CALGARY, ALBERTA — (Marketwire) — 10/30/12 — TransCanada Corporation (TSX: TRP) (NYSE: TRP) (TransCanada or the Company) today announced comparable earnings for third quarter 2012 of $349 million or $0.50 per share. Net income attributable to common shares for third quarter 2012 was $369 million or $0.52 per share. TransCanada–s Board of Directors also declared a quarterly dividend of $0.44 per common share for the quarter ending December 31, 2012, equivalent to $1.76 per common share on an annualized basis.
“TransCanada–s diverse, high-quality energy infrastructure assets performed well in the third quarter,” said Russ Girling, TransCanada–s president and chief executive officer. “While the majority of our assets continued to generate stable and predictable earnings and cash flow, plant outages at Bruce Power and Sundance A along with a lower contribution from certain natural gas pipelines did adversely affect our financial results. Looking forward, TransCanada is well positioned to grow earnings, cash flow and dividends as we complete our current capital program, benefit from a recovery in natural gas and power prices and secure attractive new growth opportunities.”
Over the next three years, TransCanada expects to complete $13 billion of projects that are currently in advanced stages of development. They include the Bruce Power Unit 1 and 2 Restart Project, the Gulf Coast Project, Keystone XL, the Tamazunchale extension, Canadian Solar and the ongoing expansion of the Alberta System.
Since the beginning of 2012, TransCanada has also commercially secured an additional $7 billion of long-life, contracted energy infrastructure opportunities that are expected to be placed into service in 2016 and beyond. They include the Coastal GasLink Pipeline Project that would move natural gas to Canada–s West Coast for liquefaction and shipment to Asian markets, the Northern Courier and Grand Rapids Oil Pipeline Projects in Northern Alberta and the 900 megawatt Napanee Generating Station in Eastern Ontario. TransCanada expects each of these projects to generate significant, sustained earnings and cash flow and deliver superior returns to its shareholders.
Highlights
(All financial figures are unaudited and in Canadian dollars unless noted otherwise)
Comparable earnings for third quarter 2012 were $349 million or $0.50 per share compared to $416 million or $0.59 per share for the same period in 2011. Higher earnings from Keystone and recently commissioned assets were more than offset by lower contributions from Bruce Power, Western Power and certain natural gas pipelines including the Canadian Mainline, ANR and Great Lakes.
Net income attributable to common shares for third quarter 2012 was $369 million or $0.52 per share compared to $386 million or $0.55 per share in third quarter 2011.
Notable recent developments in Oil Pipelines, Natural Gas Pipelines, Energy and Corporate include:
Oil Pipelines:
Natural Gas Pipelines:
Energy:
Corporate:
Teleconference – Audio and Slide Presentation:
TransCanada will hold a teleconference and webcast on Tuesday, October 30, 2012 to discuss its third quarter 2012 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 at 9:00 a.m. (MDT) / 11:00 a.m. (EDT).
Analysts, members of the media and other interested parties are invited to participate by calling 866.226.1793 or 416.340.2218 (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 6, 2012. Please call 905.694.9451 or 800.408.3053 (North America only) and enter pass code 8130635.
The unaudited interim Consolidated Financial Statements and Management–s Discussion and Analysis (MD&A) are available on SEDAR at , with the U.S. Securities and Exchange Commission on EDGAR at and on the TransCanada website at .
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 operates a network of natural gas pipelines that extends more than 68,500 kilometres (42,500 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 10,900 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: or check us out on Twitter @TransCanada.
Forward Looking Information
This news release contains certain information that is forward-looking and is subject to important risks and uncertainties (such statements are usually accompanied by words such as “anticipate”, “expect”, “would”, “believe”, “may”, “will”, “plan”, “intend” or other similar words). 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. All forward-looking statements reflect TransCanada–s beliefs and assumptions based on information available at the time the statements were made and as such are not guarantees of future performance. 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, and not to use future-oriented information or financial outlooks for anything other than their intended purpose. TransCanada undertakes no obligation to update or revise any forward-looking information except as required by law. For additional information on the assumptions made, and the risks and uncertainties which could cause actual results to differ from the anticipated results, refer to TransCanada–s MD&A filed February 15, 2012 under TransCanada–s profile on SEDAR at and other reports filed by TransCanada with Canadian securities regulators and with the U.S. Securities and Exchange Commission.
Non-GAAP Measures
This news release contains references to non-GAAP measures that do not have any standardized meaning as prescribed by U.S. GAAP and may therefore not be comparable to similar measures used by other companies. These non-GAAP measures are calculated on a consistent basis from period to period and are adjusted for specific items in each period, as applicable. For more information on non-GAAP measures, refer to TransCanada–s Quarterly Report to Shareholders dated October 29, 2012.
TRANSCANADA CORPORATION – THIRD QUARTER 2012
Quarterly Report to Shareholders
Management–s Discussion and Analysis
This Management–s Discussion and Analysis (MD&A) dated October 29, 2012 should be read in conjunction with the accompanying unaudited Condensed Consolidated Financial Statements of TransCanada Corporation (TransCanada or the Company) for the three and nine months ended September 30, 2012. The condensed consolidated financial statements of the Company have been prepared in accordance with United States (U.S.) generally accepted accounting principles (U.S. GAAP). Comparative figures, which were previously presented in accordance with Canadian generally accepted accounting principles as defined in Part V of the Canadian Institute of Chartered Accountants Handbook (CGAAP), have been adjusted as necessary to be compliant with the Company–s accounting policies under U.S. GAAP, 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 2011 Annual Report, as prepared in accordance with CGAAP, for the year ended December 31, 2011. 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 2011 Annual Report.
Forward-Looking Information
This MD&A contains certain information that is forward looking and is subject to important risks and uncertainties. The words “anticipate”, “expect”, “believe”, “may”, “will”, “should”, “estimate”, “project”, “outlook”, “forecast”, “intend”, “target”, “plan” or other similar words are typically 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 plans and financial outlook. Forward-looking statements in this document may include, but are not limited to, statements regarding:
These forward-looking statements reflect TransCanada–s beliefs and assumptions based on information available at the time the statements were made and, as such, are not guarantees of future performance. By their nature, forward-looking statements are subject to various assumptions, risks and uncertainties which could cause TransCanada–s actual results and achievements to differ materially from the anticipated results or expectations expressed or implied in such statements.
Key assumptions on which TransCanada–s forward-looking statements are based include, but are not limited to, assumptions about:
The risks and uncertainties that could cause actual results or events to differ materially from current expectations include, but are not limited to:
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 against placing undue reliance on forward-looking information, which is given as of the date it is expressed in this MD&A or otherwise stated, and not to use future-oriented information or financial outlooks for anything other than their intended purpose. TransCanada undertakes no obligation to publicly update or revise any forward-looking information in this MD&A or otherwise stated, 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 as prescribed by U.S. GAAP. They are, therefore, considered to be non-GAAP measures and are unlikely to be comparable to similar measures presented by other entities. Management of TransCanada uses 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. EBITDA includes income from equity investments. 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. EBIT includes income from equity investments.
Comparable Earnings, Comparable EBITDA, Comparable EBIT, Comparable Interest Expense, Comparable Interest Income and Other, and Comparable Income Taxes comprise Net Income Applicable to Common Shares, EBITDA, EBIT, Interest Expense, Interest Income and Other, and Income Taxes, respectively, and are 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 adjustments, gains or losses on sales of assets, legal and bankruptcy settlements, and write-downs of assets and investments. These non-GAAP measures are calculated on a consistent basis from period to period. The specific items for which such measures are adjusted in each applicable period may only be relevant in certain periods and are disclosed in the Reconciliation of Non-GAAP Measures table in this MD&A.
The Company engages in risk management activities to reduce its exposure to certain financial and commodity price risks by utilizing 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 year. The unrealized gains or losses from changes in the fair value of these derivative contracts 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 Reconciliation of Non-GAAP Measures table in this MD&A presents a reconciliation of these non-GAAP measures to Net Income Attributable to Common Shares. Comparable Earnings per Common Share is calculated by dividing Comparable Earnings by the weighted average number of common shares outstanding for the period.
Funds Generated from Operations 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 Summarized Cash Flow 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 2012 were $349 million or $0.50 per share compared to $416 million or $0.59 per share for the same period in 2011. Comparable Earnings excluded net unrealized after-tax gains of $20 million ($31 million pre-tax) (2011 – losses of $30 million after tax ($43 million pre-tax)) resulting from changes in the fair value of certain risk management activities.
Comparable Earnings decreased $67 million or $0.09 per share in third quarter 2012 compared to the same period in 2011 and reflected the following:
Comparable Earnings in the first nine months of 2012 were $1,012 million or $1.44 per share compared to $1,194 million or $1.70 per share for the same period in 2011. Comparable Earnings in the first nine months of 2012 excluded net unrealized after-tax losses of $4 million ($5 million pre-tax) (2011 – losses of $44 million after tax ($65 million pre-tax)) resulting from changes in the fair value of certain risk management activities. Comparable Earnings in the first nine months of 2012 also excluded a negative after-tax charge of $15 million ($20 million pre-tax) following the July 2012 Sundance A PPA arbitration decision that was recorded in second quarter 2012 but related to amounts originally recorded in fourth quarter 2011.
Comparable Earnings decreased $182 million or $0.26 per share for the first nine months of 2012 compared to the same period in 2011 and reflected the following:
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 exchange rates to convert a U.S. dollar to a Canadian dollar for the three and nine months ended September 30, 2012 were 0.99 and 1.00, respectively (2011 – 0.98 and 0.98, respectively).
Summary of Significant U.S. Dollar-Denominated Amounts
Natural Gas Pipelines
Natural Gas Pipelines– Comparable EBIT was $429 million and $1.4 billion in the three and nine months ended September 30, 2012, respectively, compared to $467 million and $1.5 billion, respectively, for the same periods in 2011.
Canadian Natural Gas Pipelines
Canadian Mainline–s net income of $47 million and $140 million in the three and nine months ended September 30, 2012, respectively, decreased $14 million and $46 million from $61 million and $186 million in the same periods in 2011. Canadian Mainline–s net income for the three and nine months ended September 30, 2011 included incentive earnings earned under an incentive arrangement in the five-year tolls settlement which expired December 31, 2011. In the absence of a National Energy Board (NEB) decision with respect to the 2012-2013 tolls application, which is not expected until late first quarter 2013, Canadian Mainline–s 2012 year-to-date results continued to reflect the last NEB-approved rate of return on common equity of 8.08 per cent on deemed common equity of 40 per cent and excluded incentive earnings. In addition, Canadian Mainline–s 2012 year-to-date net income decreased as a result of a lower average investment base compared to the prior year.
The Alberta System–s net income in the three and nine months ended September 30, 2012, was $53 million and $153 million, respectively, compared to $51 million and $149 million for the same periods in 2011. The positive impact on 2012 net income from a higher average investment base was mostly offset by lower incentive earnings for the three and nine months ending September 30, 2012.
Canadian Mainline–s Comparable EBITDA for the three and nine months ended September 30, 2012 of $247 million and $744 million, respectively, decreased $17 million and $52 million compared to the same periods in 2011. EBITDA from the Canadian Mainline reflects the net income variances discussed above as well as variances in depreciation, financial charges and income taxes which are recovered in revenue on a flow-through basis and, therefore, do not impact net income.
U.S. and International Natural Gas Pipelines
ANR–s Comparable EBITDA in the three and nine months ended September 30, 2012 was US$41 million and US$191 million, respectively, compared to US$55 million and US$233 million for the same periods in 2011. The decreases were primarily due to lower transportation and storage revenues, higher operating and maintenance costs, lower incidental commodity sales and a second quarter 2011 settlement with a counterparty.
GTN–s Comparable EBITDA in the three and nine months ended September 30, 2012 was US$28 million and US$84 million, respectively, compared to US$29 million and US$105 million for the same periods in 2011. The decrease in the nine months ended September 2012 compared to 2011 was primarily due to TransCanada–s sale of a 25 per cent interest in GTN to TC PipeLines, LP in May 2011.
Great Lakes– Comparable EBITDA in the three and nine months ended September 30, 2012 was US$16 million and US$51 million, respectively, compared to US$26 million and US$81 million for the same periods in 2011. The decreases were due to lower transportation revenue resulting from unsold long-haul winter capacity as well as summer capacity sold under short-term contracts at lower rates compared to the same period in 2011.
International Comparable EBITDA increased US$33 million for the nine months ended September 30, 2012 compared to the same period in 2011. The increase was primarily due to incremental earnings from the Guadalajara pipeline which was placed in service in June 2011.
Business Development
Natural Gas Pipelines– Business Development Comparable EBITDA loss from business development activities decreased $7 million and $12 million in the three and nine months ended September 30, 2012, respectively, compared to the same periods in 2011. The decreases in business development costs were primarily related to reduced activity in 2012 for the Alaska Pipeline Project and 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.
Depreciation and Amortization
Natural Gas Pipelines– Depreciation and Amortization increased $9 million for the nine months ended September 30, 2012 compared to the same period in 2011. The increase was primarily due to incremental depreciation for the Guadalajara pipeline which was placed in service in June 2011.
Oil Pipelines
Oil Pipelines Comparable EBIT for the three and nine months ended September 30, 2012 was $140 million and $417 million, respectively, compared to $118 million and $313 million for the three and eight month periods in 2011.
Keystone Pipeline System
The Keystone Pipeline System–s Comparable EBITDA of $180 million and $532 million for the three and nine months ended September 30, 2012, respectively, increased $23 million and $122 million compared to the three and eight month periods in 2011. These increases reflected higher revenues primarily resulting from higher contracted volumes, the impact of higher final fixed tolls on the Cushing Extension and Wood River/Patoka sections of the system which came into effect in July 2012 and May 2011, respectively, and nine months of earnings being recorded in 2012 compared to eight months in 2011.
EBITDA from the Keystone Pipeline System is primarily generated from payments received under long-term commercial arrangements for committed capacity that are not dependant on actual throughput. Uncontracted capacity is offered to the market on a spot basis and, when capacity is available, provides opportunities to generate incremental EBITDA.
Depreciation and Amortization
Oil Pipelines Depreciation and Amortization increased $14 million for the nine months ended September 30, 2012 compared to the corresponding period in 2011 and primarily reflected nine months of operations compared to eight months in 2011 for the Wood River/Patoka and Cushing Extension sections of the Keystone Pipeline System.
Energy
Energy–s Comparable EBIT was $197 million and $466 million for the three and nine months ended September 30, 2012, respectively, compared to $287 million and $720 million, respectively, for the same periods in 2011.
Western Power–s Comparable EBITDA of $93 million and $251 million for the three and nine months ended September 30, 2012 decreased $57 million and $90 million compared to the same periods of 2011, respectively.
Throughout first quarter 2012, revenues and costs related to the Sundance A PPA had been recorded as though the outages of Units 1 and 2 were interruptions of supply. As a result of the Sundance A PPA arbitration decision received in July 2012, a $30 million charge, equivalent to the amount of pre-tax income recorded in first quarter 2012, was recorded in second quarter 2012. Because the plant is now in force majeure, revenues and costs will not be recorded until the plant returns to service. Western Power–s Comparable EBITDA for the three and nine months ended September 30, 2011 included $48 million and $99 million, respectively, of accrued earnings related to the Sundance A PPA. Refer to the Recent Developments section in this MD&A for further discussion regarding the Sundance A PPA arbitration decision.
The decrease in Western Power–s Comparable EBITDA in third quarter 2012 compared to 2011 was primarily due to the Sundance A PPA force majeure as well as lower volumes, partially offset by higher realized power prices.
The decrease in Western Power–s Comparable EBITDA for the nine months ended September 30, 2012 compared to the same period in 2011 primarily reflected the Sundance A PPA force majeure as well as the impact of lower volumes sold, partially offset by the impact of lower fuel costs, incremental earnings from Coolidge which was placed in service in May 2011, and higher realized power prices.
Purchased volumes for the three and nine months ended September 30, 2012 decreased compared to the same periods in 2011 primarily due to decreased utilization of the Sundance B and Sheerness PPAs during periods of lower spot market power prices and higher plant outage days. Average spot market power prices decreased 18 per cent to $78 per megawatt hour (MWh) and 23 per cent to $59 per MWh for the three and nine months ended September 30, 2012, respectively, compared to the same periods in 2011. Despite the decrease in spot prices, Western Power earned a higher realized price per MWh for the three and nine months ended September 30, 2012 compared to the same periods in 2011 as a result of contracting activities.
Western Power–s Power Revenue of $152 million and $482 million for the three and nine months ended September 30, 2012, respectively, decreased $87 million and $121 million, respectively, compared to the same periods in 2011 primarily due to the Sundance A PPA force majeure as well as lower purchased volumes, partially offset by higher realized power prices. Revenue for the nine months ended September 30, 2012 was also positively affected by Coolidge being placed in service in May 2011.
Western Power–s Commodity Purchases Resold of $70 million and $207 million for the three and nine months ended September 30, 2012, respectively, decreased $33 million and $72 million, respectively, compared to the same periods in 2011 primarily due to the Sundance A PPA force majeure, as well as lower purchased volumes.
Eastern Power–s Comparable EBITDA of $85 million and $251 million for the three and nine months ended September 30, 2012 increased $13 million and $36 million, respectively, compared to the same periods in 2011. Similarly, Eastern Power–s Power Revenues of $108 million and $309 million for the three and nine months ended September 30, 2012 increased $9 million and $23 million, respectively, compared to the same periods in 2011. The increases were primarily due to higher Becancour contractual earnings and incremental earnings from Montagne-Seche and phase one of Gros-Morne at Cartier Wind, which were both placed in service in November 2011.
Income from Equity Investments of $28 million and $45 million, respectively, for the three and nine months ended September 30, 2012 decreased $11 million and $40 million, respectively, compared to the same periods in 2011 primarily due to lower earnings from the ASTC Power Partnership as a result of lower Sundance B PPA volumes and lower spot market power prices. Income from Equity Investments for the nine months ended September 30, 2012 was also impacted by lower earnings from Portlands Energy due to an unplanned outage in second quarter 2012.
Plant Operating Costs and Other, which includes fuel gas consumed in power generation, of $58 million and $160 million for the three and nine months ended September 30, 2012, respectively, decreased $4 million and $20 million compared to the same periods in 2011 primarily due to decreased natural gas fuel prices in 2012 compared to 2011.
Depreciation and Amortization for the nine months ended September 30, 2012 increased $11 million compared to the same period in 2011 primarily due to Montagne-Seche and phase one of Gros-Morne at Cartier Wind and Coolidge being placed in service.
Approximately 91 per cent of Western Power sales volumes were sold under contract in third quarter 2012 compared to 81 per cent in third quarter 2011. To reduce its exposure to spot market prices in Alberta, as at September 30, 2012, Western Power had entered into fixed-price power sales contracts to sell approximately 2,100 gigawatt hours (GWh) for the remainder of 2012 and 5,700 GWh for 2013.
Eastern Power–s sales volumes were 100 per cent sold under contract and are expected to be fully contracted going forward.
TransCanada–s Equity Income from Bruce A decreased $55 million and $143 million for the three and nine months ended September 30, 2012, respectively, to losses of $39 million and $95 million compared to income of $16 million and $48 million for the same periods in 2011. The third quarter decrease was primarily due to lower volumes resulting from the Unit 4 planned outage which commenced on August 2, 2012. The decrease for the nine months ended September 30, 2012 also reflected the impact of the Unit 3 West Shift Plus planned outage which commenced in November 2011 and was completed in June 2012. Refer to the Recent Developments section in this MD&A for further discussion of these planned outages.
TransCanada–s Equity Income from Bruce B for the three and nine months ended September 30, 2012 of $43 million and $117 million, respectively, increased $12 million and $54 million compared to the same periods in 2011. The increases were primarily due to higher volumes and lower operating costs resulting from fewer planned outage days, lower lease expense and higher realized prices. Provisions in the Bruce B lease agreement with Ontario Power Generation provide for a reduction in annual lease expense if the annual average Ontario spot price for electricity is less than $30 per MWh. The average spot price has been below $30 per MWh for the first nine months of 2012, and this is expected to continue throughout 2012.
Under a contract with the Ontario Power Authority (OPA), all output from Bruce A in third quarter 2012 was sold at a fixed price of $68.23 per MWh (before recovery of fuel costs from the OPA) compared to $66.33 per MWh in third quarter 2011. Also under a contract with the OPA, all output from the Bruce B units was subject to a floor price of $51.62 per MWh in third quarter 2012 compared to $50.18 in third quarter 2011. 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 2012, TransCanada currently expects spot prices to be less than the floor price for the year, therefore, no amounts recorded in revenues in 2012 are expected to be repaid.
The Unit 4 outage, which commenced on August 2, 2012, is expected to be completed in late fourth quarter 2012. There are no further outages planned at Bruce Power for the remainder of 2012. In October 2012, Bruce Power completed the refurbishment of Units 1 and 2 and returned Unit 1 to service on October 22, 2012. Bruce Power also synchronized Unit 2 to Ontario–s electrical grid on October 16, 2012 and commercial operations for this unit are expected to commence shortly.
U.S Power–s Comparable EBITDA of US$87 million and US$161 million for the three and nine months ended September 30, 2012, respectively, decreased US$3 million and US$80 million compared to the same periods in 2011. The reductions were primarily due to lower realized power prices, higher load serving costs, and reduced water flows at the U.S. hydro facilities, partially offset by increased sales to wholesale, commercial and industrial customers.
Physical sales volumes for the three and nine months ended September 30, 2012 have increased compared to the same period in 2011 primarily due to higher purchased volumes to serve increased sales to wholesale, commercial and industrial customers in the PJM and New England markets. Generation volumes have been negatively impacted by reduced hydro volumes throughout 2012, however this was more than offset by higher generation volumes from other U.S. Power facilities in third quarter 2012.
U.S Power–s Power Revenue of US$408 million for the three months ended September 30, 2012 increased US$72 million compared to the same period in 2011. The increase was primarily due to higher sales volumes to wholesale, commercial and industrial customers, partially offset by lower realized power prices. Power Revenue of US$836 million for the nine months ended September 30, 2012 decreased US$95 million compared to the same period in 2011 primarily due to lower realized power prices partially offset by increased sales volumes.
Capacity Revenue of US$75 million for the three months ended September 30, 2012 increased US$5 million compared to the same period in 2011 due to higher realized capacity prices in New York partially offset by lower New England capacity prices. Capacity Revenue of US$181 million for the nine months ended September 30, 2012, decreased US$2 million compared to the same period in 2011 as lower capacity prices in New England more than offset higher realized capacity prices in New York.
Commodity Purchases Resold of US$268 million and US$548 million for the three and nine months ended September 30, 2012, respectively, increased US$100 million and US$49 million compared to the same periods in 2011 due to higher volumes of physical power purchased for resale under power sales commitments to wholesale, commercial and industrial customers and higher load serving costs, partially offset by lower power prices.
Plant Operating Costs and Other, which includes fuel gas consumed in generation, of US$120 million and US$303 million for the three and nine months ended September 30, 2012, respectively, decreased US$29 million and US$96 million compared to the same periods in 2011 primarily due to lower natural gas fuel prices.
As at September 30, 2012, approximately 1,200 GWh or 53 per cent and 2,700 GWh or 35 per cent of U.S. Power–s planned generation is contracted for the remainder of 2012 and for 2013, respectively. Planned generation fluctuates depending on hydrology, wind conditions, commodity prices and the resulting dispatch of the assets. Power sales fluctuate based on customer usage.
Natural Gas Storage
Natural Gas Storage–s Comparable EBITDA of $17 million for the three months ended September 30, 2012 increased $6 million compared to the same period in 2011 primarily due to higher realized natural gas storage price spreads and lower operating costs.
Natural Gas Storage–s Comparable EBITDA of $47 million for the nine months ended September 30, 2012 decreased $9 million compared to the same period in 2011 primarily as a result of the impact of lower realized natural gas storage price spreads in the first quarter of 2012, partially offset by lower operating costs throughout the year.
Other Income Statement Items
Comparable Interest Expense of $249 million and $730 million for the three and nine months ended September 30, 2012 increased $7 million and $42 million, respectively, compared to the same periods in 2011. The increase in interest expense for the nine months ended September 30, 2012 reflected incremental interest on debt issues of US$1.0 billion in August 2012, US$500 million in March 2012 and $750 million in November 2011, and a TC PipeLines, LP debt issue of US$350 million in June 2011. These increases also reflected the negative impact of a stronger U.S. dollar on U.S. dollar-denominated interest, and lower capitalized interest for Keystone, Coolidge and Guadalajara as a result of placing these assets in service, partially offset by higher realized gains in 2012 compared to 2011 from derivatives used to manage the Company–s exposure to rising interest rates and the impact of Canadian and U.S. dollar-denominated debt maturities in 2012 and 2011.
Comparable Interest Income and Other of $22 million and $66 million for the three and nine months ended September 30, 2012 increased $26 million and $14 million, respectively, compared to the same periods in 2011. The increase for the three months ended September 30, 2012 was primarily due to gains in 2012 compared to losses in 2011 on derivatives used to manage the Company–s net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income and on translation of foreign denominated working capital balances. The increase for the nine months ended September 30, 2012 was primarily due to gains in 2012 compared to losses in 2011 on the translation of foreign denominated working capital balances.
Comparable Income Taxes were $123 million and $354 million in the three and nine months ended September 30, 2012, respectively, compared to $144 million and $470 million for the same periods in 2011. The decreases of $21 million and $116 million, respectively, were primarily due to lower pre-tax earnings in 2012 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 cash flow from operations, available cash balances and unutilized committed revolving bank lines of US$1.0 billion, US$300 million, US$1.0 billion and $2.0 billion, maturing in November 2012, February 2013, October 2013 and October 2017, respectively. These facilities also support the Company–s three commercial paper programs. In addition, at September 30, 2012, TransCanada–s proportionate share of unutilized capacity on committed bank facilities at the Company–s operated affiliates was $90 million with maturity dates in 2016. As at September 30, 2012, TransCanada had remaining capacity of $2.0 billion, $1.25 billion and US$2.5 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.
Net Cash Provided by Operations increased $93 million in the three months ended September 30, 2012 compared to the same period in 2011 primarily due to changes in working capital, partially offset by increased funding for pension plans and lower distributions received from equity investments. Net Cash Provided by Operations decreased $213 million in the nine months ended September 30, 2012 compared to the same periods in 2011 primarily due to lower earnings in addition to the previously mentioned third quarter changes.
As at September 30, 2012, TransCanada–s current assets were $2.6 billion and current liabilities were $4.8 billion resulting in a working capital deficiency of $2.2 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
In the three and nine months ended September 30, 2012, capital expenditures totalled $694 million and $1,555 million, respectively (2011- $505 million and $1,593 million, respectively) related to the expansions of the Keystone Pipeline System and the Alberta System. Equity investments of $144 million and $557 million for the three and nine months ended September 30, 2012, respectively (2011 – $213 million and $451 million, respectively) were primarily related to the Company–s investment in the refurbishment and restart of Bruce Power Units 1 and 2 which were completed in October 2012 and the West Shift Plus life extension outage on Unit 3.
Financing Activities
In August 2012, the Company issued US$1.0 billion of senior notes maturing on August 1, 2022 and bearing interest at an annual rate of 2.5 per cent. In March 2012, the Company issued US$500 million of senior notes maturing on March 2, 2015 and bearing interest at an annual rate of 0.875 per cent. These notes were issued under the US$4.0 billion debt shelf prospectus filed in November 2011. The net proceeds of these offerings were used for general corporate purposes and to reduce short-term indebtedness.
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 TC PipeLines, LP.
Dividends
On October 29, 2012, TransCanada–s Board of Directors declared a quarterly dividend of $0.44 per share for the quarter ending December 31, 2012 on the Company–s outstanding common shares. The dividend is payable on January 31, 2013 to shareholders of record at the close of business on December 31, 2012. 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 December 31, 2012. The dividends are payable on December 31, 2012 to shareholders of record at the close of business on November 30, 2012. Furthermore, a quarterly dividend of $0.275 per Series 5 preferred share was declared for the period ending January 30, 2013, payable on January 30, 2013 to shareholders of record at the close of business on December 31, 2012.
Contractual Obligations
There have been no material changes, except for an increase in capital commitments of $1.4 billion, primarily related to the Gulf Coast Project and Keystone XL Pipeline, offset by the decreases to market-based commodity purchase commitments of approximately $1.3 billion, to TransCanada–s contractual obligations from December 31, 2011 to September 30, 2012, 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 2011 Annual Report.
Accounting Policies and Critical Accounting Estimates
Effective January 1, 2012, TransCanada commenced reporting under U.S. GAAP as permitted. Comparative figures, which were previously presented in accordance with CGAAP, have been adjusted as necessary to be compliant with the Company–s accounting policies under U.S. GAAP. The financial reporting impact of TransCanada adopting U.S. GAAP is disclosed in Note 25 of TransCanada–s 2011 audited Consolidated Financial Statements included in TransCanada–s 2011 Annual Report. The accounting policies and critical accounting estimates applied are consistent with those outlined in TransCanada–s 2011 Annual Report, except as described below, which outlines the Company–s significant accounting policies that have changed upon adoption of U.S. GAAP.
In preparing the financial statements, TransCanada is required to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be dependent on future events. The Company uses the most current information available and exercises careful judgement in making these estimates and assumptions.
Changes to Accounting Policies Upon Adoption of U.S. GAAP
Principles of Consolidation
The condensed consolidated financial statements include the accounts of TransCanada and its subsidiaries. The Company consolidates its interests in entities over which it is able to exercise control. To the extent there are interests owned by other parties, these interests are included in Non-Controlling Interests. TransCanada uses the equity method of accounting for joint ventures in which the Company is able to exercise joint control and for investments in which the Company is able to exercise significant influence. TransCanada records its proportionate share of undivided interests in certain assets.
Inventories
Inventories primarily consist of materials and supplies, including spare parts and fuel, and natural gas inventory in storage, and are carried at the lower of weighted average cost or market.
Income Taxes
The Company uses the liability method of accounting for income taxes. This method requires the recognition of deferred income tax assets and liabilities for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred income tax assets and liabilities are measured using enacted tax rates at the balance sheet date that are anticipated to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. Changes to these balances are recognized in income in the period during which they occur except for changes in balances related to the Canadian Mainline, Alberta System and Foothills, which are deferred until they are refunded or recovered in tolls, as permitted by the NEB.
Canadian income taxes are not provided on the unremitted earnings of foreign investments that the Company does not intend to repatriate in the foreseeable future.
Employee Benefit and Other Plans
The Company sponsors defined benefit pension plans (DB Plans), defined contribution plans (DC Plans), a Savings Plan and other post-retirement benefit plans. Contributions made by the Company to the DC Plans and Savings Plan are expensed in the period in which contributions are made. The cost of the DB Plans and other post-retirement benefits received by employees is actuarially determined using the projected benefit method pro-rated based on service and management–s best estimate of expected plan investment performance, salary escalation, retirement age of employees and expected health care costs.
The DB Plans– assets are measured at fair value. The expected return on the DB Plans– assets is determined using market-related values based on a five-year moving average value for all of the DB Plans– assets. Past service costs are amortized over the expected average remaining service life of the employees. Adjustments arising from plan amendments are amortized on a straight-line basis over the average remaining service period of employees active at the date of amendment. The Company recognizes the overfunded or underfunded status of its DB Plans as an asset or liability on its Balance Sheet and recognizes changes in that funded status through Other Comprehensive Income/(Loss) (OCI) in the year in which the change occurs. The excess of net actuarial gains or losses over 10 per cent of the greater of the benefit obligation and the market-related value of the DB Plans– assets, if any, is amortized out of Accumulated Other Comprehensive Income/(Loss) (AOCI) over the average remaining service period of the active employees. For certain regulated operations, post-retirement benefit amounts are recoverable through tolls as benefits are funded. The Company records any unrecognized gains and losses or changes in actuarial assumptions related to these post-retirement benefit plans as either regulatory assets or liabilities which are then amortized on a straight-line basis over the average remaining service life of active employees. When the restructuring of a benefit plan gives rise to both a curtailment and a settlement, the curtailment is accounted for prior to the settlement.
The Company has medium-term incentive plans, under which payments are made to eligible employees. The expense related to these incentive plans is accounted for on an accrual basis. Under these plans, benefits vest when certain conditions are met, including the employees– continued employment during a specified period and achievement of specified corporate performance targets.
Long-Term Debt Transaction Costs
The Company records long-term debt transaction costs as deferred assets and amortizes these costs using the effective interest method for all costs except those related to the Canadian natural gas regulated pipelines, which continue to be amortized on a straight-line basis in accordance with the provisions of tolling mechanisms.
Guarantees
Upon issuance, the Company records the fair value of certain guarantees entered into by the Company on behalf of partially owned entities for which contingent payments may be made. The fair value of these guarantees is estimated by discounting the cash flows that would be incurred by the Company if letters of credit were used in place of the guarantees. Guarantees are recorded as an increase to Equity Investments, Plant, Property and Equipment, or a charge to Net Income, and a corresponding liability is recorded in Deferred Amounts.
Changes in Accounting Policies for 2012
Fair Value Measurement
Effective January 1, 2012, the Company adopted the Accounting Standards Update (ASU) on fair value measurements as issued by the Financial Accounting Standards Board (FASB). Adoption of the ASU has resulted in an increase in the qualitative and quantitative disclosures regarding Level III measurements.
Intangibles – Goodwill and Other
Effective January 1, 2012, the Company adopted the ASU on testing goodwill for impairment as issued by the FASB. Adoption of the ASU has resulted in a change in the accounting policy related to testing goodwill for impairment, as the Company is now permitted under U.S. GAAP to first assess qualitative factors affecting the fair value of a reporting unit in comparison to the carrying amount as a basis for determining whether it is required to proceed to the two-step quantitative impairment test.
Future Accounting Changes
Balance Sheet Offsetting/Netting
In December 2011, the FASB issued amended guidance to enhance disclosures that will enable users of the financial statements to evaluate the effect, or potential effect, of netting arrangements on an entity–s financial position. The amendments result in enhanced disclosures by requiring additional information regarding financial instruments and derivative instruments that are either offset in accordance with current U.S. GAAP or subject to an enforceable master netting arrangement. This guidance is effective for annual periods beginning on or after January 1, 2013. Adoption of these amendments is expected to result in an increase in disclosure regarding financial instruments which are subject to offsetting as described in this amendment.
Financial Instruments and Risk Management
TransCanada continues to manage and monitor its exposure to market risk, counterparty credit risk and liquidity risk.
Counterparty Credit and Liquidity Risk
TransCanada–s maximum counterparty credit exposure with respect to financial instruments at the balance sheet date, without taking into account security held, consisted of accounts receivable, the fair value of derivative assets and notes receivable. The carrying amounts and fair values of these financial assets, except amounts for derivative assets, are included in Accounts Receivable and Other in the Non-Derivative Financial Instruments Summary table below. 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, 2012, there were no significant amounts past due or impaired.
At September 30, 2012, the Company had a credit risk concentration of $266 million due from a 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.
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 September 30, 2012, the Company had designated as a net investment hedge U.S. dollar-denominated debt with a carrying value of $11.0 billion (US$11.2 billion) and a fair value of $14.4 billion (US$14.6 billion). At September 30, 2012, $60 million (December 31, 2011 – $79 million) was included in Other Current Assets, $96 million (December 31, 2011 – $66 million) was included in Intangibles and Other Assets, $6 million (December 31, 2011 – $15 million) was included in Accounts Payable and $18 million (December 31, 2011 – $41 million) was included in Deferred Amounts for the fair value of forwards and swaps used to hedge the Company–s net U.S. dollar investment in self-sustaining foreign operations.
Derivatives Hedging Net Investment in Self-Sustaining Foreign Operations
The fair values and notional principal amounts for the derivatives designated as a net investment hedge were as follows:
Non-Derivative Financial Instruments Summary
The carrying and fair values of non-derivative financial instruments were as follows:
Derivative Financial Instruments Summary
Information for the Company–s derivative financial instruments, excluding hedges of the Company–s net investment in self-sustaining foreign operations, is as follows:
Derivative contracts entered into to manage market risk often contain financial assurance provisions that allow parties to the contracts to manage credit risk. These provisions may require collateral to be provided if a credit-risk-related contingent event occurs, such as a downgrade in the Company–s credit rating to non-investment grade. Based on contracts in place and market prices at September 30, 2012, the aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a net liability position was $41 million (2011 – $77 million), for which the Company had provided collateral of nil (2011 – $6 million) in the normal course of business. If the credit-risk-related contingent features in these agreements were triggered on September 30, 2012, the Company would have been required to provide collateral of $41 million (2011 – $71 million) to its counterparties. Collateral may also need to be provided should the fair value of derivative instruments exceed pre-defined contractual exposure limit thresholds. The Company has sufficient liquidity in the form of cash and undrawn committed revolving bank lines to meet these contingent obligations should they arise.
Fair Value Hierarchy
The Company–s assets and liabilities recorded at fair value have been classified into three categories based on the fair value hierarchy.
In Level I, the fair value of assets and liabilities is determined by reference to quoted prices in active markets for identical assets and liabilities that the Company has the ability to access at the measurement date.
In Level II, the fair value of interest rate and foreign exchange derivative assets and liabilities is determined using the income approach. The fair value of power and gas commodity assets and liabilities is determined using the market approach. Under both approaches, valuation is based on the extrapolation of inputs, other than quoted prices included within Level I, for which all significant inputs are observable directly or indirectly. Such inputs include published exchange rates, interest rates, interest rate swap curves, yield curves, and broker quotes from external data service providers. Transfers between Level I and Level II would occur when there is a change in market circumstances. There were no transfers between Level I and Level II in the nine months ended September 30, 2012 and 2011.
In Level III, the fair value of assets and liabilities measured on a recurring basis is determined using a market approach based on inputs that are unobservable and significant to the overall fair value measurement. Assets and liabilities measured at fair value can fluctuate between Level II and Level III depending on the proportion of the value of the contract that extends beyond the time frame for which inputs are considered to be observable. As contracts near maturity and observable market data becomes available, they are transferred out of Level III and into Level II.
Long-dated commodity transactions in certain markets where liquidity is low are included in Level III of the fair value hierarchy, as the related commodity prices are not readily observable. Long-term electricity prices are estimated using a third-party modelling tool which takes into account physical operating characteristics of generation facilities in the markets in which the Company operates. Inputs into the model include market fundamentals such as fuel prices, power supply additions and retirements, power demand, seasonal hydro conditions and transmission constraints. Long-term North American natural gas prices are based on a view of future natural gas supply and demand, as well as exploration and development costs. Long-term prices are reviewed by management and the Board on a periodic basis. Significant decreases in fuel prices or demand for electricity or natural gas, or increases in the supply of electricity or natural gas may result in a lower fair value measurement of contracts included in Level III.
The fair value of the Company–s assets and liabilities measured on a recurring basis, including both current and non-current portions, are categorized as follows:
The following table presents the net change in the Level III fair value category:
A 10 per cent increase or decrease in commodity prices, with all other variables held constant, would result in a $6 million decrease or increase, respectively, in the fair value of outstanding derivative financial instruments included in Level III as at September 30, 2012.
Other Risks
Additional risks faced by the Company are discussed in the MD&A in TransCanada–s 2011 Annual Report. These risks remain substantially unchanged since December 31, 2011.
Controls and Procedures
As of September 30, 2012, 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 September 30, 2012.
During the quarter ended September 30, 2012, there have been no changes in TransCanada–s internal controls over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company–s internal controls over financial reporting.
Outlook
Since the disclosure in TransCanada–s 2011 Annual Report, the Company–s overall earnings outlook for 2012 will be negatively impacted by the Sundance A PPA arbitration decision received in July 2012 which is expected to result in the Company not recording earnings from the Sundance A PPA in 2012. In addition, reduced demand for natural gas and electricity due to unseasonably warm winter weather, combined with continued strong U.S. natural gas production, has resulted in historically high natural gas storage levels and low natural gas prices, which are having a negative impact on revenues in U.S. Pipelines as well as power prices in Canadian and U.S. Power. Delays in restarting the Bruce Power Units 1 and 2 as well as an expanded planned outage at Unit 4 have also reduced the 2012 earnings outlook. For further information on outlook, refer to the MD&A in TransCanada–s 2011 Annual Report.
Recent Developments
Natural Gas Pipelines
Canadian Pipelines
Canadian Mainline
2012-2013 Tolls Application
In 2011, TransCanada filed a comprehensive tolls application with the NEB to change the business structure and the terms and conditions of service for the Canadian Mainline and to set tolls for 2012 and 2013. The hearing with respect to this application began on June 4, 2012 with final arguments to be heard from TransCanada and the intervenors beginning November 13, 2012. A final decision from the NEB on the application is not expected before late first quarter 2013.
As part of the Canadian Mainline hearing, TransCanada filed an updated throughput forecast for 2013 through 2020. Based on natural gas prices being lower by approximately US$1.40 per million BTUs in 2010 dollars on an annual average basis compared to the previous forecast, the Western Mainline Receipts are expected to be lower, on average, by approximately one billion cubic feet (Bcf) per day over the forecasted period.
Marcellus Facilities Expansion
In May 2012, TransCanada received NEB approval with respect to an application that was re-filed in November 2011 to construct new pipeline infrastructure to provide Southern Ontario with additional natural gas supply from the Marcellus shale basin. Construction continues on the new pipeline facilities and it is expected that the Marcellus shale gas supply will begin moving to market as of November 1, 2012.
Mainline New Capacity Open Season
In response to requests for capacity to bring additional Marcellus shale gas volumes into Canada, TransCanada held a new capacity open season that closed in May 2012 for firm transportation service on the integrated Canadian Mainline from Niagara and Chippawa as well as from other receipt points to all delivery points, including points east of Parkway. As a result of revised project timelines for the approval and construction of the necessary facilities, TransCanada is in the process of amending the Precedent Agreements resulting from the open season to reflect a revised contract in-service date of November 2015. The ultimate facilities requirements associated with the Precedent Agreements are still being assessed.
Alberta System
Expansion Projects
In the first three