intended purpose. TransCanada undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, except as required by law.
Non-GAAP Measures
TransCanada uses the measures Comparable Earnings, Comparable Earnings per Share, Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA), Comparable EBITDA, Earnings Before Interest and Taxes (EBIT), Comparable EBIT, Comparable Interest Expense, Comparable Interest Income and Other, Comparable Income Taxes and Funds Generated from Operations in this news release. These measures do not have any standardized meaning prescribed by Canadian generally accepted accounting principles (GAAP). They are, therefore, considered to be non-GAAP measures and may not be comparable to similar measures presented by other entities. Management of TransCanada uses these non-GAAP measures to improve its ability to compare financial results among reporting periods and to enhance its understanding of operating performance, liquidity and ability to generate funds to finance operations. These non-GAAP measures are also provided to readers as additional information on TransCanada's operating performance, liquidity and ability to generate funds to finance operations.
EBITDA is an approximate measure of the Company's pre-tax operating cash flow and is generally used to better measure performance and evaluate trends of individual assets. EBITDA comprises earnings before deducting interest and other financial charges, income taxes, depreciation and amortization, net income attributable to non-controlling interests and preferred share dividends. EBIT is a measure of the Company's earnings from ongoing operations and is generally used to better measure performance and evaluate trends within each segment. EBIT comprises earnings before deducting interest and other financial charges, income taxes, net income attributable to non-controlling interests and preferred share dividends.
Comparable Earnings, Comparable EBITDA, Comparable EBIT, Comparable Interest Expense, Comparable Interest Income and Other, and Comparable Income Taxes comprise Net Income Attributable to Common Shares, EBITDA, EBIT, Interest Expense, Interest Income and Other, and Income Taxes Expense, respectively, adjusted for specific items that are significant but are not reflective of the Company's underlying operations in the period. Specific items are subjective, however, management uses its judgement and informed decision-making when identifying items to be excluded in calculating these non-GAAP measures, some of which may recur. Specific items may include but are not limited to certain fair value adjustments relating to risk management activities, income tax refunds and adjustments, gains or losses on sales of assets, legal and bankruptcy settlements, and write-downs of assets and investments.
The Company engages in risk management activities to reduce its exposure to certain financial and commodity price risks by utilizing instruments such as derivatives. The risk management activities which TransCanada excludes from Comparable Earnings provide effective economic hedges but do not meet the specific criteria for hedge accounting treatment and, therefore, changes in their fair values are recorded in Net Income each period. The unrealized gains or losses from changes in the fair value of these derivative contracts and natural gas inventory in storage are not considered to be representative of the underlying operations in the current period or the positive margin that will be realized upon settlement. As a result, these amounts have been excluded in the determination of Comparable Earnings.
The table in the Non-GAAP Measures section of the Management's Discussion and Analysis presents a reconciliation of these non-GAAP measures to Net Income Attributable to Common Shares. Comparable Earnings per Share is calculated by dividing Comparable Earnings by the weighted average number of common shares outstanding for the period.
Funds Generated from Operations comprise Net Cash Provided by Operations before changes in operating working capital and allows management to better measure consolidated operating cash flow, excluding fluctuations from working capital balances which may not necessarily be reflective of underlying operations in the same period. A reconciliation of Funds Generated from Operations to Net Cash Provided by Operations is presented in the Third Quarter 2011 Financial Highlights table in this news release.
Third Quarter 2011 Financial Highlights
Operating Results
Common Share Statistics
(1) Refer to the Non-GAAP Measures section in this news release for further discussion of Comparable EBITDA, Comparable Earnings, Funds Generated from Operations and Comparable Earnings per Share.
Quarterly Report to Shareholders
Management's Discussion and Analysis
Management's Discussion and Analysis (MD&A) dated October 31, 2011 should be read in conjunction with the accompanying unaudited Consolidated Financial Statements of TransCanada Corporation (TransCanada or the Company) for the three and nine months ended September 30, 2011. In 2011, the Company will prepare its consolidated financial statements in accordance with Canadian generally accepted accounting principles (GAAP) as defined in Part V of the Canadian Institute of Chartered Accountants (CICA) Handbook, which is discussed further in the Changes in Accounting Policies section in this MD&A. This MD&A should also be read in conjunction with the audited Consolidated Financial Statements and notes thereto, and the MD&A contained in TransCanada's 2010 Annual Report for the year ended December 31, 2010. Additional information relating to TransCanada, including the Company's Annual Information Form and other continuous disclosure documents, is available on SEDAR at under TransCanada Corporation's profile. "TransCanada" or "the Company" includes TransCanada Corporation and its subsidiaries, unless otherwise indicated. Amounts are stated in Canadian dollars unless otherwise indicated. Abbreviations and acronyms used but not otherwise defined in this MD&A are identified in the Glossary of Terms contained in TransCanada's 2010 Annual Report.
Forward-Looking Information
This MD&A may contain certain information that is forward looking and is subject to important risks and uncertainties. The words "anticipate", "expect", "believe", "may", "should", "estimate", "project", "outlook", "forecast" or other similar words are used to identify such forward-looking information. Forward-looking statements in this document are intended to provide TransCanada security holders and potential investors with information regarding TransCanada and its subsidiaries, including management's assessment of TransCanada's and its subsidiaries' future financial and operational plans and outlook. Forward-looking statements in this document may include, among others, statements regarding the anticipated business prospects, projects and financial performance of TransCanada and its subsidiaries, expectations or projections about the future, strategies and goals for growth and expansion, expected and future cash flows, costs, schedules (including anticipated construction and completion dates), operating and financial results, and expected impact of future commitments and contingent liabilities, including future abandonment costs. All forward looking statements reflect TransCanada's beliefs and assumptions based on information available at the time the statements were made.
Actual results or events may differ from those predicted in these forward-looking statements. Factors that could cause actual results or events to differ materially from current expectations include, among others, the ability of TransCanada to successfully implement its strategic initiatives and whether such strategic initiatives will yield the expected benefits, the operating performance of the Company's pipeline and energy assets, the availability and price of energy commodities, capacity payments, regulatory processes and decisions, outcomes of litigation and arbitration proceedings, changes in environmental and other laws and regulations, competitive factors in the pipeline and energy sectors, construction and completion of capital projects, labour, equipment and material costs, access to capital markets, interest and currency exchange rates, technological developments and economic conditions in North America. By its nature, forward looking information is subject to various risks and uncertainties, including those material risks discussed in the Financial Instruments and Risk Management section in this MD&A, 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 not to place undue reliance on this forward looking information, which is given as of the date it is expressed in this MD&A or otherwise specified, and not to use future-oriented information or financial outlooks for anything other than their intended purpose. TransCanada undertakes no obligation to update publicly or revise any forward looking information, whether as a result of new information, future events or otherwise, except as required by law.
Non-GAAP Measures
TransCanada uses the measures Comparable Earnings, Comparable Earnings per Share, Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA), Comparable EBITDA, Earnings Before Interest and Taxes (EBIT), Comparable EBIT, Comparable Interest Expense, Comparable Interest Income and Other, Comparable Income Taxes and Funds Generated from Operations in this MD&A. These measures do not have any standardized meaning prescribed by GAAP. They are, therefore, considered to be non-GAAP measures and may not be comparable to similar measures presented by other entities. Management of TransCanada uses these non-GAAP measures to improve its ability to compare financial results among reporting periods and to enhance its understanding of operating performance, liquidity and ability to generate funds to finance operations. These non-GAAP measures are also provided to readers as additional information on TransCanada's operating performance, liquidity and ability to generate funds to finance operations.
EBITDA is an approximate measure of the Company's pre-tax operating cash flow and is generally used to better measure performance and evaluate trends of individual assets. EBITDA comprises earnings before deducting interest and other financial charges, income taxes, depreciation and amortization, net income attributable to non-controlling interests and preferred share dividends. EBIT is a measure of the Company's earnings from ongoing operations and is generally used to better measure performance and evaluate trends within each segment. EBIT comprises earnings before deducting interest and other financial charges, income taxes, net income attributable to non-controlling interests and preferred share dividends.
Comparable Earnings, Comparable EBITDA, Comparable EBIT, Comparable Interest Expense, Comparable Interest Income and Other, and Comparable Income Taxes comprise Net Income Attributable to Common Shares, EBITDA, EBIT, Interest Expense, Interest Income and Other, and Income Taxes Expense, respectively, adjusted for specific items that are significant but are not reflective of the Company's underlying operations in the period. Specific items are subjective, however, management uses its judgement and informed decision-making when identifying items to be excluded in calculating these non-GAAP measures, some of which may recur. Specific items may include but are not limited to certain fair value adjustments relating to risk management activities, income tax refunds and adjustments, gains or losses on sales of assets, legal and bankruptcy settlements, and write-downs of assets and investments.
The Company engages in risk management activities to reduce its exposure to certain financial and commodity price risks by utilizing instruments such as derivatives. The risk management activities which TransCanada excludes from Comparable Earnings provide effective economic hedges but do not meet the specific criteria for hedge accounting treatment and, therefore, changes in their fair values are recorded in Net Income each period. The unrealized gains or losses from changes in the fair value of these derivative contracts and natural gas inventory in storage are not considered to be representative of the underlying operations in the current period or the positive margin that will be realized upon settlement. As a result, these amounts have been excluded in the determination of Comparable Earnings.
The tables below present a reconciliation of these non-GAAP measures to Net Income Attributable to Common Shares. Comparable Earnings per Share is calculated by dividing Comparable Earnings by the weighted average number of common shares outstanding for the period.
Funds Generated from Operations comprise Net Cash Provided by Operations before changes in operating working capital and allows management to better measure consolidated operating cash flow, excluding fluctuations from working capital balances which may not necessarily be reflective of underlying operations in the same period. A reconciliation of Funds Generated from Operations to Net Cash Provided by Operations is presented in the Funds Generated from Operations table in the Liquidity and Capital Resources section in this MD&A.
Reconciliation of Non-GAAP Measures
Consolidated Results of Operations
Third Quarter Results
Comparable Earnings in third quarter 2011 were $417 million or $0.59 per share compared to $374 million or $0.54 per share for the same period in 2010. Comparable Earnings in third quarter 2011 excluded net unrealized after-tax losses of $33 million ($47 million pre-tax) (2010 - gains of $3 million after tax ($4 million pre-tax)) resulting from changes in the fair value of certain risk management activities.
Comparable Earnings increased $43 million or $0.05 per share in third quarter 2011 compared to the same period in 2010 and reflected the following:
TransCanada's Net Income Attributable to Controlling Interests in third quarter 2011 was $397 million and Net Income Attributable to Common Shares was $384 million or $0.55 per share compared to $391 million and $377 million or $0.54 per share, respectively, in third quarter 2010.
Nine Month Results
Comparable Earnings in the first nine months of 2011 were $1,199 million or $1.71 per share compared to $977 million or $1.42 per share for the same period in 2010. Comparable Earnings for the first nine months of 2011 excluded net unrealized after-tax losses of $47 million ($69 million pre-tax) (2010 - after-tax losses of $19 million ($30 million pre-tax)) resulting from changes in the fair value of certain risk management activities.
Comparable Earnings increased $222 million or $0.29 per share in the first nine months of 2011 compared to the same period in 2010 and reflected the following:
TransCanada's Net Income Attributable to Controlling Interests in the first nine months of 2011 was $1,193 million and Net Income Attributable to Common Shares was $1,152 million or $1.64 per share compared to $989 million and $958 million or $1.39 per share, respectively, for the same period in 2010.
Further discussion of the financial results for the three and nine months ended September 30, 2011 is included in the Natural Gas Pipelines, Oil Pipelines, Energy and Other Income Statement Items sections in this MD&A.
U.S. Dollar-Denominated Balances
On a consolidated basis, the impact of changes in the value of the U.S. dollar on U.S. operations is partially offset by other U.S. dollar-denominated items as set out in the following table. The resultant pre-tax net exposure is managed using derivatives, further reducing the Company's exposure to changes in Canadian-U.S. foreign exchange rates. The average U.S. dollar to Canadian dollar exchange rate for the three and nine months ended September 30, 2011 was 0.98 and 0.98, respectively (2010 - 1.04 and 1.04, respectively).
Summary of Significant U.S. Dollar-Denominated Amounts
Natural Gas Pipelines
Natural Gas Pipelines' Comparable EBIT was $474 million and $1,493 million in the three and nine months ended September 30, 2011, respectively, compared to $482 million and $1,442 million, respectively, for the same periods in 2010.
Natural Gas Pipelines Results
Net Income for Wholly Owned Canadian Natural Gas Pipelines
Canadian Natural Gas Pipelines
Canadian Mainline's net income for the three and nine months ended September 30, 2011 decreased $5 million and $10 million, respectively, compared to the same periods in 2010 primarily due to a lower rate of return on common equity (ROE), as determined by the National Energy Board (NEB), of 8.08 per cent in 2011 compared to 8.52 per cent in 2010, as well as a lower average investment base. The impact of the lower ROE and average investment base was partially offset by higher incentive earnings in 2011.
The Alberta System's net income was $51 million and $149 million for the three and nine months ended September 30, 2011 compared to $70 million and $145 million, respectively, for the same periods in 2010. The decrease in net income in third quarter 2011 compared to 2010 was primarily due to the regulatory approval and recognition in September 2010 of the Alberta System Settlement, which included a 9.70 per cent ROE on deemed common equity of 40 per cent, effective January 1, 2010. The increase in net income for the first nine months of 2011 compared to 2010 was primarily due to higher incentive earnings.
Canadian Mainline's Comparable EBITDA for the three and nine months ended September 30, 2011 of $264 million and $796 million, respectively, increased $7 million and $11 million, respectively, compared to the same periods in 2010. The Alberta System's Comparable EBITDA was $191 million and $557 million for the three and nine months ended September 30, 2011 compared to $197 million and $548 million, respectively, for the same periods in 2010. EBITDA from the Canadian Mainline and the Alberta System includes net income variances discussed above as well as flow-through items which do not affect net income.
U.S. Natural Gas Pipelines
ANR's Comparable EBITDA for the three and nine months ended September 30, 2011 was US$58 million and US$239 million, respectively, compared to US$64 million and US$238 million, respectively, for the same periods in 2010. The decrease in third quarter 2011 was primarily due to higher operating, maintenance and administration (OM&A) costs. For the nine months ended September 30, 2011, the increase was primarily due to higher transportation and storage revenues, a settlement with a counterparty and increased incidental commodity sales partially offset by higher OM&A costs.
GTN's Comparable EBITDA for the three and nine months ended September 30, 2011 was US$29 million and US$105 million, respectively, compared to US$42 million and US$125 million, respectively, for the same periods in 2010. The decreases were primarily due to TransCanada's sale of a 25 per cent interest in GTN to PipeLines LP in May 2011.
The Bison pipeline was placed in service on January 14, 2011. TransCanada's portion of Comparable EBITDA was US$8 million and US$35 million for the three and nine months ended September 30, 2011, respectively. EBITDA reflects TransCanada's 75 per cent interest in Bison subsequent to the sale of a 25 per cent interest in Bison to PipeLines LP in May 2011 and 100 per cent prior to that date.
Comparable EBITDA for the remainder of the U.S. Natural Gas Pipelines was US$146 million and US$416 million for the three and nine months ended September 30, 2011, respectively, compared to US$105 million and US$352 million, respectively, for the same periods in 2010. The increases were primarily due to incremental earnings from the Guadalajara pipeline, which was placed in service on June 15, 2011, lower general, administrative and support costs and higher Non-Controlling Interests due to the sale of a 25 per cent interest in GTN and Bison to PipeLines LP in May 2011.
Depreciation
Natural Gas Pipelines' depreciation increased $15 million and decreased $1 million for the three and nine months ended September 30, 2011, respectively, compared to the same periods in 2010. The increase in the third quarter was primarily due to an adjustment for the regulatory approval and recognition in September 2010 of the Alberta System Settlement which included a reduction in the composite depreciation rate, effective January 1, 2010, and incremental depreciation for Bison and Guadalajara partially offset by the effect of a weaker U.S. dollar.
Business Development
Natural Gas Pipelines' Business Development Comparable EBITDA loss increased $6 million and decreased $4 million in the three and nine months ended September 30, 2011, respectively, compared to the same periods in 2010. Business development costs increased in third quarter 2011 compared to third quarter 2010 primarily due to greater activity in 2011 for the Alaska Pipeline Project. Business development costs in the first nine months of 2011 decreased primarily due to the increased reimbursement by the State of Alaska to 90 per cent from 50 per cent effective July 31, 2010. Project applicable expenses and reimbursements are shared proportionately with ExxonMobil, TransCanada's joint venture partner in the Alaska Pipeline Project. The decrease in business development costs in the first nine months of 2011 was partially offset by a levy charged by the NEB in March 2011 to recover the Aboriginal Pipeline Group's proportionate share of costs relating to the Mackenzie Gas Project hearings.
Operating Statistics
(1) Canadian Mainline's throughput volumes in the above table reflect
physical deliveries to domestic and export markets. Canadian Mainline's
physical receipts originating at the Alberta border and in Saskatchewan
for the nine months ended September 30, 2011 were 912 billion cubic feet
(Bcf) (2010 - 927 Bcf); average per day was 3.3 Bcf (2010 - 3.4 Bcf).
(2) Field receipt volumes for the Alberta System for the nine months ended
September 30, 2011 were 2,643 Bcf (2010 - 2,619 Bcf); average per day
was 9.7 Bcf (2010 - 9.6 Bcf).
(3) ANR's results are not impacted by average investment base as these
systems operate under fixed-rate models approved by the U.S. Federal
Energy Regulatory Commission.
Oil Pipelines
Oil Pipelines Comparable EBIT for the three and eight months ended September 30, 2011, was $118 million and $313 million, respectively. At the beginning of February 2011, the Company commenced recording EBITDA for the Wood River/Patoka section of Keystone following the NEB's decision to remove the maximum operating pressure restriction along the conversion section of the system. The Cushing Extension was also placed in service at that time.
Oil Pipelines Results
(1) Refer to the Non-GAAP Measures section in this MD&A for further
discussion of Comparable EBITDA and Comparable EBIT.
Operating Statistics
(1) Delivery volumes reflect physical deliveries.
Energy
Energy's Comparable EBIT was $298 million and $745 million for the three and nine months ended September 30, 2011, respectively, compared to $217 million and $550 million, respectively, for the same periods in 2010.
Energy Results
Canadian Power
Western and Eastern Canadian Power Comparable EBIT(1)(2)
Western and Eastern Canadian Power Operating Statistics
Western Power's Comparable EBITDA of $152 million and Power Revenues of $326 million in third quarter 2011 increased $107 million and $158 million, respectively, compared to the same periods in 2010, primarily due to higher realized power prices in Alberta and incremental earnings from Coolidge, which went into service under a 20-year power purchase arrangement (PPA) in May 2011. Certain plant outages and higher demand resulted in average spot market power prices in Alberta increasing 164 per cent to $95 per megawatt hour (MWh) in third quarter 2011 compared to $36 per MWh in third quarter 2010.
Western Power's Comparable EBITDA of $346 million and Power Revenues of $787 million in the first nine months of 2011 increased $174 million and $253 million, respectively, compared to the same period in 2010 primarily due to higher overall realized prices in Alberta and incremental earnings from Coolidge.
Western Power's Comparable EBITDA in the three and nine months ended September 30, 2011 included $48 million and $99 million, respectively, of accrued earnings from the Sundance A PPA, the revenues and costs of which have been recorded as though the outages of Sundance A Units 1 and 2 are interruptions of supply in accordance with the terms of the PPA. Refer to the Recent Developments section in this MD&A for further discussion regarding the Sundance A outage.
Western Power's Commodity Purchases Resold of $157 million and $401 million for the three and nine months ended September 30, 2011, respectively, increased $48 million and $87 million, respectively, compared to the same periods in 2010 due to higher volumes at Sheerness, higher PPA costs per MWh and increased direct sales to customers.
Eastern Power's Comparable EBITDA of $76 million and $227 million for the three and nine months ended September 30, 2011, respectively, increased $20 million and $73 million, respectively, compared to the same periods in 2010. Similarly, Eastern Power's Power Revenues of $119 million and $350 million for the three and nine months ended September 30, 2011, respectively, increased $34 million and $133 million, respectively, compared to the same periods in 2010. The increases were primarily due to incremental earnings from Halton Hills, which went into service in September 2010.
Plant Operating Costs and Other, which includes fuel gas consumed in power generation, of $71 million and $206 million for the three and nine months ended September 30, 2011, increased $13 million and $55 million, respectively, compared to the same periods in 2010. The increases were primarily due to incremental fuel consumed at Halton Hills.
Depreciation and amortization increased $10 million and $21 million for the three and nine months ended September 30, 2011, respectively, compared to the same periods in 2010 primarily due to incremental depreciation from Halton Hills and Coolidge.
Western Power manages the sale of its supply volumes on a portfolio basis. A portion of its supply is sold into the spot market to assure supply in the event of an unexpected plant outage. The overall amount of spot market volumes sold is also dependent upon the ability to transact in forward sales markets at acceptable contract terms. This approach to portfolio management helps to minimize costs in situations where Western Power would otherwise have to purchase electricity in the open market to fulfill its contractual sales obligations. Approximately 81 per cent of Western Power sales volumes were sold under contract in third quarter 2011, compared to 76 per cent in third quarter 2010. To reduce its exposure to spot market prices on uncontracted volumes, as at September 30, 2011, Western Power had entered into fixed-price power sales contracts to sell approximately 2,300 gigawatt hours (GWh) in fourth quarter 2011 and 7,700 GWh for 2012.
Eastern Power is focused on selling power under long-term contracts. In third quarter 2011 and 2010, 100 per cent of Eastern Power's sales volumes were sold under contract and are expected to continue to be 100 per cent sold under contract for the remainder of 2011 and in 2012.
Bruce Power Results
TransCanada's proportionate share of Bruce A's Comparable EBITDA decreased $2 million in third quarter 2011 to $33 million compared to $35 million in third quarter 2010 as a result of higher operating costs, partially offset by increased revenues from higher volumes and higher realized prices.
TransCanada's proportionate share of Bruce B's Comparable EBITDA decreased $1 million in third quarter 2011 to $53 million compared to $54 million in third quarter 2010 as a result of increased revenues from higher volumes being more than offset by lower realized prices due to the expiration of fixed price contracts at higher prices.
TransCanada's proportionate share of Bruce A's Comparable EBITDA increased $41 million in the nine months ended September 30, 2011 to $99 million compared to the same period in 2010 primarily due to higher volumes and lower operating costs due to a decrease in outage days. Results for the nine months ended September 30, 2010 included a payment made from Bruce B to Bruce A regarding 2009 amendments to a long-term agreement with the Ontario Power Authority (OPA). The net positive impact reflected TransCanada's higher percentage ownership interest in Bruce A.
TransCanada's proportionate share of Bruce B's Comparable EBITDA decreased $21 million in the nine months ended September 30, 2011 to $120 million compared to the same period in 2010 primarily due to lower realized prices resulting from the expiration of fixed-price contracts at higher prices as well as lower volumes and higher operating costs due to increased outage days. Bruce B results for the nine months ended September 30, 2010 included the above-noted payment in first quarter 2010 to Bruce A.
Under a contract with the OPA, all output from Bruce A in third quarter 2011 was sold at a fixed price of $66.33 per MWh (before recovery of fuel costs from the OPA) compared to $64.71 per MWh in third quarter 2010. Also under a contract with the OPA, all output from the Bruce B units was subject to a floor price of $50.18 per MWh in third quarter 2011 compared to $48.96 per MWh in third quarter 2010. Both the Bruce A and Bruce B contract prices are adjusted annually for inflation on
April 1.
Amounts received under the Bruce B floor price mechanism within a calendar year are subject to repayment if the monthly average spot price exceeds the floor price. With respect to 2011, TransCanada currently expects spot prices to be less than the floor price for the remainder of the year, therefore no amounts recorded in revenues in the first nine months of 2011 are expected to be repaid.
Bruce B enters into fixed-price contracts whereby Bruce B receives or pays the difference between the contract price and the spot price. Bruce B's realized price decreased by $4 per MWh to $53 per MWh and $54 per MWh for the three and nine months ended September 30, 2011, respectively, and reflected revenues recognized from both the floor price mechanism and contract sales. The decreases were a result of the majority of higher-priced contracts entered into in previous years having expired by the end of December 2010. As the remainder of these higher-priced contracts continue to expire, a further reduction in realized prices at Bruce B is expected.
The overall plant availability percentage in 2011 is expected to be in the mid-80s for the two operating Bruce A units and for the four Bruce B units. Bruce B began an approximate seven week outage on Unit 5 on October 14, 2011, and Bruce A will commence an approximate six month outage (West Shift Plus program) on Unit 3 starting in November 2011.
As at September 30, 2011, TransCanada's share of the total capital cost of the Bruce A refurbishment and restart of Units 1 and 2 was $2.2 billion and was approximately $136 million for the refurbishment of Units 3 and 4.
U.S. Power Comparable EBIT(1)(2)
U.S. Power Operating Statistics(1)
U.S Power's Comparable EBITDA of US$90 million and US$241 million for the three and nine months ended September 30, 2011, respectively, decreased US$21 million and US$3 million, respectively, compared to the same periods in 2010 primarily due to lower volumes of power sold and lower realized prices partially offset by new sales activity in the PJM Interconnection area (PJM), an increase in the New York commercial customer base and incremental earnings from phase two of Kibby Wind which went into service in October 2010.
U.S. Power's Power Revenues of US$280 million for the three months ended September 30, 2011, decreased US$103 million compared to the same period in 2010 primarily due to lower volumes of power sold and lower realized prices on power sales partially offset by new sales activity in PJM and New York. For the nine months ended September 30, 2011, Power Revenues of US$759 million, decreased US$93 million compared to the same period in 2010, primarily due to lower volumes of power sold, partially offset by new sales activity in PJM and New York.
Capacity Revenues of US$70 million for the three months ended September 30, 2011, decreased US$4 million compared to the same period in 2010. For the nine months ended September 30, 2011, Capacity Revenues of US$183 million increased US$3 million compared to the same period in 2010. Capacity Revenues in third quarter 2011 were negatively impacted by low spot prices in New York as a result of the capacity price issue described in the Recent Developments section of this MD&A. Capacity revenues throughout 2010 were negatively impacted by higher forced outage rates at Ravenswood.
Commodity Purchases Resold of US$112 million and US$327 million for the three and nine months ended September 30, 2011, respectively, decreased US$60 million and US$93 million, respectively, compared to the same periods in 2010 primarily due to a decrease in the quantity of power purchased for resale.
Plant Operating Costs and Other, including fuel gas consumed in generation, of US$149 million in third quarter 2011, decreased US$33 million compared to the same period in 2010 primarily due to lower quantities of fuel purchased as a result of decreased generation. For the nine months ended September 30, 2011, Plant Operating Costs and Other of US$399 million was consistent with the same period in 2010.
U.S. Power focuses on selling power under short- and long-term contracts to wholesale, commercial and industrial customers in the New England, New York and PJM power markets. Exposure to fluctuations in spot prices on these power sales commitments are hedged with a combination of forward purchases of power, forward purchases of fuel to generate power and through the use of financial contracts. As at September 30, 2011, approximately 1,600 GWh or 73 per cent and 2,800 GWh or 31 per cent of U.S. Power's planned generation is contracted for fourth quarter 2011 and fiscal 2012, respectively. Planned generation fluctuates depending on hydrology, wind conditions, commodity prices and the resulting dispatch of the assets, and power sales fluctuate based on customer usage.
Natural Gas Storage
Natural Gas Storage's Comparable EBITDA for the three and nine month periods ended September 30, 2011, was $13 million and $60 million, respectively, compared to $26 million and $95 million for the same periods in 2010. The decreases in Comparable EBITDA in 2011 were primarily due to decreased third party and proprietary storage revenues as a result of lower realized natural gas price spreads, partially offset by lower operating costs.
Other Income Statement Items
Comparable Interest Expense(1)
(1) Refer to the Non-GAAP Measures section in this MD&A for further
discussion of Comparable Interest Expense.
(2) Includes interest on Junior Subordinated Notes.
Comparable Interest Expense for third quarter 2011 increased $83 million to $242 million from $159 million in third quarter 2010. Comparable Interest Expense for the nine months ended September 30, 2011 increased $160 million to $688 million from $528 million for the nine months ended September 30, 2010. The increases reflected lower capitalized interest for Keystone and Halton Hills as a result of placing these assets into service and incremental interest expense on debt issues of US$1.25 billion in June 2010 and US$1.0 billion in September 2010. These increases were partially offset by realized gains in 2011 compared to losses in 2010 on derivatives used to manage the Company's exposure to rising interest rates, the positive impact of a weaker U.S. dollar on U.S. dollar-denominated interest costs and Canadian dollar-denominated debt maturities in 2011 and 2010.
Comparable Interest Income and Other for third quarter 2011 decreased $32 million to a loss of $5 million from income of $27 million in third quarter 2010. The decreases in third quarter reflected realized losses in 2011 compared to gains in 2010 on derivatives used to manage the Company's net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income. Comparable Interest Income and Other for the nine months ended September 30, 2011 increased $19 million to $52 million from $33 million for the nine months ended September 30, 2010. The increase for the nine months ended September 30, 2011 reflected higher realized gains in 2011 compared to 2010 on similar foreign exchange derivatives.
Comparable Income Taxes were $147 million in third quarter 2011 compared to $119 million for the same period in 2010. Comparable Income Taxes for the nine months ended September 30, 2011 were $472 million compared to $297 million for the same period in 2010. The increases were primarily due to higher pre-tax earnings in 2011 compared to 2010 and higher positive income tax adjustments in 2010 compared to 2011.
Liquidity and Capital Resources
TransCanada believes that its financial position remains sound as does its ability to generate cash in the short and long term to provide liquidity, maintain financial capacity and flexibility, and provide for planned growth. TransCanada's liquidity is underpinned by predictable cash flow from operations, cash balances on hand and unutilized committed revolving bank lines of US$1.0 billion, $2.0 billion, US$1.0 billion and US$300 million, maturing in November 2011, October 2016, October 2012 and February 2013, respectively. These facilities also support the Company's commercial paper programs. In addition, at September 30, 2011, TransCanada's proportionate share of unutilized capacity on committed bank facilities at TransCanada-operated affiliates was $183 million with maturity dates in 2012 and 2016. As at September 30, 2011, TransCanada had remaining capacity of $1.75 billion, $2.0 billion and US$1.75 billion under its equity, Canadian debt and U.S. debt shelf prospectuses, respectively.
On October 21, 2011, the Company's $3.0 billion equity base shelf prospectus expired with remaining capacity of $1.75 billion. In November 2011, TransCanada intends to file a new $2.0 billion equity base shelf prospectus. In November 2011, the Company also intends to file a new US$4.0 billion U.S. debt base shelf prospectus to replace its December 2009 US$4.0 billion U.S. debt base shelf prospectus, which is due to expire in January 2012 and has remaining capacity of US$1.75 billion. TransCanada's liquidity, market and other risks are discussed further in the Risk Management and Financial Instruments section in this MD&A.
At September 30, 2011, the Company held Cash and Cash Equivalents of $596 million compared to $764 million at December 31, 2010. The decrease in Cash and Cash Equivalents was primarily due to expenditures for the Company's capital program, debt repayments and dividend payments, partially offset by increased Net Cash Provided by Operations.
Operating Activities
Funds Generated from Operations(1)
(1) Refer to the Non-GAAP Measures section in this MD&A for further
discussion of Funds Generated from Operations.
Net Cash Provided by Operations increased $274 million and $726 million for the three and nine months ended September 30, 2011, respectively, compared to the same periods in 2010, largely as a result of changes in operating working capital as well as increased Funds Generated from Operations. Funds Generated from Operations for the three and nine months ended September 30, 2011 were $971 million and $2.8 billion, compared to $861 million and $2.5 billion, respectively, for the same periods in 2010. The increases were primarily due to an increase in cash generated through earnings, partially offset by the recognition in 2010 of current income tax benefits from U.S. bonus tax depreciation.
As at September 30, 2011, TransCanada's current liabilities were $5.6 billion and current assets were $3.0 billion resulting in a working capital deficiency of $2.6 billion. The Company believes this shortfall can be managed through its ability to generate cash flow from operations as well as its ongoing access to capital markets.
Investing Activities
TransCanada remains committed to executing its remaining $11 billion capital expenditure program. For the three and nine months ended September 30, 2011, capital expenditures totalled $696 million and $2.1 billion, respectively (2010 - $1.3 billion and $3.6 billion, respectively), primarily related to the construction of Keystone, the refurbishment and restart of Bruce A Units 1 and 2, and expansion of the Alberta System.
Financing Activities
On October 14, 2011, TransCanada PipeLines Limited (TCPL) amended and restated its $2.0 billion committed, syndicated, revolving, extendible credit facility. The amended and restated facility is set to expire October 2016 and is fully available.
On October 14, 2011, a wholly-owned subsidiary of the Company, TransCanada PipeLine USA Ltd., refinanced its existing US$1.0 billion credit facility with a new 364-day, US$1.0 billion committed, syndicated, revolving, extendible credit facility which is fully available.
In August 2011, TransCanada PipeLine USA Ltd. made a principal repayment of US$200 million on its US$700 million, five-year term loan which matures in 2012.
In July 2011, PipeLines LP increased its senior syndicated revolving credit facility to US$500 million and extended the maturity date to July 2016. PipeLines LP's remaining US$300 million term loan matures December 2011, and it is expected it will be refinanced with fixed or floating rate debt at or prior to its maturity.
In June 2011, TCPL retired $60 million of 9.5 per cent Medium-Term Notes and, in January 2011, retired $300 million of 4.3 per cent Medium-Term Notes.
In June 2011, PipeLines LP issued US$350 million of 4.65 per cent Senior Notes due 2021 and cancelled US$175 million of its unsecured syndicated senior credit facility. The proceeds from the issuance were used to reduce PipeLines LP's term loan and senior revolving credit facility, and repay its bridge loan facility.
In May 2011, PipeLines LP completed a public offering of 7.2 million common units at a price of US$47.58 per unit, resulting in gross proceeds of approximately US$345 million. TransCanada contributed an additional approximate US$7 million to maintain its general partnership interest and did not purchase any other units. Upon completion of this offering, TransCanada's ownership interest in PipeLines LP decreased from 38.2 per cent to 33.3 per cent. In addition, PipeLines LP made draws of US$61 million on a bridge loan facility and of US$125 million on its senior revolving credit facility.
In June 2011, TCPL filed a $2.0 billion Canadian Medium-Term Notes base shelf prospectus to replace an April 2009 $2.0 billion Canadian Medium-Term Notes base shelf prospectus which expired in May 2011 and had remaining capacity of $2.0 billion.
The Company believes it has the capacity to fund its existing capital program through internally-generated cash flow, continued access to capital markets and liquidity underpinned by in excess of $4 billion of committed credit facilities. TransCanada's financial flexibility is further bolstered by opportunities for portfolio management, including an ongoing role for PipeLines LP.
Dividends
On October 31, 2011, TransCanada's Board of Directors declared a quarterly dividend of $0.42 per share for the quarter ending December 31, 2011 on the Company's outstanding common shares. The dividend is payable on January 31, 2012 to shareholders of record at the close of business on December 30, 2011. In addition, quarterly dividends of $0.2875 and $0.25 per Series 1 and Series 3 preferred share, respectively, were declared for the quarter ending September 30, 2011. The dividends are payable on December 30, 2011 to shareholders of record at the close of business on November 30, 2011. Furthermore, a quarterly dividend of $0.275 per Series 5 preferred share was declared for the period ending January 30, 2012, payable on January 30, 2012 to shareholders of record at the close of business on December 30, 2011.
Commencing with the dividends declared April 28, 2011, common shares purchased with reinvested cash dividends under TransCanada's Dividend Reinvestment and Share Purchase Plan (DRP) will no longer be satisfied with shares issued from treasury at a discount but rather will be acquired on the open market at 100 per cent of the weighted average purchase price. The DRP is available for dividends payable on TransCanada's common and preferred shares, and TCPL's preferred shares. In the three and nine months ended September 30, 2011, TransCanada issued nil and 5.4 million (2010 - 2.9 million and 7.8 million) common shares, respectively, under its DRP, in lieu of making cash dividend payments of nil and $202 million, respectively (2010 - $101 million and $271 million).
Contractual Obligations
There have been no material changes to TransCanada's contractual obligations from December 31, 2010 to September 30, 2011, 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 2010 Annual Report.
Significant Accounting Policies and Critical Accounting Estimates
To prepare financial statements that conform with 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, 2010. For further information on the Company's accounting policies and estimates refer to the MD&A in TransCanada's 2010 Annual Report.
Changes in Accounting Policies
The Company's accounting policies have not changed materially from those described in TransCanada's 2010 Annual Report except as follows:
Changes in Accounting Policies for 2011
Business Combinations, Consolidated Financial Statements and Non-Controlling Interests
Effective January 1, 2011, the Company adopted CICA Handbook Section 1582 "Business Combinations", which is effective for business combinations with an acquisition date after January 1, 2011. This standard was amended to require additional use of fair value measurements, recognition of additional assets and liabilities, and increased disclosure. Adopting the standard is expected to have a significant impact on the way the Company accounts for future business combinations. Entities adopting Section 1582 were also required to adopt CICA Handbook Sections 1601 "Consolidated Financial Statements" and 1602 "Non-Controlling Interests". Sections 1601 and 1602 require Non-Controlling Interests to be presented as part of Equity on the balance sheet. In addition, the income statement of the controlling parent now includes 100 per cent of the subsidiary's results and presents the allocation of income between the controlling and non-controlling interests. Changes resulting from the adoption of Section 1582 were applied prospectively and changes resulting from the adoption of Sections 1601 and 1602 were applied retrospectively.
Future Accounting Changes
U.S. GAAP/International Financial Reporting Standards
The CICA's Accounting Standards Board (AcSB) previously 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 October 2010, the AcSB and the Canadian Securities Administrators amended their policies applicable to Canadian publicly accountable enterprises, such as TransCanada, that use rate-regulated accounting (RRA) in order to permit these entities to defer the adoption of IFRS for one year. TransCanada deferred its adoption and accordingly will continue to prepare its consolidated financial statements in 2011 in accordance with Canadian GAAP, as defined by Part V of the CICA Handbook, in order to continue using RRA.
In the application of Canadian GAAP, TransCanada follows specific accounting guidance under U.S. GAAP unique to a rate-regulated business. These RRA standards allow the timing of recognition of certain revenues and expenses to differ from the timing that may otherwise be expected in a non-rate-regulated business under GAAP in order to appropriately reflect the economic impact of regulators' decisions regarding the Company's revenues and tolls. The IASB concluded that the development of RRA under IFRS requires further analysis and removed the RRA project from its current agenda. TransCanada does not expect a final RRA standard under IFRS to be effective in the foreseeable future.
As an SEC registrant, TransCanada prepares and files a "Reconciliation to United States GAAP" and has the option under Canadian disclosure rules to prepare and file its consolidated financial statements using U.S. GAAP. As a result of the developments noted above, the Company's Board of Directors has approved the adoption of U.S. GAAP effective January 1, 2012.
U.S. GAAP Conversion Project
Effective January 1, 2012, the Company will begin reporting using U.S. GAAP. The Company's U.S. GAAP conversion team is led by a multi-disciplinary Steering Committee that provides directional leadership for the adoption of U.S. GAAP. Management also updates TransCanada's Audit Committee on the progress of the U.S. GAAP project at each Audit Committee meeting and reports regularly to the Company's Board of Directors on the status of the conversion project.
U.S. GAAP training sessions for TransCanada staff have been completed and periodic training updates will continue in the future. As noted above, TransCanada prepares and files a "Reconciliation to United States GAAP". As a result, significant changes to existing systems and processes are not required to implement U.S. GAAP as the Company's primary accounting standard. The impact to internal controls over financial reporting and disclosure controls and procedures are currently being assessed and necessary changes, if any, will be in place by the end of 2011.
Identified differences between Canadian GAAP and U.S. GAAP that are significant to the Company are explained below and are consistent with those currently reported in the Company's publicly-filed "Reconciliation to United States GAAP."
Joint Ventures
Canadian GAAP requires the Company to account for certain investments using the proportionate consolidation method of accounting whereby TransCanada's proportionate share of assets, liabilities, revenues, expenses and cash flows are included in the Company's financial statements. U.S. GAAP does not permit the use of proportionate consolidation with respect to TransCanada's joint ventures and requires that such investments be recorded using the equity method of accounting.
Inventory
Canadian GAAP allows the Company's proprietary natural gas inventory held in storage to be recorded at its fair value. Under U.S. GAAP, inventory is recorded at the lower of cost or market.
Income Tax
Canadian GAAP requires an entity to record income tax assets and liabilities resulting from substantively enacted income tax legislation. Under U.S. GAAP, the legislation must be fully enacted for income tax adjustments to be recorded.
Employee Benefits
Canadian GAAP requires an entity to recognize an accrued benefit asset or liability for defined benefit pension and other postretirement benefit plans. Under U.S. GAAP, an employer is required to recognize the overfunded or underfunded status of defined benefit pension and other postretirement benefit plans as an asset or liability in its balance sheet and to recognize changes in the funded status through Other Comprehensive Income in the year in which the change occurs.
Debt Issue Costs
Canadian GAAP requires debt issue costs to be included in long-term debt. Under U.S. GAAP these costs are classified as deferred assets.
Financial Instruments and Risk Management
TransCanada continues to manage and monitor its exposure to counterparty credit, liquidity and market risk.
Counterparty Credit and Liquidity Risk
TransCanada's maximum counterparty credit exposure with respect to financial instruments at the balance sheet date, without taking into account security held, consisted of accounts receivable, portfolio investments recorded at fair value, the fair value of derivative assets, and notes, loans and advances receivable. The carrying amounts and fair values of these financial assets, except amounts for derivative assets, are included in Accounts Receivable and Other, and Available-For-Sale Assets in the Non-Derivative Financial Instruments Summary table below. Guarantees, letters of credit and cash are the primary types of security provided to support these amounts. The majority of counterparty credit exposure is with counterparties who are investment grade. At September 30, 2011, there were no significant amounts past due or impaired.
At September 30, 2011, the Company had a credit risk concentration of $271 million due from a creditworthy counterparty. This amount is expected to be fully collectible and is secured by a guarantee from the counterparty's parent company.
The Company continues to manage its liquidity risk by ensuring sufficient cash and credit facilities are available to meet its operating and capital expenditure obligations when due, under both normal and stressed economic conditions.
Natural Gas Storage Commodity Price Risk
At September 30, 2011, the fair value of proprietary natural gas inventory held in storage, as measured using a weighted average of forward prices for the following four months less selling costs, was $40 million (December 31, 2010 - $49 million). The change in the fair value adjustment of proprietary natural gas inventory in storage in the three and nine months ended September 30, 2011 resulted in net pre-tax unrealized losses of $1 million and nil, respectively (2010 - nil and losses of $20 million, respectively), which were recorded as adjustments to Revenues and Inventories. The change in fair value of natural gas forward purchase and sale contracts in the three and nine months ended September 30, 2011 resulted in net pre-tax unrealized losses of $3 million and $13 million, respectively (2010 - gains of $7 million and $12 mi
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Datum: 01.11.2011 - 12:11 Uhr
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