CALGARY, ALBERTA — (Marketwire) — 07/28/11 — TransCanada Corporation (TSX: TRP) (NYSE: TRP) (TransCanada or the Company) today announced comparable earnings for second quarter 2011 of $357 million or $0.51 per share. Net income attributable to common shares was $353 million or $0.50 per share. TransCanada–s Board of Directors also declared a quarterly dividend of $0.42 per common share for the quarter ending September 30, 2011, equivalent to $1.68 per share on an annualized basis.
“We continue to experience strong earnings and cash flow growth as our company realizes the benefits of major projects that have started operations over the last year,” said Russ Girling, TransCanada–s president and chief executive officer. “Those benefits have translated into a 30 per cent increase in comparable earnings for the second quarter of 2011, compared to the same period in 2010.”
TransCanada has completed and brought into service more than $10 billion of assets under its capital growth program. Most recently, the Company–s Guadalajara pipeline began shipping natural gas in Mexico in mid June. In early May, TransCanada–s Coolidge Generating Station began producing power in Arizona under a 20-year power purchase arrangement (PPA) with a local utility.
Earlier in 2011 and in 2010, the company brought into service the first and second phases of the Keystone oil pipeline system, the Bison and Groundbirch natural gas pipelines, Maine–s largest wind project – Kibby Wind, the Halton Hills Generating Station in Ontario and the North Central Corridor gas pipeline in northern Alberta.
Looking forward, TransCanada is focused on completing the remaining projects that are part of its current capital program – 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 Cartier Wind power project in Quebec. Each is expected to generate long-term, sustainable earnings and cash flow as they begin operations.
Second Quarter Highlights
(All financial figures are unaudited and in Canadian dollars unless noted otherwise)
Comparable earnings for second quarter 2011 were $357 million ($0.51 per share) compared to $275 million ($0.40 per share) in the same period in 2010. The increase was primarily due to incremental earnings from recently commissioned assets including Keystone, Halton Hills, Bison and Coolidge. Also contributing to the year-over-year increase in earnings were higher Natural Gas Pipeline earnings from the Alberta System and ANR and higher Energy earnings from U.S. Power and Bruce A. Partially offsetting these increases were higher interest costs and a lower contribution from Western Power and Bruce B.
Notable recent developments in Oil Pipelines, Natural Gas Pipelines, Energy and Corporate include:
Teleconference and Webcast – Audio and Slide Presentation:
TransCanada will hold a teleconference and webcast to discuss its 2011 second 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 second quarter financial results teleconference and webcast
Date:
Thursday, July 28, 2011
Time:
2:30 p.m. mountain daylight time (MDT) / 4:30 p.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) August 4, 2011. Please call (800) 408-3053 or (905) 694-9451 (Toronto area) and enter pass code 5762531#.
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: .
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. All forward-looking statements reflect TransCanada–s beliefs and assumptions based on information available at the time the statements were made. Actual results or events may differ from those predicted in these forward-looking statements. Factors that could cause actual results or events to differ materially from current expectations include, among others, the ability of TransCanada to successfully implement its strategic initiatives and whether such strategic initiatives will yield the expected benefits, the operating performance of the Company–s pipeline and energy assets, the availability and price of energy commodities, capacity payments, regulatory processes and decisions, changes in environmental and other laws and regulations, competitive factors in the pipeline and energy sectors, construction and completion of capital projects, labour, equipment and material costs, access to capital markets, interest and currency exchange rates, technological developments and economic conditions in North America. By its nature, forward-looking information is subject to various risks and uncertainties, which could cause TransCanada–s actual results and experience to differ materially from the anticipated results or expectations expressed. Additional information on these and other factors is available in the reports filed by TransCanada with Canadian securities regulators and with the U.S. Securities and Exchange Commission.
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 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 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 Second Quarter 2011 Financial Highlights table in this news release.
Quarterly Report to Shareholders
Management–s Discussion and Analysis
Management–s Discussion and Analysis (MD&A) dated July 28, 2011 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, 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), and operating and financial results, and expected impact of future commitments and contingent liabilities. All forward-looking statements reflect TransCanada–s beliefs and assumptions based on information available at the time the statements were made. Actual results or events may differ from those predicted in these forward-looking statements. Factors that could cause actual results or events to differ materially from current expectations include, among others, the ability of TransCanada to successfully implement its strategic initiatives and whether such strategic initiatives will yield the expected benefits, the operating performance of the Company–s pipeline and energy assets, the availability and price of energy commodities, capacity payments, regulatory processes and decisions, changes in environmental and other laws and regulations, competitive factors in the pipeline and energy sectors, construction and completion of capital projects, labour, equipment and material costs, access to capital markets, interest and currency exchange rates, technological developments and economic conditions in North America. By its nature, forward-looking information is subject to various risks and uncertainties, 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.
Consolidated Results of Operations
TransCanada–s Net Income Attributable to Controlling Interests in second quarter 2011 was $367 million and Net Income Attributable to Common Shares was $353 million or $0.50 per share compared to $295 million and $285 million or $0.41 per share, respectively, in second quarter 2010.
Comparable Earnings in second quarter 2011 were $357 million or $0.51 per share compared to $275 million or $0.40 per share for the same period in 2010. Comparable Earnings in second quarter 2011 excluded net unrealized after-tax losses of $4 million ($5 million pre-tax) (2010 – gains of $10 million after tax ($15 million pre-tax)) resulting from changes in the fair value of certain risk management activities.
Comparable Earnings increased $82 million or $0.11 per share in second quarter 2011 compared to the same period in 2010 and reflected the following:
TransCanada–s Net Income Attributable to Controlling Interests in the first six months of 2011 was $796 million and Net Income Attributable to Common Shares was $768 million or $1.10 per share compared to $598 million and $581 million or $0.84 per share, respectively, for the same period in 2010.
Comparable Earnings in the first six months of 2011 were $782 million or $1.12 per share compared to $603 million or $0.87 per share for the same period in 2010. Comparable Earnings for the first six months of 2011 excluded net unrealized after-tax losses of $14 million ($22 million pre-tax) (2010 – after-tax losses of $22 million ($34 million pre-tax)) resulting from changes in the fair value of certain risk management activities.
Comparable Earnings increased $179 million or $0.25 per share in the first six months of 2011 compared to the same period in 2010 and reflected the following:
Further discussion of the significant financial results in the first three and six months in 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 six months ended June 30, 2011 was 0.97 and 0.98, respectively (2010 – 1.03 and 1.03, respectively).
Canadian Natural Gas Pipelines
Canadian Mainline–s net income for the three and six months ended June 30, 2011 decreased $1 million and $5 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.
Canadian Mainline–s Comparable EBITDA for the three and six months ended June 30, 2011 of $267 million and $532 million, respectively, increased $4 million compared to each of the same periods in 2010. An increase in revenues as a result of higher incentive earnings and higher flow-through costs was partially offset by a lower overall return, associated with the reduced ROE and financial charges, on a reduced average investment base. The flow-through costs do not impact net income and increased primarily due to higher income taxes.
The Alberta System–s net income was $50 million in second quarter 2011 and $98 million for the first six months of 2011 compared to $37 million and $75 million for the same periods in 2010. The increases reflect an ROE of 9.70 per cent on 40 per cent deemed common equity approved by the NEB in September 2010 as part of the Company–s 2010 – 2012 Revenue Requirement Settlement application. Net income in 2010 reflected an ROE of 8.75 per cent on 35 per cent deemed common equity.
The Alberta System–s Comparable EBITDA was $181 million in second quarter 2011 and $366 million for the first six months of 2011 compared to $176 million and $351 million for the same periods in 2010. The increases were primarily due to the increased ROE included in the 2010 – 2012 Revenue Requirement Settlement.
U.S. Natural Gas Pipelines
ANR–s Comparable EBITDA for the three and six months ended June 30, 2011 was US$70 million and US$181 million, respectively, compared to US$59 million and US$174 million for the same periods in 2010. The increases were 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 six months ended June 30, 2011 was US$31 million and US$76 million, respectively, compared to US$40 million and US$83 million for the same periods in 2010. The decreases were primarily due to TransCanada–s sale of 25 per cent of GTN to PipeLines LP in May 2011.
The Bison pipeline was placed in service in January 2011. TransCanada–s portion of Comparable EBITDA was US$14 million and US$27 million for the three and six months ended June 30, 2011, respectively. EBIDTA reflects TransCanada–s sale of 25 per cent of Bison to PipeLines LP in May 2011.
Comparable EBITDA for the remainder of the U.S. Natural Gas Pipelines was US$157 million and US$346 million for the three and six months ended June 30, 2011, respectively, compared to US$152 million and US$333 million for the same periods in 2010. The increases were primarily due to higher revenues for Northern Border, lower general, administrative and support costs, and incremental earnings from the Guadalajara pipeline which was placed in service on June 15, 2011.
Depreciation
Natural Gas Pipelines– depreciation decreased $7 million and $16 million for the three and six months ended June 30, 2011, respectively, compared to the same periods in 2010. The decreases were primarily due to lower depreciation rates included in the Great Lakes and Alberta System rate settlements, and the effect of a weaker U.S. dollar on U.S. asset depreciation, partially offset by incremental depreciation for Bison.
Business Development
Natural Gas Pipelines– Business Development Comparable EBITDA loss increased $5 million and decreased $10 million in the three and six months ended June 30, 2011, respectively, compared to the same periods in 2010. Business development costs increased in second quarter 2011 compared to second quarter 2010 primarily due to greater activity in 2011 for the Alaska Pipeline Project, partially offset by a 90 per cent reimbursement by the State of Alaska for eligible project costs effective July 31, 2010 versus a 50 per cent reimbursement prior to this date. Business development costs in the first six months of 2011 were lower primarily due to the increased reimbursement by the State of Alaska. 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 six 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
Oil Pipelines
In the three and five months ended June 30, 2011, the Company recorded $119 million and $195 million, respectively, of Comparable EBIT related to the Oil Pipelines segment. In late January 2011, work was completed to allow Keystone to increase its operating pressure following the NEB–s decision to remove the maximum operating pressure restriction along the conversion section of the system in December 2010. At the beginning of February 2011, the Company commenced recording EBITDA for the Wood River/Patoka section of Keystone and for the Cushing Extension, which was placed in service at that time.
Western Power–s Comparable EBITDA of $74 million and Power Revenues of $182 million in second quarter 2011 decreased $11 million and $20 million, respectively, compared to the same period in 2010, primarily due to lower realized power prices in Alberta, partially offset by incremental earnings from Coolidge, which went into service under a 20-year power purchase arrangement (PPA) in May 2011. Average spot market power prices in Alberta decreased 35 per cent to $52 per megawatt hour (MWh) in second quarter 2011 compared to $80 per MWh in second quarter 2010 when certain unplanned plant and transmission outages resulted in significantly higher spot prices.
Western Power–s Comparable EBITDA of $194 million and Power Revenues of $461 million in the first six months of 2011 increased $67 million and $95 million, respectively, compared to the same period in 2010 primarily due to higher overall realized prices and incremental earnings from Coolidge.
Western Power–s Comparable EBITDA in the three and six months ended June 30, 2011 included $12 million and $51 million, respectively, of accrued earnings from the Sundance A PPA, the revenues and costs of which have been recorded as though Sundance A Units 1 and 2 were on normal plant outages. Refer to the Recent Developments section in this MD&A for further discussion regarding the Sundance A outage.
Western Power–s Commodity Purchases Resold increased $39 million for the six months ended June 30, 2011 compared to the same period in 2010 primarily due to higher volumes at Sheerness and increased retail contracts.
Eastern Power–s Comparable EBITDA of $71 million and $151 million for the three and six months ended June 30, 2011, respectively, increased $25 million and $53 million, respectively, compared to the same periods in 2010. Power Revenues of $113 million and $231 million for the three and six months ended June 30, 2011, respectively, increased $48 million and $99 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 of $63 million and $135 million for the three and six months ended June 30, 2011, respectively, which includes fuel gas consumed in power generation, increased $18 million and $42 million, respectively, compared to the same periods in 2010 primarily due to incremental fuel consumed at Halton Hills.
Depreciation and amortization increased $9 million and $11 million for the three and six months ended June 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 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 77 per cent of Western Power sales volumes were sold under contract in second quarter 2011, compared to 82 per cent in second quarter 2010. To reduce its exposure to spot market prices on uncontracted volumes, as at June 30, 2011, Western Power had entered into fixed-price power sales contracts to sell approximately 4,600 gigawatt hours (GWh) for the remainder of 2011 and 7,500 GWh for 2012.
Eastern Power is focused on selling power under long-term contracts. In second 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.
TransCanada–s proportionate share of Bruce A–s Comparable EBITDA for the three and six months ended June 30, 2011 of $32 million and $66 million, respectively, increased from $10 million and $23 million, respectively, in the same periods in 2010 as a result of higher volumes and lower operating expenses due to lower planned and unplanned outage days. Results for the six months ended June 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 for the three and six months ended June 30, 2011 of $24 million and $67 million, respectively, decreased from $37 million and $87 million, respectively, in the same periods in 2010 primarily due to lower volumes and higher operating costs due to increased outage days, as well as lower realized prices resulting from the expiration of fixed-price contracts at higher prices. Results for the six months ended June 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 second 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 second 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 second quarter 2011 compared to $48.96 per MWh in second 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 six 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 to $55 per MWh and $54 per MWh for the three and six months ended June 30, 2011, respectively, a decrease of $4 per MWh from each of the same periods in 2010, 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 in future periods 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 in the mid-80s for the four Bruce B units. Bruce B commenced an approximately three week outage on Unit 6 in late July 2011. For further information on Bruce Power–s planned maintenance outages, refer to the MD&A in TransCanada–s 2010 Annual Report.
As at June 30, 2011, Bruce A had incurred approximately $4.4 billion in costs for the refurbishment and restart of Units 1 and 2, and approximately $0.3 billion for the refurbishment of Units 3 and 4.
U.S Power–s Comparable EBITDA of US$89 million and US$151 million for the three and six months ended June 30, 2011, respectively, increased US$20 million and US$18 million, respectively, compared to the same periods in 2010. The increases were primarily due to increased capacity revenues, higher realized power prices and incremental earnings from phase two of Kibby Wind which went into service in October 2010.
U.S. Power–s Power Revenues of US$224 for the three months ended June 30, 2011 decreased US$13 million compared to the same period in 2010, primarily due to lower physical volumes of power sold, partially offset by higher realized power prices, incremental revenues from the second phase of Kibby Wind, new sales activity in the PJM Interconnection area (PJM) and an increase in the New York commercial customer base. For the six months ended June 30, 2011, U.S. Power–s Power Revenues were US$479 million, an increase of US$10 million from the same period in 2010 as a result of higher realized power prices, incremental revenues from the second phase of Kibby Wind and additional revenue from PJM and New York commercial customers, partially offset by lower volumes of power sold.
Capacity Revenues of US$74 million and US$113 million for the three and six months ended June 30, 2011, respectively, increased from US$66 million and US$106 million, respectively, in the same periods in 2010 primarily due to a reduction in forced outage rates at Ravenswood, partially offset by lower capacity prices in the New England power market.
Commodity Purchases Resold of US$84 million and US$215 million for the three and six months ended June 30, 2011, respectively, decreased from US$112 million and US$248 million, respectively, in the same periods in 2010 primarily due to a decrease in the quantity of power purchased for resale, partially offset by higher power prices per MWh purchased.
Plant Operating Costs and Other, including fuel gas consumed in generation, of US$128 million in second quarter 2011, was consistent with second quarter 2010. For the six months ended June 30, 2011, Plant Operating Costs and Other were US$250 million, an increase of US$34 million from the same period in 2010 primarily due to higher fuel costs as a result of increased generation, incremental operating costs from the second phase of Kibby Wind and reduced lease costs related to Ravenswood 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 June 30, 2011, approximately 3,100 GWh or 67 per cent of U.S. Power–s planned generation is contracted for the remainder of 2011. 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. The seasonal nature of the U.S. Power business generally results in higher generation volumes in the summer months.
Natural Gas Storage
Natural Gas Storage–s Comparable EBITDA for the three and six month periods ended June 30, 2011, was $18 million and $47 million, respectively, compared to $18 million and $69 million, respectively, for the same periods in 2010. The decrease in Comparable EBITDA in the six months ended June 30, 2011 compared to the same period in 2010 was primarily due to decreased proprietary and third-party storage revenues as a result of lower realized natural gas price spreads.
Comparable Interest Expense for second quarter 2011 increased $49 million to $236 million from $187 million in second quarter 2010. Comparable Interest Expense for the six months ended June 30, 2011 increased $77 million to $446 million from $369 million for the six months ended June 30, 2010. The increases reflected lower capitalized interest for Keystone and Halton Hills as assets were placed 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 from 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 and Canadian dollar-denominated debt maturities in 2011 and 2010.
Comparable Interest Income and Other for second quarter 2011 increased $44 million to income of $26 million from an expense of $18 million in second quarter 2010. Comparable Interest Income and Other for the six months ended June 30, 2011 increased $51 million to income of $57 million from income of $6 million for the six months ended June 30, 2010. The increases reflected realized gains in 2011 compared to losses in 2010 on derivatives used to manage the Company–s net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income and from the translation of working capital balances due to a weakening of the U.S. dollar.
Comparable Income Taxes were $140 million in second quarter 2011 compared to $60 million for the same period in 2010. Comparable Income Taxes for the six months ended June 30, 2011 were $325 million compared to $178 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 and consistent with recent years as does its ability to generate cash in the short and long term to provide liquidity, maintain financial capacity and flexibility, and provide for planned growth. TransCanada–s liquidity 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$200 million, maturing in November 2011, December 2012, December 2012 and February 2013, respectively. These facilities also support the Company–s commercial paper programs. In addition, at June 30, 2011, TransCanada–s proportionate share of unutilized capacity on committed bank facilities at TransCanada-operated affiliates was $169 million with maturity dates in 2011 and 2012. As at June 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. TransCanada–s liquidity, market and other risks are discussed further in the Risk Management and Financial Instruments section in this MD&A.
At June 30, 2011, the Company held Cash and Cash Equivalents of $468 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 cash generated from operations.
Net Cash Provided by Operations increased $275 million and $452 million for the three and six months ended June 30, 2011, respectively, compared to the same periods in 2010, largely as a result of changes in operating working capital. The six months ended June 30, 2011 also reflected an increase in Funds Generated from Operations. Funds Generated from Operations for the three and six months ended June 30, 2011 were $892 million and $1.8 billion, respectively, compared to $935 million and $1.7 billion, respectively, for the same periods in 2010. The decrease for the three months ended June 30, 2011 was primarily due to the second quarter 2010 income tax benefit generated from bonus depreciation for U.S. tax purposes on Keystone assets placed in service in June 2010. Cash generated through earnings increased in second quarter 2011 compared to second quarter 2010 excluding the 2010 income tax benefit from bonus depreciation. The increase for the six months ended June 30, 2011 was primarily due to an increase in cash generated through earnings, partially offset by the 2010 income tax benefit from bonus depreciation.
As at June 30, 2011, TransCanada–s current liabilities were $4.6 billion and current assets were $2.8 billion resulting in a working capital deficiency of $1.8 billion. Excluding $1.6 billion of Notes Payable under the Company–s commercial paper programs and draws on its line-of-credit facilities, TransCanada–s working capital deficiency was $0.2 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 six months ended June 30, 2011, capital expenditures totalled $0.7 billion and $1.4 billion, respectively (2010 – $1.0 billion and $2.3 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 July 13, 2011, PipeLines LP entered into a five-year, US$500 million senior syndicated revolving credit facility, maturing July 2016. The proceeds from the credit facility were used to reduce PipeLines LP–s term loan and senior revolving credit facility, and repay its bridge loan facility. PipeLines LP–s remaining US$300 million term loan matures December 2011.
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.
In May 2011, PipeLines LP completed a public offering of 7,245,000 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 July 28, 2011, TransCanada–s Board of Directors declared a quarterly dividend of $0.42 per share for the quarter ending September 30, 2011 on the Company–s outstanding common shares. The dividend is payable on October 31, 2011 to shareholders of record at the close of business on September 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 September 30, 2011 to shareholders of record at the close of business on August 31, 2011. Furthermore, a quarterly dividend of $0.275 per Series 5 preferred share was declared for the three month period ending October 30, 2011, payable on October 31, 2011 to shareholders of record at the close of business on September 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 six months ended June 30, 2011, TransCanada issued 2.8 million and 5.4 million (2010 – 2.6 million and 4.9 million) common shares, respectively, under its DRP, in lieu of making cash dividend payments of $109 million and $202 million, respectively (2010 – $92 million and $170 million).
Contractual Obligations
In the first six months of 2011, TransCanada had a net reduction to its purchase obligations primarily due to the settlement of its commitments in the normal course of business. There have been no other material changes to TransCanada–s contractual obligations from December 31, 2010 to June 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 accordance with GAAP, TransCanada follows specific accounting policies unique to a rate-regulated business. These rate-regulated accounting (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.
In July 2009, the IASB issued an Exposure Draft “Rate-Regulated Activities”, which proposed a form of RRA under IFRS. At its September 2010 meeting, 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.
In October 2010, the AcSB and the Canadian Securities Administrators amended their policies applicable to Canadian publicly accountable enterprises that use 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.
As an SEC registrant, TransCanada prepares and files a “Reconciliation to United States GAAP” and has the option 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. TransCanada–s IFRS conversion team has been redeployed to support the conversion to U.S. GAAP. The 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 continue for TransCanada staff who are impacted by the conversion and will be ongoing as needed throughout 2011. Significant changes to existing systems and processes are not required to implement U.S. GAAP as the Company–s primary accounting standard since TransCanada prepares and files a “Reconciliation to United States GAAP”. The impact to internal controls over financial reporting and disclosure controls and procedures will be addressed over the remainder 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 June 30, 2011, there were no significant amounts past due or impaired.
At June 30, 2011, the Company had a credit risk concentration of $286 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 June 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 $47 million (December 31, 2010 – $49 million). The change in the fair value adjustment of proprietary natural gas inventory in storage in the three and six months ended June 30, 2011 resulted in net pre-tax unrealized losses of $1 million and gains of $1 million, respectively (2010 – gains of $4 million 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 six months ended June 30, 2011 resulted in net pre-tax unrealized losses of $3 million and $10 million, respectively (2010 – gains of $2 million and $5 million, respectively), which were included in Revenues.
VaR Analysis
TransCanada uses a Value-at-Risk (VaR) methodology to estimate the potential impact from its exposure to market risk on its liquid open positions. VaR represents the potential change in pre-tax earnings over a given holding period. It is calculated assuming a 95 per cent confidence level that the daily change resulting from normal market fluctuations in its open positions will not exceed the reported VaR. Although losses are not expected to exceed the statistically estimated VaR on 95 per cent of occasions, losses on the other five per cent of occasions could be substantially greater than the estimated VaR. TransCanada–s consolidated VaR was $11 million at June 30, 2011, which was consistent with VaR at December 31, 2010 of $12 million.
Net Investment in Self-Sustaining Foreign Operations
The Company hedges its net investment in self-sustaining foreign operations (on an after-tax basis) with U.S. dollar-denominated debt, cross-currency interest rate swaps, forward foreign exchange contracts and foreign exchange options. At June 30, 2011, the Company had designated as a net investment hedge U.S. dollar-denominated debt with a carrying value of $9.5 billion (US$9.8 billion) and a fair value of $10.8 billion (US$11.2 billion). At June 30, 2011, $279 million (December 31, 2010 – $181 million) was included in Other Current Assets and Intangibles and Other Assets for the fair value of forwards and swaps used to hedge the Company–s net U.S. dollar investment in foreign operations.
The fair values and notional principal amounts for the derivatives designated as a net investment hedge were as follows:
Other Risks
Additional risks faced by the Company are discussed in the MD&A in TransCanada–s 2010 Annual Report. These risks remain substantially unchanged since December 31, 2010.
Controls and Procedures
As of June 30, 2011, an evaluation was carried out under the supervision of, and with the participation of management, including the President and Chief Executive Officer and the Chief Financial Officer, of the effectiveness of TransCanada–s disclosure controls and procedures as defined under the rules adopted by the Canadian securities regulatory authorities and by the SEC. Based on this evaluation, the President and Chief Executive Officer and the Chief Financial Officer concluded that the design and operation of TransCanada–s disclosure controls and procedures were effective at a reasonable assurance level as at June 30, 2011.
During the quarter ended June 30, 2011, 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.
Outlook
Since the disclosure in TransCanada–s 2010 Annual Report, the Company–s overall earnings outlook for 2011 has improved due to higher realized power prices in Western Power in the first half of 2011, with relatively strong prices expected throughout the remainder of 2011. The Company–s earnings outlook could also be affected by the uncertainty and ultimate resolution of the capacity pricing issues in New York, as discussed in the Recent Developments section of this MD&A. For further information on outlook, refer to the MD&A in TransCanada–s 2010 Annual Report.
Recent Developments
Natural Gas Pipelines
Canadian Mainline
2011 Final Tolls
In April 2011, TransCanada filed an application with the NEB for approval of Canadian Mainline–s final tolls for 2011 determined in accordance with the existing 2007-2011 Tolls Settlement.
TransCanada proposed to continue charging the interim 2011 tolls for the remainder of 2011 and to carry forward to 2012 the difference between the revenue that would have been generated from the final tolls and the revenue actually generated from the interim tolls. The interim 2011 tolls were implemented on March 1, 2011 and reflected a firm transportation toll from Empress, Saskatchewan to Dawn, Ontario of $1.89 per gigajoule. Adjusting for the difference in 2012 will result in greater Canadian Mainline toll certainty and stability.
In May 2011, the NEB solicited comments on the application for final tolls from interested parties, requesting their position and recommended process with respect to the application. Subsequently, the NEB solicited additional comments on the application and required TransCanada to file a reply submission by July 29, 2011.
2012 – 2013 Tolls Application
As part of its 2011 final tolls application, TransCanada informed the NEB of its intent to file an application for 2012 and 2013 tolls by October 31, 2011 that will include changes to the business structure, toll design and services. These changes are intended to improve the competitiveness of TransCanada–s regulated Canadian natural gas transportation infrastructure and the Western Canada Sedimentary Basin (WCSB).
In June 2011, the NEB directed Tran