TransCanada Reports an Increase in Third Quarter Comparable Earnings to $417 Million or $0.59 Per Share
CALGARY, ALBERTA--(Marketwire - Nov. 1, 2011) - TransCanada Corporation (TSX:TRP) (NYSE:TRP) (TransCanada or the Company) today announced comparable earnings for third quarter 2011 of $417 million or $0.59 per share. Net income attributable to common shares was $384 million or $0.55 per share. TransCanada's Board of Directors also declared a quarterly dividend of $0.42 per common share for the quarter ending December 31, 2011, equivalent to $1.68 per share on an annualized basis.
"TransCanada experienced another strong quarter driven by earnings from our new assets and the Company's diverse and high-quality energy infrastructure portfolio," said Russ Girling, TransCanada's president and chief executive officer. "Comparable earnings for the first nine months of 2011 were $1.71 per share, a 20 per cent increase over the same period last year."
Since the spring of 2010, TransCanada has brought $10 billion of growth projects into service including the first and second phases of the Keystone Pipeline System, the Bison and Guadalajara natural gas pipelines, extensions and expansions of the Alberta System, phase two of the Kibby Wind farm in Maine, the Halton Hills Generating Station in Ontario and the Coolidge Generating Station in Arizona.
The Company is positioned to complete another $11 billion of new projects that will come into service by 2013 including the Keystone U.S. Gulf Coast Expansion (Keystone XL), additional extensions and expansions of the Alberta System, the Bruce Power restart program in Ontario and the final two phases of the Cartier Wind power project in Quebec. TransCanada expects these projects will generate sustained earnings and cash flow growth and deliver superior returns to our shareholders.
Third Quarter Highlights
(All financial figures are unaudited and in Canadian dollars unless noted otherwise)
-- Comparable earnings of $417 million, an increase of 11 per cent
-- Comparable earnings per share of $0.59, an increase of 9 per cent
-- Net income attributable to common shares of $384 million or $0.55 per
share
-- Comparable EBITDA of $1.258 billion, an increase of 25 per cent
-- Funds generated from operations of $971 million, an increase of 13 per
cent
-- Common share dividend of $0.42 per share declared for the quarter ending
December 31, 2011
-- Favourable Final Environmental Impact Statement (FEIS) received from the
U.S. Department of State for Keystone XL
-- Comprehensive tolls application for the Canadian Mainline filed with the
National Energy Board (NEB) addressing tolls for 2012 and 2013
Comparable earnings for third quarter 2011 were $417 million ($0.59 per share) compared to $374 million ($0.54 per share) in the same period in 2010. Contributions from recently commissioned pipeline and power generation assets, combined with higher realized power prices in Alberta, were the primary reasons for the year over year increase in comparable earnings. Partially offsetting these increases were higher interest expense and lower contributions from the U.S. Power and Alberta Gas Storage businesses. Comparable earnings in third quarter 2010 included the positive impact of recognizing the Alberta System 2010-2012 Revenue Requirement Settlement retroactive to its January 1, 2010 effective date.
Notable recent developments in Oil Pipelines, Natural Gas Pipelines, Energy and Corporate include:
Oil Pipelines:
-- On August 26, 2011, the U.S. Department of State (DOS), the lead agency
for U.S. federal regulatory approvals, released its FEIS for Keystone
XL. The FEIS found that the project would have limited environmental
impact and the proposed route would have the least environmental impact
of the alternatives considered.
-- Following the issuance of the FEIS, the DOS initiated a 90-day National
Interest Determination (NID) process. As part of the NID process, the
DOS held nine public comment meetings in September and October and will
consult with other U.S. federal agencies to determine if granting
approval for Keystone XL is in the national interest of the United
States. The NID period concludes on November 25, 2011 and a decision on
the Presidential Permit is expected by year end.
-- In August 2011, TransCanada launched two binding open seasons both of
which closed October 17, 2011. The first offered capacity to attract
long-term firm service contracts for crude oil transportation from
Hardisty, Alberta to Houston, Texas (Houston Lateral). The approximate
US$600 million Houston Lateral project would involve the expansion of
capacity through the addition of pump stations and the construction of
an approximate 80-kilometre (km) (50-mile) pipeline extension from the
proposed Keystone XL System. The proposed project would double the U.S.
Gulf Coast refining market capacity accessible from the Keystone
Pipeline System. TransCanada is currently analyzing the results of the
open season. Pending sufficient shipper commitments and regulatory
approvals, the Houston Lateral is expected to be operational in 2014.
-- The second binding open season offered capacity to attract additional
long-term firm service contracts for crude oil transportation from
Cushing, Oklahoma to Port Arthur or Houston, Texas (Cushing Marketlink).
The approximate US$50 million Cushing Marketlink project uses a portion
of the facilities that form part of Keystone XL including the Houston
Lateral. TransCanada is currently analyzing the results of the open
season. Pending regulatory approvals, Cushing Marketlink is expected to
begin shipping crude oil to Port Arthur in 2013 and to Houston in 2014.
Natural Gas Pipelines:
-- On September 1, 2011, TransCanada filed a comprehensive application with
the NEB to change the business structure and the terms and conditions of
service for the Canadian Mainline, including addressing tolls for 2012
and 2013. The application includes components that affect the
Alberta System and Foothills (Restructuring Proposal). The
application is intended to address the long-term economic viability of
the Canadian Mainline and improve the competitiveness of TransCanada's
regulated Canadian natural gas transportation infrastructure and the
Western Canada Sedimentary Basin (WCSB). On October 31, 2011,
TransCanada filed supplementary information on cost of service and the
proposed tolls for 2012 and 2013. The application results in a 2012 Nova
Inventory Transfer System to Dawn toll of $1.29 per gigajoule (GJ) which
is $0.80 per GJ or 38 per cent lower than the comparable tolls charged
in 2011.
In addition, on October 31, 2011, TransCanada filed for interim
2012 tolls on the Alberta System and annual tolls on Foothills to be
effective January 1, 2012. These applications are based on the
provisions of the current settlements in place for these systems. An
application for interim tolls for 2012 on the Mainline is expected to
be filed in mid-November 2011. Final tolls for 2012 on the Mainline and
Alberta System will be determined following the NEB's decision on the
Restructuring Proposal.
In response to the application, the NEB held a Pre-hearing Planning
Conference on October 12, 2011 for interested parties to provide
suggestions on sequencing of the hearing, procedural steps required and
the timing of these steps. Based on comments received, the NEB decided
that it will hear all of TransCanada's Application, including cost of
capital, in one proceeding before issuing a decision on the Application.
The oral portion of the hearing will commence on June 4, 2012 in
Calgary, Alberta.
-- The Alberta System's Horn River natural gas pipeline project was
approved by the NEB in January 2011 and commenced construction in March
2011, with a targeted completion date of second quarter 2012 and an
estimated capital cost of $275 million. In addition, the Company has
executed an agreement to extend the Horn River pipeline by approximately
100 km (62 miles) at an estimated capital cost of $230 million. As a
result of the extension, additional contractual commitments of 100
million cubic feet per day (mmcf/d) are expected to commence in 2014
with volumes increasing to 300 mmcf/d by 2020. An application requesting
approval to construct and operate this extension was filed with the NEB
on October 14, 2011. The total currently contracted volumes for Horn
River, including the extension, are expected to be approximately 900
mmcf/d by 2020.
-- On June 24, 2011, the NEB approved the construction and operation of a
24 km (15 mile) extension of the Groundbirch natural gas pipeline.
Construction commenced in August 2011 with an expected in-service date
of April 1, 2012 and an estimated capital cost of approximately $60
million. The project is required to serve 250 mmcf/d of new
transportation contracts.
-- TransCanada continues to advance further pipeline development in British
Columbia (B.C.) and Alberta to transport new natural gas supplies. The
Company has filed several applications with the NEB requesting approval
of further expansions of the Alberta System to accommodate requests for
additional natural gas transmission service throughout the northwest and
northeast portions of the WCSB. As at September 30, 2011, including the
projects previously discussed, the NEB had approved natural gas pipeline
projects with capital costs of approximately $750 million. Further
pipeline projects with a total capital cost of approximately $640
million are awaiting NEB decision.
-- Ongoing business with Western Canadian producers have resulted in new
contracts from both the Montney and Horn River shale gas formations.
Including the projects discussed above, TransCanada has firm commitments
to transport 2.9 billion cubic feet per day from northwest Alberta and
northeast B.C. by 2014.
Energy:
-- Bruce Power continues to progress through the commissioning of Units 1
and 2. Fueling of Unit 1 will commence in November 2011 and the final
phases of commissioning for Unit 2 are planned to begin in fourth
quarter 2011.
Subject to regulatory approval, Bruce Power expects to achieve first
synchronization of Unit 2 to the electrical grid early in first quarter
2012 and commence commercial operation in late first quarter 2012. Bruce
Power expects the first synchronization of Unit 1 to the electrical grid
in second quarter 2012 and commercial operations to occur during third
quarter 2012.
TransCanada's share of the total capital cost is expected to be
approximately $2.4 billion, of which $2.2 billion was incurred as of
September 30, 2011.
-- Construction continues on the five-stage, 590 MW Cartier Wind project in
Quebec. As at September 30, 2011, 100 per cent of the wind turbines at
Gros-Morne phase 1 and approximately 80 per cent of the wind turbines at
Montagne-Seche had been erected. The 101 MW first phase of the Gros-
Morne and 58 MW Montagne-Seche wind farm projects are expected to be
operational in December 2011. The 111 MW Gros-Morne phase two is
expected to be operational in December 2012. These are the fourth and
fifth Quebec-based wind farms of Cartier Wind, which are 62 per cent
owned by TransCanada. All of the power produced by Cartier Wind is sold
under a 20-year Power Purchase Arrangement (PPA) to Hydro-Quebec.
-- The dispute arising out of TransAlta Corporation's claims of force
majeure and economic destruction for the Sundance A facility will be
heard through a single binding arbitration process. The arbitration
panel has scheduled a hearing in March and April 2012 for these claims.
Assuming the hearing concludes within the time allotted, TransCanada
expects to receive a decision in mid-2012.
TransCanada does not believe the owner's claims meet the tests of force
majeure or destruction as specified in the PPA and therefore continues
to record revenues and costs as though this event is an interruption of
supply, in accordance with the terms of the PPA. For the nine months
ended September 30, 2011, TransCanada has recorded $99 million of EBITDA
related to the Sundance A PPA. Ultimate recovery of this amount will
depend upon the outcome of the arbitration process.
-- Since July 2011, spot prices for capacity sales in the New York Zone J
market have settled at materially lower levels than prior periods as a
result of the manner in which the New York Independent System Operator
(NYISO) has applied pricing rules for a new power plant that recently
began service in this market. TransCanada believes that this application
of pricing rules by the NYISO is in direct contravention of a series of
Federal Energy Regulatory Commission (FERC) orders which direct how new
entrant capacity is to be treated for the purpose of determining
capacity prices. TransCanada and other parties have filed formal
complaints with FERC that are currently pending. The outcome of the
complaints and longer-term impact that this development may have on
TransCanada's Ravenswood operations are unknown.
During third quarter, the demand curve reset process was completed
following FERC's acceptance of the NYISO's September 22, 2011 compliance
filing. This resulted in increased demand curve rates that apply going
forward to 2014 and positively impacted capacity prices in October. The
impact on winter capacity prices is expected to be negligible due to
excess capacity in the winter months, exacerbated by the above noted
NYISO actions relative to new unit pricing.
Corporate:
-- The Board of Directors of TransCanada declared a quarterly dividend of
$0.42 per common share for the quarter ending December 31, 2011 on
TransCanada's outstanding common shares. The quarterly amount is
equivalent to $1.68 per common share on an annual basis.
-- On October 14, 2011, TransCanada PipeLines Limited (TCPL) amended and
restated its $2.0 billion committed, syndicated, revolving, extendible
credit facility. The amended and restated facility is set to expire
October 2016 and is fully available.
On October 14, 2011, a wholly-owned subsidiary of the Company,
TransCanada PipeLine USA Ltd., refinanced its existing US$1.0 billion
credit facility with a new 364-day, US$1.0 billion committed,
syndicated, revolving, extendible credit facility which is fully
available.
-- 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.
-- In September 2011, TransCanada was named for the tenth consecutive year
to the Dow Jones Sustainability Index (DJSI). In addition, it was named
to the North American Index for the seventh year in a row. The DJSI
tracks the stock performance of the world's leading companies in terms
of economic, environmental and social criteria. The indexes serve as
benchmarks for investors who integrate sustainability considerations
into their portfolios, and provide an effective engagement platform for
companies who want to adopt sustainable best practices.
Teleconference and Webcast - Audio and Slide Presentation:
TransCanada will hold a teleconference and webcast to discuss its 2011 third quarter financial results. Russ Girling, TransCanada president and chief executive officer and Don Marchand, executive vice-president and chief financial officer, along with other members of the TransCanada executive leadership team, will discuss the financial results and company developments before opening the call to questions from analysts and members of the media.
Event:
TransCanada 2011 third quarter financial results teleconference and webcast
Date:
Tuesday, November 1, 2011
Time:
9:00 a.m. mountain daylight time (MDT) / 11:00 a.m. eastern daylight time (EDT)
How:
Analysts, members of the media and other interested parties are invited to participate by calling 866.223.7781 or 416.340.8018 (Toronto area). Please dial in 10 minutes prior to the start of the call. No pass code is required. A live webcast of the teleconference will be available at www.transcanada.com.
A replay of the teleconference will be available two hours after the conclusion of the call until midnight (EDT) November 8, 2011. Please call 800.408.3053 or 905.694.9451 (Toronto area) and enter pass code 2786260.
With more than 60 years experience, TransCanada is a leader in the responsible development and reliable operation of North American energy infrastructure including natural gas and oil pipelines, power generation and gas storage facilities. TransCanada's network of wholly owned natural gas pipelines extends more than 57,000 kilometres (35,500 miles), tapping into virtually all major gas supply basins in North America. TransCanada is one of the continent's largest providers of gas storage and related services with approximately 380 billion cubic feet of storage capacity. A growing independent power producer, TransCanada owns, or has interests in, over 10,800 megawatts of power generation in Canada and the United States. TransCanada is developing one of North America's largest oil delivery systems. TransCanada's common shares trade on the Toronto and New York stock exchanges under the symbol TRP. For more information visit: www.transcanada.com and follow us on Twitter @TransCanada.
Forward-Looking Information
This news release may contain certain information that is forward-looking and is subject to important risks and uncertainties. The words "anticipate", "expect", "believe", "may", "should", "estimate", "project", "outlook", "forecast" or other similar words are used to identify such forward-looking information. Forward-looking statements in this document are intended to provide TransCanada security holders and potential investors with information regarding TransCanada and its subsidiaries, including management's assessment of TransCanada's and its subsidiaries' future financial and operational plans and outlook. Forward-looking statements in this document may include, among others, statements regarding the anticipated business prospects, projects and financial performance of TransCanada and its subsidiaries, expectations or projections about the future, strategies and goals for growth and expansion, expected and future cash flows, costs, schedules (including anticipated construction and completion dates), operating and financial results and expected impact of future commitments and contingent liabilities, including future abandonment costs. All forward-looking statements reflect TransCanada's beliefs and assumptions based on information available at the time the statements were made. Actual results or events may differ from those predicted in these forward-looking statements. Factors that could cause actual results or events to differ materially from current expectations include, among others, the ability of TransCanada to successfully implement its strategic initiatives and whether such strategic initiatives will yield the expected benefits, the operating performance of the Company's pipeline and energy assets, the availability and price of energy commodities, capacity payments, regulatory processes and decisions, outcomes of litigation and arbitration proceedings, changes in environmental and other laws and regulations, competitive factors in the pipeline and energy sectors, construction and completion of capital projects, labour, equipment and material costs, access to capital markets, interest and currency exchange rates, technological developments and economic conditions in North America. By its nature, forward-looking information is subject to various risks and uncertainties, which could cause TransCanada's actual results and experience to differ materially from the anticipated results or expectations expressed.
Additional information on these and other factors is available in the reports filed by TransCanada with Canadian securities regulators and with the U.S. Securities and Exchange Commission. Readers are cautioned not to place undue reliance on this forward-looking information, which is given as of the date it is expressed in this news release or otherwise specified, and not to use future-oriented information or financial outlooks for anything other than their intended purpose. TransCanada undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, except as required by law.
Non-GAAP Measures
TransCanada uses the measures Comparable Earnings, Comparable Earnings per Share, Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA), Comparable EBITDA, Earnings Before Interest and Taxes (EBIT), Comparable EBIT, Comparable Interest Expense, Comparable Interest Income and Other, Comparable Income Taxes and Funds Generated from Operations in this news release. These measures do not have any standardized meaning prescribed by Canadian generally accepted accounting principles (GAAP). They are, therefore, considered to be non-GAAP measures and may not be comparable to similar measures presented by other entities. Management of TransCanada uses these non-GAAP measures to improve its ability to compare financial results among reporting periods and to enhance its understanding of operating performance, liquidity and ability to generate funds to finance operations. These non-GAAP measures are also provided to readers as additional information on TransCanada's operating performance, liquidity and ability to generate funds to finance operations.
EBITDA is an approximate measure of the Company's pre-tax operating cash flow and is generally used to better measure performance and evaluate trends of individual assets. EBITDA comprises earnings before deducting interest and other financial charges, income taxes, depreciation and amortization, net income attributable to non-controlling interests and preferred share dividends. EBIT is a measure of the Company's earnings from ongoing operations and is generally used to better measure performance and evaluate trends within each segment. EBIT comprises earnings before deducting interest and other financial charges, income taxes, net income attributable to non-controlling interests and preferred share dividends.
Comparable Earnings, Comparable EBITDA, Comparable EBIT, Comparable Interest Expense, Comparable Interest Income and Other, and Comparable Income Taxes comprise Net Income Attributable to Common Shares, EBITDA, EBIT, Interest Expense, Interest Income and Other, and Income Taxes Expense, respectively, adjusted for specific items that are significant but are not reflective of the Company's underlying operations in the period. Specific items are subjective, however, management uses its judgement and informed decision-making when identifying items to be excluded in calculating these non-GAAP measures, some of which may recur. Specific items may include but are not limited to certain fair value adjustments relating to risk management activities, income tax refunds and adjustments, gains or losses on sales of assets, legal and bankruptcy settlements, and write-downs of assets and investments.
The Company engages in risk management activities to reduce its exposure to certain financial and commodity price risks by utilizing instruments such as derivatives. The risk management activities which TransCanada excludes from Comparable Earnings provide effective economic hedges but do not meet the specific criteria for hedge accounting treatment and, therefore, changes in their fair values are recorded in Net Income each period. The unrealized gains or losses from changes in the fair value of these derivative contracts and natural gas inventory in storage are not considered to be representative of the underlying operations in the current period or the positive margin that will be realized upon settlement. As a result, these amounts have been excluded in the determination of Comparable Earnings.
The table in the Non-GAAP Measures section of the Management's Discussion and Analysis presents a reconciliation of these non-GAAP measures to Net Income Attributable to Common Shares. Comparable Earnings per Share is calculated by dividing Comparable Earnings by the weighted average number of common shares outstanding for the period.
Funds Generated from Operations comprise Net Cash Provided by Operations before changes in operating working capital and allows management to better measure consolidated operating cash flow, excluding fluctuations from working capital balances which may not necessarily be reflective of underlying operations in the same period. A reconciliation of Funds Generated from Operations to Net Cash Provided by Operations is presented in the Third Quarter 2011 Financial Highlights table in this news release.
Third Quarter 2011 Financial Highlights
Operating Results
Three months ended Nine months ended
(unaudited) September 30 September 30
(millions of dollars) 2011 2010 2011 2010
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Revenues 2,393 2,129 6,779 6,007
Comparable EBITDA(1) 1,258 1,007 3,622 2,936
Net Income Attributable to Controlling
Interests 397 391 1,193 989
Net Income Attributable to Common
Shares 384 377 1,152 958
Comparable Earnings(1) 417 374 1,199 977
Cash Flows
Funds generated from operations(1) 971 861 2,782 2,519
Decrease/(increase) in operating
working capital 94 (70) 192 (271)
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Net cash provided by operations 1,065 791 2,974 2,248
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Capital Expenditures 696 1,297 2,135 3,565
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Common Share Statistics
Three months ended Nine months ended
September 30 September 30
(unaudited) 2011 2010 2011 2010
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Net Income per Share - Basic $ 0.55 $ 0.54 $ 1.64 $ 1.39
Comparable Earnings per Share(1) $ 0.59 $ 0.54 $ 1.71 $ 1.42
Dividends Declared per Share $ 0.42 $ 0.40 $ 1.26 $ 1.20
Basic Common Shares Outstanding
(millions)
Average for the period 703 692 701 689
End of period 703 693 703 693
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(1) Refer to the Non-GAAP Measures section in this news release for further discussion of Comparable EBITDA, Comparable Earnings, Funds Generated from Operations and Comparable Earnings per Share.
Quarterly Report to Shareholders
Management's Discussion and Analysis
Management's Discussion and Analysis (MD&A) dated October 31, 2011 should be read in conjunction with the accompanying unaudited Consolidated Financial Statements of TransCanada Corporation (TransCanada or the Company) for the three and nine months ended September 30, 2011. In 2011, the Company will prepare its consolidated financial statements in accordance with Canadian generally accepted accounting principles (GAAP) as defined in Part V of the Canadian Institute of Chartered Accountants (CICA) Handbook, which is discussed further in the Changes in Accounting Policies section in this MD&A. This MD&A should also be read in conjunction with the audited Consolidated Financial Statements and notes thereto, and the MD&A contained in TransCanada's 2010 Annual Report for the year ended December 31, 2010. Additional information relating to TransCanada, including the Company's Annual Information Form and other continuous disclosure documents, is available on SEDAR at www.sedar.com under TransCanada Corporation's profile. "TransCanada" or "the Company" includes TransCanada Corporation and its subsidiaries, unless otherwise indicated. Amounts are stated in Canadian dollars unless otherwise indicated. Abbreviations and acronyms used but not otherwise defined in this MD&A are identified in the Glossary of Terms contained in TransCanada's 2010 Annual Report.
Forward-Looking Information
This MD&A may contain certain information that is forward looking and is subject to important risks and uncertainties. The words "anticipate", "expect", "believe", "may", "should", "estimate", "project", "outlook", "forecast" or other similar words are used to identify such forward-looking information. Forward-looking statements in this document are intended to provide TransCanada security holders and potential investors with information regarding TransCanada and its subsidiaries, including management's assessment of TransCanada's and its subsidiaries' future financial and operational plans and outlook. Forward-looking statements in this document may include, among others, statements regarding the anticipated business prospects, projects and financial performance of TransCanada and its subsidiaries, expectations or projections about the future, strategies and goals for growth and expansion, expected and future cash flows, costs, schedules (including anticipated construction and completion dates), operating and financial results, and expected impact of future commitments and contingent liabilities, including future abandonment costs. All forward looking statements reflect TransCanada's beliefs and assumptions based on information available at the time the statements were made.
Actual results or events may differ from those predicted in these forward-looking statements. Factors that could cause actual results or events to differ materially from current expectations include, among others, the ability of TransCanada to successfully implement its strategic initiatives and whether such strategic initiatives will yield the expected benefits, the operating performance of the Company's pipeline and energy assets, the availability and price of energy commodities, capacity payments, regulatory processes and decisions, outcomes of litigation and arbitration proceedings, changes in environmental and other laws and regulations, competitive factors in the pipeline and energy sectors, construction and completion of capital projects, labour, equipment and material costs, access to capital markets, interest and currency exchange rates, technological developments and economic conditions in North America. By its nature, forward looking information is subject to various risks and uncertainties, including those material risks discussed in the Financial Instruments and Risk Management section in this MD&A, which could cause TransCanada's actual results and experience to differ materially from the anticipated results or expectations expressed. Additional information on these and other factors is available in the reports filed by TransCanada with Canadian securities regulators and with the U.S. Securities and Exchange Commission (SEC). Readers are cautioned not to place undue reliance on this forward looking information, which is given as of the date it is expressed in this MD&A or otherwise specified, and not to use future-oriented information or financial outlooks for anything other than their intended purpose. TransCanada undertakes no obligation to update publicly or revise any forward looking information, whether as a result of new information, future events or otherwise, except as required by law.
Non-GAAP Measures
TransCanada uses the measures Comparable Earnings, Comparable Earnings per Share, Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA), Comparable EBITDA, Earnings Before Interest and Taxes (EBIT), Comparable EBIT, Comparable Interest Expense, Comparable Interest Income and Other, Comparable Income Taxes and Funds Generated from Operations in this MD&A. These measures do not have any standardized meaning prescribed by GAAP. They are, therefore, considered to be non-GAAP measures and may not be comparable to similar measures presented by other entities. Management of TransCanada uses these non-GAAP measures to improve its ability to compare financial results among reporting periods and to enhance its understanding of operating performance, liquidity and ability to generate funds to finance operations. These non-GAAP measures are also provided to readers as additional information on TransCanada's operating performance, liquidity and ability to generate funds to finance operations.
EBITDA is an approximate measure of the Company's pre-tax operating cash flow and is generally used to better measure performance and evaluate trends of individual assets. EBITDA comprises earnings before deducting interest and other financial charges, income taxes, depreciation and amortization, net income attributable to non-controlling interests and preferred share dividends. EBIT is a measure of the Company's earnings from ongoing operations and is generally used to better measure performance and evaluate trends within each segment. EBIT comprises earnings before deducting interest and other financial charges, income taxes, net income attributable to non-controlling interests and preferred share dividends.
Comparable Earnings, Comparable EBITDA, Comparable EBIT, Comparable Interest Expense, Comparable Interest Income and Other, and Comparable Income Taxes comprise Net Income Attributable to Common Shares, EBITDA, EBIT, Interest Expense, Interest Income and Other, and Income Taxes Expense, respectively, adjusted for specific items that are significant but are not reflective of the Company's underlying operations in the period. Specific items are subjective, however, management uses its judgement and informed decision-making when identifying items to be excluded in calculating these non-GAAP measures, some of which may recur. Specific items may include but are not limited to certain fair value adjustments relating to risk management activities, income tax refunds and adjustments, gains or losses on sales of assets, legal and bankruptcy settlements, and write-downs of assets and investments.
The Company engages in risk management activities to reduce its exposure to certain financial and commodity price risks by utilizing instruments such as derivatives. The risk management activities which TransCanada excludes from Comparable Earnings provide effective economic hedges but do not meet the specific criteria for hedge accounting treatment and, therefore, changes in their fair values are recorded in Net Income each period. The unrealized gains or losses from changes in the fair value of these derivative contracts and natural gas inventory in storage are not considered to be representative of the underlying operations in the current period or the positive margin that will be realized upon settlement. As a result, these amounts have been excluded in the determination of Comparable Earnings.
The tables below present a reconciliation of these non-GAAP measures to Net Income Attributable to Common Shares. Comparable Earnings per Share is calculated by dividing Comparable Earnings by the weighted average number of common shares outstanding for the period.
Funds Generated from Operations comprise Net Cash Provided by Operations before changes in operating working capital and allows management to better measure consolidated operating cash flow, excluding fluctuations from working capital balances which may not necessarily be reflective of underlying operations in the same period. A reconciliation of Funds Generated from Operations to Net Cash Provided by Operations is presented in the Funds Generated from Operations table in the Liquidity and Capital Resources section in this MD&A.
Reconciliation of Non-GAAP Measures
For the three
months ended
September 30 Natural
(unaudited) Gas Oil
(millions of Pipelines Pipelines Energy Corporate Total
dollars) 2011 2010 2011 2010 2011 2010 2011 2010 2011 2010
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Comparable
EBITDA 721 714 156 - 399 311 (18) (18) 1,258 1,007
Depreciation and
amortization (247) (232) (38) - (101) (94) (3) - (389) (326)
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Comparable EBIT 474 482 118 - 298 217 (21) (18) 869 681
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Other Income Statement Items
Comparable interest expense (242) (159)
Interest expense of joint ventures (13) (13)
Comparable interest income and other (5) 27
Comparable income taxes (147) (119)
Net income attributable to non-controlling interests (32) (29)
Preferred share dividends (13) (14)
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Comparable Earnings 417 374
Specific item (net of tax):
Risk management activities(1) (33) 3
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Net Income Attributable to Common Shares 384 377
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For the three months ended September 30
(unaudited)(millions of dollars except per share amounts) 2011 2010
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Comparable Interest Expense (242) (159)
Specific item:
Risk management activities(1) 2 -
------------------
Interest Expense (240) (159)
------------------
------------------
Comparable Interest Income and Other (5) 27
Specific item:
Risk management activities(1) (39) -
------------------
Interest Income and Other (44) 27
------------------
------------------
Comparable Income Taxes (147) (119)
Specific item:
Income taxes attributable to risk management
activities(1) 14 (1)
------------------
Income Taxes Expense (133) (120)
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Comparable Earnings per Share $ 0.59 $ 0.54
Specific items (net of tax):
Risk management activities (0.04) -
------------------
Net Income per Share $ 0.55 $ 0.54
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(1) For the three months ended September 30
(unaudited)(millions of dollars) 2011 2010
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Risk Management Activities Gains/(Losses):
U.S. Power derivatives (3) (3)
Canadian Power derivatives (3) -
Natural Gas Storage proprietary inventory and derivatives (4) 7
Interest rate derivatives 2 -
Foreign exchange derivatives (39) -
Income taxes attributable to risk management activities 14 (1)
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Risk Management Activities (33) 3
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For the nine
months ended
September 30
(unaudited) Natural Gas Oil
(millions of Pipelines Pipelines Energy Corporate Total
dollars) 2011 2010 2011 2010 2011 2010 2011 2010 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Comparable
EBITDA 2,228 2,178 408 - 1,043 824 (57) (66) 3,622 2,936
Depreciation
and
amortization (735) (736) (95) - (298) (274) (10) - (1,138) (1,010)
--------------------------------------------------------------
Comparable
EBIT 1,493 1,442 313 - 745 550 (67) (66) 2,484 1,926
-----------------------------------------------
-----------------------------------------------
Other Income Statement Items
Comparable interest expense (688) (528)
Interest expense of joint ventures (40) (44)
Comparable interest income and other 52 33
Comparable income taxes (472) (297)
Net income attributable to non-controlling interests (96) (82)
Preferred share dividends (41) (31)
---------------
Comparable Earnings 1,199 977
Specific item (net of tax):
Risk management activities(1) (47) (19)
---------------
Net Income Attributable to Common Shares 1,152 958
---------------
---------------
For the nine months ended September 30
(unaudited)(millions of dollars except per share amounts) 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Comparable Interest Expense (688) (528)
Specific item:
Risk management activities(1) 2 -
------------------
Interest Expense (686) (528)
------------------
------------------
Comparable Interest Income and Other 52 33
Specific item:
Risk management activities(1) (40) -
------------------
Interest Income and Other 12 33
------------------
------------------
Comparable Income Taxes (472) (297)
Specific item:
Income taxes attributable to risk management
activities(1) 22 11
------------------
Income Taxes Expense (450) (286)
------------------
------------------
Comparable Earnings per Share $ 1.71 $ 1.42
Specific items (net of tax):
Risk management activities (0.07) (0.03)
------------------
Net Income per Share $ 1.64 $ 1.39
------------------
------------------
(1) For the nine months ended September 30
(unaudited)(millions of dollars) 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Risk Management Activities Gains/(Losses):
U.S. Power derivatives (15) (22)
Canadian Power derivatives (3) -
Natural Gas Storage proprietary inventory and derivatives (13) (8)
Interest rate derivatives 2 -
Foreign exchange derivatives (40) -
Income taxes attributable to risk management activities 22 11
----------------
Risk Management Activities (47) (19)
----------------
----------------
Consolidated Results of Operations
Third Quarter Results
Comparable Earnings in third quarter 2011 were $417 million or $0.59 per share compared to $374 million or $0.54 per share for the same period in 2010. Comparable Earnings in third quarter 2011 excluded net unrealized after-tax losses of $33 million ($47 million pre-tax) (2010 - gains of $3 million after tax ($4 million pre-tax)) resulting from changes in the fair value of certain risk management activities.
Comparable Earnings increased $43 million or $0.05 per share in third quarter 2011 compared to the same period in 2010 and reflected the following:
-- decreased Natural Gas Pipelines Comparable EBIT primarily due to lower
earnings from the Alberta System as a result of the nine-month impact of
the 2010 Alberta System Settlement recorded in third quarter 2010 and
the negative impact of a weaker U.S. dollar on U.S. operations,
partially offset by incremental earnings from Bison and Guadalajara
which were placed in service in January 2011 and June 2011,
respectively;
-- Oil Pipelines Comparable EBIT as the Company commenced recording
earnings from Keystone in February 2011;
-- increased Energy Comparable EBIT primarily due to higher realized power
prices in Western Power and incremental earnings from the start-up of
Halton Hills in September 2010 and Coolidge in May 2011, partially
offset by lower volumes and prices in U.S. Power and lower Natural Gas
Storage revenues;
-- increased Comparable Interest Expense primarily due to decreased
capitalized interest upon placing Keystone, Halton Hills and Coolidge
into service, partially offset by the positive impact of a weaker U.S.
dollar on U.S. dollar-denominated interest expense;
-- decreased Comparable Interest Income and Other, which included realized
losses in 2011 compared to gains in 2010 on derivatives used to manage
the Company's exposure to foreign exchange rate fluctuations on U.S.
dollar-denominated income; and
-- increased Comparable Income Taxes primarily due to higher pre-tax
earnings in 2011 compared to 2010.
TransCanada's Net Income Attributable to Controlling Interests in third quarter 2011 was $397 million and Net Income Attributable to Common Shares was $384 million or $0.55 per share compared to $391 million and $377 million or $0.54 per share, respectively, in third quarter 2010.
Nine Month Results
Comparable Earnings in the first nine months of 2011 were $1,199 million or $1.71 per share compared to $977 million or $1.42 per share for the same period in 2010. Comparable Earnings for the first nine months of 2011 excluded net unrealized after-tax losses of $47 million ($69 million pre-tax) (2010 - after-tax losses of $19 million ($30 million pre-tax)) resulting from changes in the fair value of certain risk management activities.
Comparable Earnings increased $222 million or $0.29 per share in the first nine months of 2011 compared to the same period in 2010 and reflected the following:
-- increased EBIT from Natural Gas Pipelines primarily due to incremental
earnings from Bison and Guadalajara, which were placed in service in
January 2011 and June 2011, respectively, lower general and
administrative expenses, and higher earnings from the Canadian Mainline,
partially offset by the negative impact of a weaker U.S. dollar;
-- Oil Pipelines Comparable EBIT as the Company commenced recording
earnings from Keystone in February 2011;
-- increased EBIT from Energy primarily due to higher overall realized
power prices in Western Power, incremental earnings from the start-up of
Halton Hills in September 2010, Coolidge in May 2011 and phase two of
Kibby Wind in October 2010, and higher volumes and lower operating
expenses due to reduced outage days and higher realized prices at Bruce
A, partially offset by lower realized prices and reduced volumes at
Bruce B, and decreased third-party and proprietary storage revenues for
Natural Gas Storage;
-- increased Comparable Interest Expense primarily due to decreased
capitalized interest upon placing Keystone and Halton Hills into
service, partially offset by the positive impact of a weaker U.S. dollar
on U.S. dollar-denominated interest expense;
-- increased Comparable Interest Income and Other due to higher realized
gains in 2011 compared to 2010 on derivatives used to manage the
Company's exposure to foreign exchange rate fluctuations on U.S. dollar-
denominated income;
-- increased Comparable Income Taxes primarily due to higher pre-tax
earnings in 2011 compared to 2010 and higher positive income tax
adjustments in 2010; and
-- increased Preferred Share Dividends due to new preferred share issues in
2010.
TransCanada's Net Income Attributable to Controlling Interests in the first nine months of 2011 was $1,193 million and Net Income Attributable to Common Shares was $1,152 million or $1.64 per share compared to $989 million and $958 million or $1.39 per share, respectively, for the same period in 2010.
Further discussion of the financial results for the three and nine months ended September 30, 2011 is included in the Natural Gas Pipelines, Oil Pipelines, Energy and Other Income Statement Items sections in this MD&A.
U.S. Dollar-Denominated Balances
On a consolidated basis, the impact of changes in the value of the U.S. dollar on U.S. operations is partially offset by other U.S. dollar-denominated items as set out in the following table. The resultant pre-tax net exposure is managed using derivatives, further reducing the Company's exposure to changes in Canadian-U.S. foreign exchange rates. The average U.S. dollar to Canadian dollar exchange rate for the three and nine months ended September 30, 2011 was 0.98 and 0.98, respectively (2010 - 1.04 and 1.04, respectively).
Summary of Significant U.S. Dollar-Denominated Amounts
Three months ended Nine months ended
(unaudited) September 30 September 30
(millions of U.S. dollars, pre-tax) 2011 2010 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
U.S. Natural Gas Pipelines
Comparable EBIT(1) 173 149 597 522
U.S. Oil Pipelines Comparable
EBIT(1) 78 - 210 -
U.S. Power Comparable EBIT(1) 63 83 160 164
Interest on U.S. dollar-denominated
long-term debt (187) (175) (549) (497)
Capitalized interest on U.S. capital
expenditures 21 78 93 211
U.S. non-controlling interests and
other (48) (39) (143) (120)
----------------------------------------
100 96 368 280
----------------------------------------
----------------------------------------
(1) Refer to the Non-GAAP Measures section in this MD&A for further
discussion of Comparable EBIT.
Natural Gas Pipelines
Natural Gas Pipelines' Comparable EBIT was $474 million and $1,493 million in the three and nine months ended September 30, 2011, respectively, compared to $482 million and $1,442 million, respectively, for the same periods in 2010.
Natural Gas Pipelines Results
Three months ended Nine months ended
(unaudited) September 30 September 30
(millions of dollars) 2011 2010 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Canadian Natural Gas Pipelines
Canadian Mainline 264 257 796 785
Alberta System 191 197 557 548
Foothills 31 34 96 102
Other (TQM, Ventures LP) 13 12 38 39
----------------------------------------
Canadian Natural Gas Pipelines
Comparable EBITDA(1) 499 500 1,487 1,474
Depreciation and amortization (181) (167) (542) (535)
----------------------------------------
Canadian Natural Gas Pipelines
Comparable EBIT(1) 318 333 945 939
----------------------------------------
U.S. Natural Gas Pipelines (in U.S.
dollars)
ANR 58 64 239 238
GTN(2) 29 42 105 125
Great Lakes(3) 26 26 81 83
PipeLines LP(4)(5) 26 26 76 73
Iroquois 15 16 50 51
Bison(2)(6) 8 - 35 -
Portland(5)(7) 2 1 15 12
International (Tamazunchale,
Guadalajara, TransGas,
Gas Pacifico/INNERGY)(8) 27 10 52 34
General, administrative and support
costs(9) (2) (16) (6) (25)
Non-controlling interests(5) 52 42 148 124
----------------------------------------
U.S. Natural Gas Pipelines
Comparable EBITDA(1) 241 211 795 715
Depreciation and amortization (68) (62) (198) (193)
----------------------------------------
U.S. Natural Gas Pipelines
Comparable EBIT(1) 173 149 597 522
Foreign exchange (3) 8 (12) 22
----------------------------------------
U.S. Natural Gas Pipelines
Comparable EBIT(1)
(in Canadian dollars) 170 157 585 544
----------------------------------------
Natural Gas Pipelines Business
Development Comparable EBITDA(1) (14) (8) (37) (41)
----------------------------------------
Natural Gas Pipelines Comparable
EBIT(1) 474 482 1,493 1,442
----------------------------------------
----------------------------------------
Summary:
Natural Gas Pipelines Comparable
EBITDA(1) 721 714 2,228 2,178
Depreciation and amortization (247) (232) (735) (736)
----------------------------------------
Natural Gas Pipelines Comparable
EBIT(1) 474 482 1,493 1,442
----------------------------------------
----------------------------------------
(1) Refer to the Non-GAAP Measures section in this MD&A for further
discussion of Comparable EBITDA and Comparable EBIT.
(2) Results reflect TransCanada's direct ownership interest of 75 per cent
effective May 3, 2011 and 100 per cent prior to that date.
(3) Represents TransCanada's 53.6 per cent direct ownership interest.
(4) Effective May 3, 2011, TransCanada's ownership interest in PipeLines LP
decreased from 38.2 per cent to 33.3 per cent. As a result, PipeLines
LP's results include TransCanada's decreased ownership in PipeLines LP
and TransCanada's effective ownership through PipeLines LP of 8.3 per
cent of each of GTN and Bison since May 3, 2011.
(5) Non-Controlling Interests reflects Comparable EBITDA for the portions of
PipeLines LP and Portland not owned by TransCanada.
(6) Includes Bison effective January 14, 2011.
(7) Represents TransCanada's 61.7 per cent ownership interest.
(8) Includes Guadalajara's operations since June 15, 2011.
(9) Represents General, Administrative and Support Costs associated with
certain of TransCanada's pipelines.
Net Income for Wholly Owned Canadian Natural Gas Pipelines
Three months ended Nine months ended
(unaudited) September 30 September 30
(millions of dollars) 2011 2010 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Canadian Mainline 61 66 186 196
Alberta System 51 70 149 145
Foothills 6 7 18 20
----------------------------------------
----------------------------------------
Canadian Natural Gas Pipelines
Canadian Mainline's net income for the three and nine months ended September 30, 2011 decreased $5 million and $10 million, respectively, compared to the same periods in 2010 primarily due to a lower rate of return on common equity (ROE), as determined by the National Energy Board (NEB), of 8.08 per cent in 2011 compared to 8.52 per cent in 2010, as well as a lower average investment base. The impact of the lower ROE and average investment base was partially offset by higher incentive earnings in 2011.
The Alberta System's net income was $51 million and $149 million for the three and nine months ended September 30, 2011 compared to $70 million and $145 million, respectively, for the same periods in 2010. The decrease in net income in third quarter 2011 compared to 2010 was primarily due to the regulatory approval and recognition in September 2010 of the Alberta System Settlement, which included a 9.70 per cent ROE on deemed common equity of 40 per cent, effective January 1, 2010. The increase in net income for the first nine months of 2011 compared to 2010 was primarily due to higher incentive earnings.
Canadian Mainline's Comparable EBITDA for the three and nine months ended September 30, 2011 of $264 million and $796 million, respectively, increased $7 million and $11 million, respectively, compared to the same periods in 2010. The Alberta System's Comparable EBITDA was $191 million and $557 million for the three and nine months ended September 30, 2011 compared to $197 million and $548 million, respectively, for the same periods in 2010. EBITDA from the Canadian Mainline and the Alberta System includes net income variances discussed above as well as flow-through items which do not affect net income.
U.S. Natural Gas Pipelines
ANR's Comparable EBITDA for the three and nine months ended September 30, 2011 was US$58 million and US$239 million, respectively, compared to US$64 million and US$238 million, respectively, for the same periods in 2010. The decrease in third quarter 2011 was primarily due to higher operating, maintenance and administration (OM&A) costs. For the nine months ended September 30, 2011, the increase was primarily due to higher transportation and storage revenues, a settlement with a counterparty and increased incidental commodity sales partially offset by higher OM&A costs.
GTN's Comparable EBITDA for the three and nine months ended September 30, 2011 was US$29 million and US$105 million, respectively, compared to US$42 million and US$125 million, respectively, for the same periods in 2010. The decreases were primarily due to TransCanada's sale of a 25 per cent interest in GTN to PipeLines LP in May 2011.
The Bison pipeline was placed in service on January 14, 2011. TransCanada's portion of Comparable EBITDA was US$8 million and US$35 million for the three and nine months ended September 30, 2011, respectively. EBITDA reflects TransCanada's 75 per cent interest in Bison subsequent to the sale of a 25 per cent interest in Bison to PipeLines LP in May 2011 and 100 per cent prior to that date.
Comparable EBITDA for the remainder of the U.S. Natural Gas Pipelines was US$146 million and US$416 million for the three and nine months ended September 30, 2011, respectively, compared to US$105 million and US$352 million, respectively, for the same periods in 2010. The increases were primarily due to incremental earnings from the Guadalajara pipeline, which was placed in service on June 15, 2011, lower general, administrative and support costs and higher Non-Controlling Interests due to the sale of a 25 per cent interest in GTN and Bison to PipeLines LP in May 2011.
Depreciation
Natural Gas Pipelines' depreciation increased $15 million and decreased $1 million for the three and nine months ended September 30, 2011, respectively, compared to the same periods in 2010. The increase in the third quarter was primarily due to an adjustment for the regulatory approval and recognition in September 2010 of the Alberta System Settlement which included a reduction in the composite depreciation rate, effective January 1, 2010, and incremental depreciation for Bison and Guadalajara partially offset by the effect of a weaker U.S. dollar.
Business Development
Natural Gas Pipelines' Business Development Comparable EBITDA loss increased $6 million and decreased $4 million in the three and nine months ended September 30, 2011, respectively, compared to the same periods in 2010. Business development costs increased in third quarter 2011 compared to third quarter 2010 primarily due to greater activity in 2011 for the Alaska Pipeline Project. Business development costs in the first nine months of 2011 decreased primarily due to the increased reimbursement by the State of Alaska to 90 per cent from 50 per cent effective July 31, 2010. Project applicable expenses and reimbursements are shared proportionately with ExxonMobil, TransCanada's joint venture partner in the Alaska Pipeline Project. The decrease in business development costs in the first nine months of 2011 was partially offset by a levy charged by the NEB in March 2011 to recover the Aboriginal Pipeline Group's proportionate share of costs relating to the Mackenzie Gas Project hearings.
Operating Statistics
Nine months ended Canadian Alberta
September 30 Mainline(1) System(2) Foothills ANR(3)
(unaudited) 2011 2010 2011 2010 2011 2010 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Average investment
base (millions of
dollars) 6,250 6,518 5,017 4,986 611 661 n/a n/a
Delivery volumes
(Bcf)
Total 1,474 1,191 2,580 2,535 948 1,054 1,276 1,171
Average per day 5.4 4.4 9.5 9.3 3.5 3.9 4.7 4.3
---------------------------------------------------------
---------------------------------------------------------
(1) Canadian Mainline's throughput volumes in the above table reflect
physical deliveries to domestic and export markets. Canadian Mainline's
physical receipts originating at the Alberta border and in Saskatchewan
for the nine months ended September 30, 2011 were 912 billion cubic feet
(Bcf) (2010 - 927 Bcf); average per day was 3.3 Bcf (2010 - 3.4 Bcf).
(2) Field receipt volumes for the Alberta System for the nine months ended
September 30, 2011 were 2,643 Bcf (2010 - 2,619 Bcf); average per day
was 9.7 Bcf (2010 - 9.6 Bcf).
(3) ANR's results are not impacted by average investment base as these
systems operate under fixed-rate models approved by the U.S. Federal
Energy Regulatory Commission.
Oil Pipelines
Oil Pipelines Comparable EBIT for the three and eight months ended September 30, 2011, was $118 million and $313 million, respectively. At the beginning of February 2011, the Company commenced recording EBITDA for the Wood River/Patoka section of Keystone following the NEB's decision to remove the maximum operating pressure restriction along the conversion section of the system. The Cushing Extension was also placed in service at that time.
Oil Pipelines Results
Three months Eight months
ended ended
For the period February 1 to September 30 September 30 September 30
(unaudited)(millions of dollars) 2011 2011
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Canadian Oil Pipelines Comparable EBITDA(1) 56 146
Depreciation and amortization (14) (36)
----------------------------
Canadian Oil Pipelines Comparable EBIT(1) 42 110
----------------------------
U.S. Oil Pipelines Comparable EBITDA(1) (in U.S.
dollars) 102 270
Depreciation and amortization (24) (60)
----------------------------
U.S. Oil Pipelines Comparable EBIT(1) 78 210
Foreign exchange (1) (5)
----------------------------
U.S. Oil Pipelines Comparable EBIT(1) (in
Canadian dollars) 77 205
----------------------------
Oil Pipelines Business Development Comparable
EBITDA(1) (1) (2)
----------------------------
Oil Pipelines Comparable EBIT(1) 118 313
----------------------------
----------------------------
Summary:
Oil Pipelines Comparable EBITDA(1) 156 408
Depreciation and amortization (38) (95)
----------------------------
Oil Pipelines Comparable EBIT(1) 118 313
----------------------------
----------------------------
(1) Refer to the Non-GAAP Measures section in this MD&A for further
discussion of Comparable EBITDA and Comparable EBIT.
Operating Statistics
Three months Eight months
ended ended
For the period February 1 to September 30 September 30 September 30
(unaudited) 2011 2011
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Delivery volumes (thousands of barrels)(1)
Total 39,696 92,329
Average per day 431 382
----------------------------
----------------------------
(1) Delivery volumes reflect physical deliveries.
Energy
Energy's Comparable EBIT was $298 million and $745 million for the three and nine months ended September 30, 2011, respectively, compared to $217 million and $550 million, respectively, for the same periods in 2010.
Energy Results
Three months ended Nine months ended
(unaudited) September 30 September 30
(millions of dollars) 2011 2010 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Canadian Power
Western Power(1) 152 45 346 172
Eastern Power(2) 76 56 227 154
Bruce Power 86 89 219 199
General, administrative and support
costs (11) (14) (28) (29)
----------------------------------------
Canadian Power Comparable EBITDA(3) 303 176 764 496
Depreciation and amortization (72) (61) (208) (179)
----------------------------------------
Canadian Power Comparable EBIT(3) 231 115 556 317
----------------------------------------
U.S. Power (in U.S. dollars)
Northeast Power(4) 100 117 270 268
General, administrative and support
costs (10) (6) (29) (24)
----------------------------------------
U.S. Power Comparable EBITDA(3) 90 111 241 244
Depreciation and amortization (27) (28) (81) (80)
----------------------------------------
U.S. Power Comparable EBIT(3) 63 83 160 164
Foreign exchange - 3 (3) 6
----------------------------------------
U.S. Power Comparable EBIT(3) (in
Canadian dollars) 63 86 157 170
----------------------------------------
Natural Gas Storage
Alberta Storage 14 28 66 101
General, administrative and support
costs (1) (2) (6) (6)
----------------------------------------
Natural Gas Storage Comparable
EBITDA(3) 13 26 60 95
Depreciation and amortization (3) (3) (11) (11)
----------------------------------------
Natural Gas Storage Comparable
EBIT(3) 10 23 49 84
Energy Business Development
Comparable EBITDA(3)
(6) (7) (17) (21)
----------------------------------------
Energy Comparable EBIT(3) 298 217 745 550
----------------------------------------
----------------------------------------
Summary:
Energy Comparable EBITDA(3) 399 311 1,043 824
Depreciation and amortization (101) (94) (298) (274)
----------------------------------------
Energy Comparable EBIT(3) 298 217 745 550
----------------------------------------
----------------------------------------
(1) Includes Coolidge effective May 2011.
(2) Includes Halton Hills effective September 2010.
(3) Refer to the Non-GAAP Measures section in this MD&A for further
discussion of Comparable EBITDA and Comparable EBIT.
(4) Includes phase two of Kibby Wind effective October 2010.
Canadian Power
Western and Eastern Canadian Power Comparable EBIT(1)(2)
Three months ended Nine months ended
(unaudited) September 30 September 30
(millions of dollars) 2011 2010 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenues
Western power 326 168 787 534
Eastern power 119 85 350 217
Other(3) 15 27 56 64
----------------------------------------
460 280 1,193 815
----------------------------------------
Commodity Purchases Resold
Western power (157) (109) (401) (314)
Other(4) (4) (12) (13) (24)
----------------------------------------
(161) (121) (414) (338)
----------------------------------------
Plant operating costs and other (71) (58) (206) (151)
General, administrative and support
costs (11) (14) (28) (29)
----------------------------------------
Comparable EBITDA(1) 217 87 545 297
Depreciation and amortization (43) (33) (123) (102)
----------------------------------------
Comparable EBIT(1) 174 54 422 195
----------------------------------------
----------------------------------------
(1) Refer to the Non-GAAP Measures section in this MD&A for further
discussion of Comparable EBITDA and Comparable EBIT.
(2) Includes Coolidge and Halton Hills effective May 2011 and September
2010, respectively.
(3) Includes sales of excess natural gas purchased for generation and
thermal carbon black. The realized gains and losses from derivatives
used to purchase and sell natural gas to manage Western and Eastern
Power's assets are presented on a net basis in Other Revenues.
(4) Includes the cost of excess natural gas not used in operations.
Western and Eastern Canadian Power Operating Statistics
Three months ended Nine months ended
September 30 September 30
(unaudited) 2011 2010 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Sales Volumes (GWh)
Supply
Generation
Western Power(1) 630 572 1,937 1,751
Eastern Power(2) 1,014 661 2,862 1,485
Purchased
Sundance A & B and Sheerness
PPAs(3) 2,074 2,641 6,034 7,755
Other purchases 352 89 728 311
-------------------------------------------
4,070 3,963 11,561 11,302
-------------------------------------------
-------------------------------------------
Sales
Contracted
Western Power(1) 2,474 2,526 6,781 7,368
Eastern Power(2) 1,014 660 2,862 1,500
Spot
Western Power 582 777 1,918 2,434
-------------------------------------------
4,070 3,963 11,561 11,302
-------------------------------------------
-------------------------------------------
Plant Availability(4)
Western Power(1)(5) 98% 94% 97% 94%
Eastern Power(2)(6) 96% 98% 96% 97%
-------------------------------------------
-------------------------------------------
(1) Includes Coolidge effective May 2011.
(2) Includes Halton Hills effective September 2010.
(3) No volumes were delivered under the Sundance A PPA in 2011.
(4) Plant availability represents the percentage of time in a period that
the plant is available to generate power regardless of whether it is
running.
(5) Excludes facilities that provide power to TransCanada under PPAs.
(6) Becancour has been excluded from the availability calculation as power
generation has been suspended since 2008.
Western Power's Comparable EBITDA of $152 million and Power Revenues of $326 million in third quarter 2011 increased $107 million and $158 million, respectively, compared to the same periods in 2010, primarily due to higher realized power prices in Alberta and incremental earnings from Coolidge, which went into service under a 20-year power purchase arrangement (PPA) in May 2011. Certain plant outages and higher demand resulted in average spot market power prices in Alberta increasing 164 per cent to $95 per megawatt hour (MWh) in third quarter 2011 compared to $36 per MWh in third quarter 2010.
Western Power's Comparable EBITDA of $346 million and Power Revenues of $787 million in the first nine months of 2011 increased $174 million and $253 million, respectively, compared to the same period in 2010 primarily due to higher overall realized prices in Alberta and incremental earnings from Coolidge.
Western Power's Comparable EBITDA in the three and nine months ended September 30, 2011 included $48 million and $99 million, respectively, of accrued earnings from the Sundance A PPA, the revenues and costs of which have been recorded as though the outages of Sundance A Units 1 and 2 are interruptions of supply in accordance with the terms of the PPA. Refer to the Recent Developments section in this MD&A for further discussion regarding the Sundance A outage.
Western Power's Commodity Purchases Resold of $157 million and $401 million for the three and nine months ended September 30, 2011, respectively, increased $48 million and $87 million, respectively, compared to the same periods in 2010 due to higher volumes at Sheerness, higher PPA costs per MWh and increased direct sales to customers.
Eastern Power's Comparable EBITDA of $76 million and $227 million for the three and nine months ended September 30, 2011, respectively, increased $20 million and $73 million, respectively, compared to the same periods in 2010. Similarly, Eastern Power's Power Revenues of $119 million and $350 million for the three and nine months ended September 30, 2011, respectively, increased $34 million and $133 million, respectively, compared to the same periods in 2010. The increases were primarily due to incremental earnings from Halton Hills, which went into service in September 2010.
Plant Operating Costs and Other, which includes fuel gas consumed in power generation, of $71 million and $206 million for the three and nine months ended September 30, 2011, increased $13 million and $55 million, respectively, compared to the same periods in 2010. The increases were primarily due to incremental fuel consumed at Halton Hills.
Depreciation and amortization increased $10 million and $21 million for the three and nine months ended September 30, 2011, respectively, compared to the same periods in 2010 primarily due to incremental depreciation from Halton Hills and Coolidge.
Western Power manages the sale of its supply volumes on a portfolio basis. A portion of its supply is sold into the spot market to assure supply in the event of an unexpected plant outage. The overall amount of spot market volumes sold is also dependent upon the ability to transact in forward sales markets at acceptable contract terms. This approach to portfolio management helps to minimize costs in situations where Western Power would otherwise have to purchase electricity in the open market to fulfill its contractual sales obligations. Approximately 81 per cent of Western Power sales volumes were sold under contract in third quarter 2011, compared to 76 per cent in third quarter 2010. To reduce its exposure to spot market prices on uncontracted volumes, as at September 30, 2011, Western Power had entered into fixed-price power sales contracts to sell approximately 2,300 gigawatt hours (GWh) in fourth quarter 2011 and 7,700 GWh for 2012.
Eastern Power is focused on selling power under long-term contracts. In third quarter 2011 and 2010, 100 per cent of Eastern Power's sales volumes were sold under contract and are expected to continue to be 100 per cent sold under contract for the remainder of 2011 and in 2012.
Bruce Power Results
(TransCanada's proportionate share)
(unaudited) Three months ended Nine months ended
(millions of dollars unless September 30 September 30
otherwise indicated) 2011 2010 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenues(1) 221 212 636 634
Operating Expenses (135) (123) (417) (435)
----------------------------------------
Comparable EBITDA(2) 86 89 219 199
----------------------------------------
----------------------------------------
Bruce A Comparable EBITDA(2) 33 35 99 58
Bruce B Comparable EBITDA(2) 53 54 120 141
----------------------------------------
Comparable EBITDA(2) 86 89 219 199
Depreciation and amortization (29) (28) (85) (77)
----------------------------------------
Comparable EBIT(2) 57 61 134 122
----------------------------------------
----------------------------------------
Bruce Power - Other Information
Plant availability
Bruce A 97% 92% 98% 77%
Bruce B 94% 88% 88% 90%
Combined Bruce Power 95% 89% 91% 86%
Planned outage days
Bruce A - - 5 60
Bruce B 19 7 92 54
Unplanned outage days
Bruce A 4 7 13 55
Bruce B - 28 24 34
Sales volumes (GWh)
Bruce A 1,489 1,446 4,425 3,556
Bruce B 2,111 2,003 5,903 6,102
----------------------------------------
3,600 3,449 10,328 9,658
----------------------------------------
Results per MWh
Bruce A power revenues $66 $65 $66 $65
Bruce B power revenues(3) $53 $57 $54 $58
Combined Bruce Power revenues $57 $60 $58 $60
----------------------------------------
----------------------------------------
(1) Revenues include Bruce A's fuel cost recoveries of $7 million and $21
million for the three and nine months ended September 30, 2011,
respectively (2010 - $7 million and $21 million).
(2) Refer to the Non-GAAP Measures section in this MD&A for further
discussion of Comparable EBITDA and Comparable EBIT.
(3) Includes revenues received under the floor price mechanism, from deemed
generation, including the associated volumes, and from contract
settlements.
TransCanada's proportionate share of Bruce A's Comparable EBITDA decreased $2 million in third quarter 2011 to $33 million compared to $35 million in third quarter 2010 as a result of higher operating costs, partially offset by increased revenues from higher volumes and higher realized prices.
TransCanada's proportionate share of Bruce B's Comparable EBITDA decreased $1 million in third quarter 2011 to $53 million compared to $54 million in third quarter 2010 as a result of increased revenues from higher volumes being more than offset by lower realized prices due to the expiration of fixed price contracts at higher prices.
TransCanada's proportionate share of Bruce A's Comparable EBITDA increased $41 million in the nine months ended September 30, 2011 to $99 million compared to the same period in 2010 primarily due to higher volumes and lower operating costs due to a decrease in outage days. Results for the nine months ended September 30, 2010 included a payment made from Bruce B to Bruce A regarding 2009 amendments to a long-term agreement with the Ontario Power Authority (OPA). The net positive impact reflected TransCanada's higher percentage ownership interest in Bruce A.
TransCanada's proportionate share of Bruce B's Comparable EBITDA decreased $21 million in the nine months ended September 30, 2011 to $120 million compared to the same period in 2010 primarily due to lower realized prices resulting from the expiration of fixed-price contracts at higher prices as well as lower volumes and higher operating costs due to increased outage days. Bruce B results for the nine months ended September 30, 2010 included the above-noted payment in first quarter 2010 to Bruce A.
Under a contract with the OPA, all output from Bruce A in third quarter 2011 was sold at a fixed price of $66.33 per MWh (before recovery of fuel costs from the OPA) compared to $64.71 per MWh in third quarter 2010. Also under a contract with the OPA, all output from the Bruce B units was subject to a floor price of $50.18 per MWh in third quarter 2011 compared to $48.96 per MWh in third quarter 2010. Both the Bruce A and Bruce B contract prices are adjusted annually for inflation on
April 1.
Amounts received under the Bruce B floor price mechanism within a calendar year are subject to repayment if the monthly average spot price exceeds the floor price. With respect to 2011, TransCanada currently expects spot prices to be less than the floor price for the remainder of the year, therefore no amounts recorded in revenues in the first nine months of 2011 are expected to be repaid.
Bruce B enters into fixed-price contracts whereby Bruce B receives or pays the difference between the contract price and the spot price. Bruce B's realized price decreased by $4 per MWh to $53 per MWh and $54 per MWh for the three and nine months ended September 30, 2011, respectively, and reflected revenues recognized from both the floor price mechanism and contract sales. The decreases were a result of the majority of higher-priced contracts entered into in previous years having expired by the end of December 2010. As the remainder of these higher-priced contracts continue to expire, a further reduction in realized prices at Bruce B is expected.
The overall plant availability percentage in 2011 is expected to be in the mid-80s for the two operating Bruce A units and for the four Bruce B units. Bruce B began an approximate seven week outage on Unit 5 on October 14, 2011, and Bruce A will commence an approximate six month outage (West Shift Plus program) on Unit 3 starting in November 2011.
As at September 30, 2011, TransCanada's share of the total capital cost of the Bruce A refurbishment and restart of Units 1 and 2 was $2.2 billion and was approximately $136 million for the refurbishment of Units 3 and 4.
U.S. Power Comparable EBIT(1)(2)
Three months ended Nine months ended
(unaudited) September 30 September 30
(millions of U.S. dollars) 2011 2010 2011 2010
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Revenues
Power(3) 280 383 759 852
Capacity 70 74 183 180
Other(4) 11 14 54 54
----------------------------------------
361 471 996 1,086
Commodity purchases resold (112) (172) (327) (420)
Plant operating costs and other(4) (149) (182) (399) (398)
General, administrative and support
costs (10) (6) (29) (24)
----------------------------------------
Comparable EBITDA(1) 90 111 241 244
Depreciation and amortization (27) (28) (81) (80)
----------------------------------------
Comparable EBIT(1) 63 83 160 164
----------------------------------------
----------------------------------------
(1) Refer to the Non-GAAP Measures section in this MD&A for further
discussion of Comparable EBITDA and Comparable EBIT.
(2) Includes phase two of Kibby Wind effective October 2010.
(3) The realized gains and losses from financial derivatives used to
purchase and sell power, natural gas and fuel oil to manage U.S. Power's
assets are presented on a net basis in Power Revenues.
(4) Includes revenues and costs related to a third-party service agreement
at Ravenswood.
U.S. Power Operating Statistics(1)
Three months ended Nine months ended
September 30 September 30
(unaudited) 2011 2010 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Physical Sales Volumes (GWh)
Supply
Generation 2,137 2,403 5,369 5,083
Purchased 1,657 2,514 4,777 7,061
----------------------------------------
3,794 4,917 10,146 12,144
----------------------------------------
----------------------------------------
Plant Availability(2)(3) 96% 96% 88% 91%
----------------------------------------
----------------------------------------
(1) Includes phase two of Kibby Wind effective October 2010.
(2) Plant availability represents the percentage of time in a period that
the plant is available to generate power regardless of whether it is
running.
(3) Plant availability decreased in the nine months ended September 30, 2011
due to the impact of planned outages at Ravenswood and OSP.
U.S Power's Comparable EBITDA of US$90 million and US$241 million for the three and nine months ended September 30, 2011, respectively, decreased US$21 million and US$3 million, respectively, compared to the same periods in 2010 primarily due to lower volumes of power sold and lower realized prices partially offset by new sales activity in the PJM Interconnection area (PJM), an increase in the New York commercial customer base and incremental earnings from phase two of Kibby Wind which went into service in October 2010.
U.S. Power's Power Revenues of US$280 million for the three months ended September 30, 2011, decreased US$103 million compared to the same period in 2010 primarily due to lower volumes of power sold and lower realized prices on power sales partially offset by new sales activity in PJM and New York. For the nine months ended September 30, 2011, Power Revenues of US$759 million, decreased US$93 million compared to the same period in 2010, primarily due to lower volumes of power sold, partially offset by new sales activity in PJM and New York.
Capacity Revenues of US$70 million for the three months ended September 30, 2011, decreased US$4 million compared to the same period in 2010. For the nine months ended September 30, 2011, Capacity Revenues of US$183 million increased US$3 million compared to the same period in 2010. Capacity Revenues in third quarter 2011 were negatively impacted by low spot prices in New York as a result of the capacity price issue described in the Recent Developments section of this MD&A. Capacity revenues throughout 2010 were negatively impacted by higher forced outage rates at Ravenswood.
Commodity Purchases Resold of US$112 million and US$327 million for the three and nine months ended September 30, 2011, respectively, decreased US$60 million and US$93 million, respectively, compared to the same periods in 2010 primarily due to a decrease in the quantity of power purchased for resale.
Plant Operating Costs and Other, including fuel gas consumed in generation, of US$149 million in third quarter 2011, decreased US$33 million compared to the same period in 2010 primarily due to lower quantities of fuel purchased as a result of decreased generation. For the nine months ended September 30, 2011, Plant Operating Costs and Other of US$399 million was consistent with the same period in 2010.
U.S. Power focuses on selling power under short- and long-term contracts to wholesale, commercial and industrial customers in the New England, New York and PJM power markets. Exposure to fluctuations in spot prices on these power sales commitments are hedged with a combination of forward purchases of power, forward purchases of fuel to generate power and through the use of financial contracts. As at September 30, 2011, approximately 1,600 GWh or 73 per cent and 2,800 GWh or 31 per cent of U.S. Power's planned generation is contracted for fourth quarter 2011 and fiscal 2012, respectively. Planned generation fluctuates depending on hydrology, wind conditions, commodity prices and the resulting dispatch of the assets, and power sales fluctuate based on customer usage.
Natural Gas Storage
Natural Gas Storage's Comparable EBITDA for the three and nine month periods ended September 30, 2011, was $13 million and $60 million, respectively, compared to $26 million and $95 million for the same periods in 2010. The decreases in Comparable EBITDA in 2011 were primarily due to decreased third party and proprietary storage revenues as a result of lower realized natural gas price spreads, partially offset by lower operating costs.
Other Income Statement Items
Comparable Interest Expense(1)
Three months ended Nine months ended
(unaudited) September 30 September 30
(millions of dollars) 2011 2010 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Interest on long-term debt(2)
Canadian dollar-denominated 121 128 365 388
U.S. dollar-denominated 187 175 549 497
Foreign exchange (4) 7 (12) 18
----------------------------------------
304 310 902 903
Other interest and amortization 4 9 17 62
Capitalized interest (66) (160) (231) (437)
----------------------------------------
Comparable Interest Expense(1) 242 159 688 528
----------------------------------------
----------------------------------------
(1) Refer to the Non-GAAP Measures section in this MD&A for further
discussion of Comparable Interest Expense.
(2) Includes interest on Junior Subordinated Notes.
Comparable Interest Expense for third quarter 2011 increased $83 million to $242 million from $159 million in third quarter 2010. Comparable Interest Expense for the nine months ended September 30, 2011 increased $160 million to $688 million from $528 million for the nine months ended September 30, 2010. The increases reflected lower capitalized interest for Keystone and Halton Hills as a result of placing these assets into service and incremental interest expense on debt issues of US$1.25 billion in June 2010 and US$1.0 billion in September 2010. These increases were partially offset by realized gains in 2011 compared to losses in 2010 on derivatives used to manage the Company's exposure to rising interest rates, the positive impact of a weaker U.S. dollar on U.S. dollar-denominated interest costs and Canadian dollar-denominated debt maturities in 2011 and 2010.
Comparable Interest Income and Other for third quarter 2011 decreased $32 million to a loss of $5 million from income of $27 million in third quarter 2010. The decreases in third quarter reflected realized losses in 2011 compared to gains in 2010 on derivatives used to manage the Company's net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income. Comparable Interest Income and Other for the nine months ended September 30, 2011 increased $19 million to $52 million from $33 million for the nine months ended September 30, 2010. The increase for the nine months ended September 30, 2011 reflected higher realized gains in 2011 compared to 2010 on similar foreign exchange derivatives.
Comparable Income Taxes were $147 million in third quarter 2011 compared to $119 million for the same period in 2010. Comparable Income Taxes for the nine months ended September 30, 2011 were $472 million compared to $297 million for the same period in 2010. The increases were primarily due to higher pre-tax earnings in 2011 compared to 2010 and higher positive income tax adjustments in 2010 compared to 2011.
Liquidity and Capital Resources
TransCanada believes that its financial position remains sound as does its ability to generate cash in the short and long term to provide liquidity, maintain financial capacity and flexibility, and provide for planned growth. TransCanada's liquidity is underpinned by predictable cash flow from operations, cash balances on hand and unutilized committed revolving bank lines of US$1.0 billion, $2.0 billion, US$1.0 billion and US$300 million, maturing in November 2011, October 2016, October 2012 and February 2013, respectively. These facilities also support the Company's commercial paper programs. In addition, at September 30, 2011, TransCanada's proportionate share of unutilized capacity on committed bank facilities at TransCanada-operated affiliates was $183 million with maturity dates in 2012 and 2016. As at September 30, 2011, TransCanada had remaining capacity of $1.75 billion, $2.0 billion and US$1.75 billion under its equity, Canadian debt and U.S. debt shelf prospectuses, respectively.
On October 21, 2011, the Company's $3.0 billion equity base shelf prospectus expired with remaining capacity of $1.75 billion. In November 2011, TransCanada intends to file a new $2.0 billion equity base shelf prospectus. In November 2011, the Company also intends to file a new US$4.0 billion U.S. debt base shelf prospectus to replace its December 2009 US$4.0 billion U.S. debt base shelf prospectus, which is due to expire in January 2012 and has remaining capacity of US$1.75 billion. TransCanada's liquidity, market and other risks are discussed further in the Risk Management and Financial Instruments section in this MD&A.
At September 30, 2011, the Company held Cash and Cash Equivalents of $596 million compared to $764 million at December 31, 2010. The decrease in Cash and Cash Equivalents was primarily due to expenditures for the Company's capital program, debt repayments and dividend payments, partially offset by increased Net Cash Provided by Operations.
Operating Activities
Funds Generated from Operations(1)
Three months ended Nine months ended
(unaudited) September 30 September 30
(millions of dollars) 2011 2010 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Cash Flows
Funds generated from operations(1) 971 861 2,782 2,519
Decrease/(increase) in operating
working capital 94 (70) 192 (271)
---------------------------------------
Net cash provided by operations 1,065 791 2,974 2,248
---------------------------------------
---------------------------------------
(1) Refer to the Non-GAAP Measures section in this MD&A for further
discussion of Funds Generated from Operations.
Net Cash Provided by Operations increased $274 million and $726 million for the three and nine months ended September 30, 2011, respectively, compared to the same periods in 2010, largely as a result of changes in operating working capital as well as increased Funds Generated from Operations. Funds Generated from Operations for the three and nine months ended September 30, 2011 were $971 million and $2.8 billion, compared to $861 million and $2.5 billion, respectively, for the same periods in 2010. The increases were primarily due to an increase in cash generated through earnings, partially offset by the recognition in 2010 of current income tax benefits from U.S. bonus tax depreciation.
As at September 30, 2011, TransCanada's current liabilities were $5.6 billion and current assets were $3.0 billion resulting in a working capital deficiency of $2.6 billion. The Company believes this shortfall can be managed through its ability to generate cash flow from operations as well as its ongoing access to capital markets.
Investing Activities
TransCanada remains committed to executing its remaining $11 billion capital expenditure program. For the three and nine months ended September 30, 2011, capital expenditures totalled $696 million and $2.1 billion, respectively (2010 - $1.3 billion and $3.6 billion, respectively), primarily related to the construction of Keystone, the refurbishment and restart of Bruce A Units 1 and 2, and expansion of the Alberta System.
Financing Activities
On October 14, 2011, TransCanada PipeLines Limited (TCPL) amended and restated its $2.0 billion committed, syndicated, revolving, extendible credit facility. The amended and restated facility is set to expire October 2016 and is fully available.
On October 14, 2011, a wholly-owned subsidiary of the Company, TransCanada PipeLine USA Ltd., refinanced its existing US$1.0 billion credit facility with a new 364-day, US$1.0 billion committed, syndicated, revolving, extendible credit facility which is fully available.
In August 2011, TransCanada PipeLine USA Ltd. made a principal repayment of US$200 million on its US$700 million, five-year term loan which matures in 2012.
In July 2011, PipeLines LP increased its senior syndicated revolving credit facility to US$500 million and extended the maturity date to July 2016. PipeLines LP's remaining US$300 million term loan matures December 2011, and it is expected it will be refinanced with fixed or floating rate debt at or prior to its maturity.
In June 2011, TCPL retired $60 million of 9.5 per cent Medium-Term Notes and, in January 2011, retired $300 million of 4.3 per cent Medium-Term Notes.
In June 2011, PipeLines LP issued US$350 million of 4.65 per cent Senior Notes due 2021 and cancelled US$175 million of its unsecured syndicated senior credit facility. The proceeds from the issuance were used to reduce PipeLines LP's term loan and senior revolving credit facility, and repay its bridge loan facility.
In May 2011, PipeLines LP completed a public offering of 7.2 million common units at a price of US$47.58 per unit, resulting in gross proceeds of approximately US$345 million. TransCanada contributed an additional approximate US$7 million to maintain its general partnership interest and did not purchase any other units. Upon completion of this offering, TransCanada's ownership interest in PipeLines LP decreased from 38.2 per cent to 33.3 per cent. In addition, PipeLines LP made draws of US$61 million on a bridge loan facility and of US$125 million on its senior revolving credit facility.
In June 2011, TCPL filed a $2.0 billion Canadian Medium-Term Notes base shelf prospectus to replace an April 2009 $2.0 billion Canadian Medium-Term Notes base shelf prospectus which expired in May 2011 and had remaining capacity of $2.0 billion.
The Company believes it has the capacity to fund its existing capital program through internally-generated cash flow, continued access to capital markets and liquidity underpinned by in excess of $4 billion of committed credit facilities. TransCanada's financial flexibility is further bolstered by opportunities for portfolio management, including an ongoing role for PipeLines LP.
Dividends
On October 31, 2011, TransCanada's Board of Directors declared a quarterly dividend of $0.42 per share for the quarter ending December 31, 2011 on the Company's outstanding common shares. The dividend is payable on January 31, 2012 to shareholders of record at the close of business on December 30, 2011. In addition, quarterly dividends of $0.2875 and $0.25 per Series 1 and Series 3 preferred share, respectively, were declared for the quarter ending September 30, 2011. The dividends are payable on December 30, 2011 to shareholders of record at the close of business on November 30, 2011. Furthermore, a quarterly dividend of $0.275 per Series 5 preferred share was declared for the period ending January 30, 2012, payable on January 30, 2012 to shareholders of record at the close of business on December 30, 2011.
Commencing with the dividends declared April 28, 2011, common shares purchased with reinvested cash dividends under TransCanada's Dividend Reinvestment and Share Purchase Plan (DRP) will no longer be satisfied with shares issued from treasury at a discount but rather will be acquired on the open market at 100 per cent of the weighted average purchase price. The DRP is available for dividends payable on TransCanada's common and preferred shares, and TCPL's preferred shares. In the three and nine months ended September 30, 2011, TransCanada issued nil and 5.4 million (2010 - 2.9 million and 7.8 million) common shares, respectively, under its DRP, in lieu of making cash dividend payments of nil and $202 million, respectively (2010 - $101 million and $271 million).
Contractual Obligations
There have been no material changes to TransCanada's contractual obligations from December 31, 2010 to September 30, 2011, including payments due for the next five years and thereafter. For further information on these contractual obligations, refer to the MD&A in TransCanada's 2010 Annual Report.
Significant Accounting Policies and Critical Accounting Estimates
To prepare financial statements that conform with GAAP, TransCanada is required to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be dependent on future events. The Company uses the most current information available and exercises careful judgement in making these estimates and assumptions.
TransCanada's significant accounting policies and critical accounting estimates have remained unchanged since December 31, 2010. For further information on the Company's accounting policies and estimates refer to the MD&A in TransCanada's 2010 Annual Report.
Changes in Accounting Policies
The Company's accounting policies have not changed materially from those described in TransCanada's 2010 Annual Report except as follows:
Changes in Accounting Policies for 2011
Business Combinations, Consolidated Financial Statements and Non-Controlling Interests
Effective January 1, 2011, the Company adopted CICA Handbook Section 1582 "Business Combinations", which is effective for business combinations with an acquisition date after January 1, 2011. This standard was amended to require additional use of fair value measurements, recognition of additional assets and liabilities, and increased disclosure. Adopting the standard is expected to have a significant impact on the way the Company accounts for future business combinations. Entities adopting Section 1582 were also required to adopt CICA Handbook Sections 1601 "Consolidated Financial Statements" and 1602 "Non-Controlling Interests". Sections 1601 and 1602 require Non-Controlling Interests to be presented as part of Equity on the balance sheet. In addition, the income statement of the controlling parent now includes 100 per cent of the subsidiary's results and presents the allocation of income between the controlling and non-controlling interests. Changes resulting from the adoption of Section 1582 were applied prospectively and changes resulting from the adoption of Sections 1601 and 1602 were applied retrospectively.
Future Accounting Changes
U.S. GAAP/International Financial Reporting Standards
The CICA's Accounting Standards Board (AcSB) previously announced that Canadian publicly accountable enterprises are required to adopt International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB), effective January 1, 2011.
In October 2010, the AcSB and the Canadian Securities Administrators amended their policies applicable to Canadian publicly accountable enterprises, such as TransCanada, that use rate-regulated accounting (RRA) in order to permit these entities to defer the adoption of IFRS for one year. TransCanada deferred its adoption and accordingly will continue to prepare its consolidated financial statements in 2011 in accordance with Canadian GAAP, as defined by Part V of the CICA Handbook, in order to continue using RRA.
In the application of Canadian GAAP, TransCanada follows specific accounting guidance under U.S. GAAP unique to a rate-regulated business. These RRA standards allow the timing of recognition of certain revenues and expenses to differ from the timing that may otherwise be expected in a non-rate-regulated business under GAAP in order to appropriately reflect the economic impact of regulators' decisions regarding the Company's revenues and tolls. The IASB concluded that the development of RRA under IFRS requires further analysis and removed the RRA project from its current agenda. TransCanada does not expect a final RRA standard under IFRS to be effective in the foreseeable future.
As an SEC registrant, TransCanada prepares and files a "Reconciliation to United States GAAP" and has the option under Canadian disclosure rules to prepare and file its consolidated financial statements using U.S. GAAP. As a result of the developments noted above, the Company's Board of Directors has approved the adoption of U.S. GAAP effective January 1, 2012.
U.S. GAAP Conversion Project
Effective January 1, 2012, the Company will begin reporting using U.S. GAAP. The Company's U.S. GAAP conversion team is led by a multi-disciplinary Steering Committee that provides directional leadership for the adoption of U.S. GAAP. Management also updates TransCanada's Audit Committee on the progress of the U.S. GAAP project at each Audit Committee meeting and reports regularly to the Company's Board of Directors on the status of the conversion project.
U.S. GAAP training sessions for TransCanada staff have been completed and periodic training updates will continue in the future. As noted above, TransCanada prepares and files a "Reconciliation to United States GAAP". As a result, significant changes to existing systems and processes are not required to implement U.S. GAAP as the Company's primary accounting standard. The impact to internal controls over financial reporting and disclosure controls and procedures are currently being assessed and necessary changes, if any, will be in place by the end of 2011.
Identified differences between Canadian GAAP and U.S. GAAP that are significant to the Company are explained below and are consistent with those currently reported in the Company's publicly-filed "Reconciliation to United States GAAP."
Joint Ventures
Canadian GAAP requires the Company to account for certain investments using the proportionate consolidation method of accounting whereby TransCanada's proportionate share of assets, liabilities, revenues, expenses and cash flows are included in the Company's financial statements. U.S. GAAP does not permit the use of proportionate consolidation with respect to TransCanada's joint ventures and requires that such investments be recorded using the equity method of accounting.
Inventory
Canadian GAAP allows the Company's proprietary natural gas inventory held in storage to be recorded at its fair value. Under U.S. GAAP, inventory is recorded at the lower of cost or market.
Income Tax
Canadian GAAP requires an entity to record income tax assets and liabilities resulting from substantively enacted income tax legislation. Under U.S. GAAP, the legislation must be fully enacted for income tax adjustments to be recorded.
Employee Benefits
Canadian GAAP requires an entity to recognize an accrued benefit asset or liability for defined benefit pension and other postretirement benefit plans. Under U.S. GAAP, an employer is required to recognize the overfunded or underfunded status of defined benefit pension and other postretirement benefit plans as an asset or liability in its balance sheet and to recognize changes in the funded status through Other Comprehensive Income in the year in which the change occurs.
Debt Issue Costs
Canadian GAAP requires debt issue costs to be included in long-term debt. Under U.S. GAAP these costs are classified as deferred assets.
Financial Instruments and Risk Management
TransCanada continues to manage and monitor its exposure to counterparty credit, liquidity and market risk.
Counterparty Credit and Liquidity Risk
TransCanada's maximum counterparty credit exposure with respect to financial instruments at the balance sheet date, without taking into account security held, consisted of accounts receivable, portfolio investments recorded at fair value, the fair value of derivative assets, and notes, loans and advances receivable. The carrying amounts and fair values of these financial assets, except amounts for derivative assets, are included in Accounts Receivable and Other, and Available-For-Sale Assets in the Non-Derivative Financial Instruments Summary table below. Guarantees, letters of credit and cash are the primary types of security provided to support these amounts. The majority of counterparty credit exposure is with counterparties who are investment grade. At September 30, 2011, there were no significant amounts past due or impaired.
At September 30, 2011, the Company had a credit risk concentration of $271 million due from a creditworthy counterparty. This amount is expected to be fully collectible and is secured by a guarantee from the counterparty's parent company.
The Company continues to manage its liquidity risk by ensuring sufficient cash and credit facilities are available to meet its operating and capital expenditure obligations when due, under both normal and stressed economic conditions.
Natural Gas Storage Commodity Price Risk
At September 30, 2011, the fair value of proprietary natural gas inventory held in storage, as measured using a weighted average of forward prices for the following four months less selling costs, was $40 million (December 31, 2010 - $49 million). The change in the fair value adjustment of proprietary natural gas inventory in storage in the three and nine months ended September 30, 2011 resulted in net pre-tax unrealized losses of $1 million and nil, respectively (2010 - nil and losses of $20 million, respectively), which were recorded as adjustments to Revenues and Inventories. The change in fair value of natural gas forward purchase and sale contracts in the three and nine months ended September 30, 2011 resulted in net pre-tax unrealized losses of $3 million and $13 million, respectively (2010 - gains of $7 million and $12 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 $7 million at September 30, 2011 (December 31, 2010 - $12 million). The decrease in VAR is primarily a result of lower price volatility in Western Power.
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, 2011, the Company had designated as a net investment hedge U.S. dollar-denominated debt with a carrying value of $10 billion (US$10 billion) and a fair value of $12 billion (US$12 billion). At September 30, 2011, $66 million was included in Other Current Assets, $41 million (December 31, 2010 - $181 million) was included in Intangible and Other Assets, $44 million was included in Accounts Payable, and $83 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 foreign operations.
The fair values and notional principal amounts for the derivatives designated as a net investment hedge were as follows:
Derivatives Hedging Net Investment in Self-Sustaining Foreign Operations
September 30, 2011 December 31, 2010
-------------------- --------------------
Asset/(Liability) Notional or Notional or
(unaudited) Fair Principal Fair Principal
(millions of dollars) Value(1) Amount Value(1) Amount
----------------------------------------------------------------------------
----------------------------------------------------------------------------
U.S. dollar cross-currency swaps
(maturing 2011 to 2018) 19 US 3,700 179 US 2,800
U.S. dollar forward foreign
exchange contracts
(maturing 2011 to 2012) (39) US 725 2 US 100
-------------------------------------------
(20) US 4,425 181 US 2,900
-------------------------------------------
-------------------------------------------
(1) Fair values equal carrying values.
The carrying and fair values of non-derivative financial instruments were as follows:
Non-Derivative Financial Instruments Summary
September 30, 2011 December 31, 2010
------------------ ------------------
(unaudited) Carrying Fair Carrying Fair
(millions of dollars) Amount Value Amount Value
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Financial Assets(1)
Cash and cash equivalents 596 596 764 764
Accounts receivable and other(2)(3) 1,518 1,563 1,555 1,595
Available-for-sale assets(2) 38 38 20 20
--------------------------------------
2,152 2,197 2,339 2,379
--------------------------------------
--------------------------------------
Financial Liabilities(1)(3)
Notes payable 1,865 1,865 2,092 2,092
Accounts payable and deferred
amounts(4) 1,253 1,253 1,436 1,436
Accrued interest 348 348 367 367
Long-term debt 18,110 22,588 17,922 21,523
Long-term debt of joint ventures 855 980 866 971
Junior subordinated notes 1,030 1,034 985 992
--------------------------------------
23,461 28,068 23,668 27,381
--------------------------------------
--------------------------------------
(1) Consolidated Net Income in the three and nine months ended September 30,
2011 included losses of $7 million and $18 million, respectively,
(2010 -losses of $2 million and $11 million, respectively), for fair
value adjustments related to interest rate swap agreements on US$350
million (2010 - US$150 million) of Long Term Debt. There were no other
unrealized gains or losses from fair value adjustments to the
non-derivative financial instruments.
(2) At September 30, 2011, the Consolidated Balance Sheet included
financial assets of $1,191 million (December 31, 2010 - $1,271 million)
in Accounts Receivable, $47 million (December 31, 2010 - $40 million)
in Other Current Assets and $318 million (December 31, 2010 -
$264 million) in Intangibles and Other Assets.
(3) Recorded at amortized cost, except for the US$350 million (December 31,
2010 - US$250 million) of Long-Term Debt that is adjusted to fair value.
(4) At September 30, 2011, the Consolidated Balance Sheet included financial
liabilities of $1,224 million (December 31, 2010 - $1,406 million) in
Accounts Payable and $29 million (December 31, 2010 - $30 million) in
Deferred Amounts.
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:
September 30, 2011
(unaudited)
(all amounts in millions
unless otherwise Natural Foreign
indicated) Power Gas Exchange Interest
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Derivative Financial
Instruments
Held for Trading(1)
Fair Values(2)
Assets $ 133 $ 160 $ - $ 26
Liabilities $ (107) $ (195) $ (46) $ (26)
Notional Values
Volumes(3)
Purchases 21,147 136 - -
Sales 25,884 109 - -
Canadian dollars - - - 684
U.S. dollars - - US 1,366 US 250
Cross-currency - - 47/US 37 -
Net unrealized
gains/(losses) in the
period(4)
Three months ended
September 30, 2011 $ 5 $ (13) $ (41) $ 1
Nine months ended
September 30, 2011 $ 8 $ (39) $ (41) $ 1
Net realized gains/(losses)
in the period(4)
Three months ended
September 30, 2011 $ 21 $ (20) $ (7) $ 3
Nine months ended
September 30, 2011 $ 32 $ (61) $ 26 $ 8
Maturity dates 2011-2018 2011-2016 2011-2012 2012-2016
Derivative Financial
Instruments
in Hedging
Relationships(5)(6)
Fair Values(2)
Assets $ 46 $ 7 $ 5 $ 18
Liabilities $ (182) $ (17) $ (36) $ (8)
Notional Values
Volumes(3)
Purchases 17,728 10 - -
Sales 8,732 - - -
U.S. dollars
- - US 104 US 1,000
Cross-currency - - 136/US 100 -
Net realized losses in the
period(4)
Three months ended
September 30, 2011 $ (54) $ (6) $ - $ (4)
Nine months ended
September 30, 2011 $ (100) $ (14) $ - $ (13)
Maturity dates 2011-2017 2011-2013 2013-2014 2011-2015
------------------------------------------------
------------------------------------------------
(1) All derivative financial instruments in the held-for-trading
classification have been entered into for risk management purposes and
are subject to the Company's risk management strategies, policies and
limits. These include derivatives that have not been designated as
hedges or do not qualify for hedge accounting treatment but have been
entered into as economic hedges to manage the Company's exposures to
market risk.
(2) Fair values equal carrying values.
(3) Volumes for power and natural gas derivatives are in GWh and Bcf,
respectively.
(4) Realized and unrealized gains and losses on financial held-for-trading
derivatives used to purchase and sell power and natural gas are included
on a net basis in Revenues. Realized and unrealized gains and losses on
interest rate and foreign exchange derivative financial instruments
held-for-trading are included in Interest Expense and Interest Income
and Other, respectively. The effective portion of unrealized gains and
losses on derivative financial instruments in cash flow hedging
relationships is initially recognized in Other Comprehensive Income and
reclassified to Revenues, Interest Expense and Interest Income and
Other, as appropriate, as the original hedged item settles.
(5) All hedging relationships are designated as cash flow hedges except for
interest rate derivative financial instruments designated as fair value
hedges with a fair value of $18 million and a notional amount of US$350
million at September 30, 2011. Net realized gains on fair value hedges
for the three and nine months ended September 30, 2011 were $1 million
and $5 million, respectively, and were included in Interest Expense. In
the three and nine months ended September 30, 2011, the Company did not
record any amounts in Net Income related to ineffectiveness for fair
value hedges.
(6) For the three and nine months ended September 30, 2011, Net Income
included gains of $1 million and nil, respectively, for changes in the
fair value of power and natural gas cash flow hedges that were
ineffective in offsetting the change in fair value of their related
underlying positions. For the three and nine months ended September 30,
2011, there were no gains or losses included in Net Income for
discontinued cash flow hedges. No amounts have been excluded from the
assessment of hedge effectiveness.
2010
(unaudited)
(all amounts in millions
unless otherwise Natural Foreign
indicated) Power Gas Exchange Interest
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Derivative Financial
Instruments
Held for Trading
Fair Values(1)(2)
Assets $ 169 $ 144 $ 8 $ 20
Liabilities $ (129) $ (173) $ (14) $ (21)
Notional Values(2)
Volumes(3)
Purchases 15,610 158 - -
Sales 18,114 96 - -
Canadian dollars - - - 736
U.S. dollars - - US 1,479 US 250
Cross-currency - - 47/US 37 -
Net unrealized
(losses)/gains in the
period(4)
Three months ended
September 30, 2010 $ (1) $ 4 $ 10 $ 50
Nine months ended
September 30, 2010 $ (27) $ 9 $ (1) $ 33
Net realized
gains/(losses) in the
period(4)
Three months ended
September 30, 2010 $ 13 $ (10) $ 6 $ (54)
Nine months ended
September 30, 2010 $ 50 $ (39) $ 8 $ (64)
Maturity dates(2) 2011-2015 2011-2015 2011-2012 2011-2016
Derivative Financial
Instruments
in Hedging
Relationships(5)(6)
Fair Values(1)(2)
Assets $ 112 $ 5 $ - $ 8
Liabilities $ (186) $ (19) $ (51) $ (26)
Notional Values(2)
Volumes(3)
Purchases 16,071 17 - -
Sales 10,498 - - -
U.S. dollars - - US 120 US 1,125
Cross-currency - - 136/US 100 -
Net realized losses in
the period(4)
Three months ended
September 30, 2010 $ 37 $ (19) $ - $ (7)
Nine months ended
September 30, 2010 $ (6) $ (28) $ - $ (26)
Maturity dates(2) 2011-2015 2011-2013 2011-2014 2011-2015
---------------------------------------------------
---------------------------------------------------
(1) Fair values equal carrying values.
(2) As at December 31, 2010.
(3) Volumes for power and natural gas derivatives are in GWh and Bcf,
respectively.
(4) Realized and unrealized gains and losses on financial held-for-trading
derivatives used to purchase and sell power and natural gas are included
on a net basis in Revenues. Realized and unrealized gains and losses on
interest rate and foreign exchange derivative financial instruments held
for trading are included in Interest Expense and Interest Income and
Other, respectively. The effective portion of unrealized gains and
losses on derivative financial instruments in cash flow hedging
relationships is initially recognized in Other Comprehensive Income and
reclassified to Revenues, Interest Expense and Interest Income and
Other, as appropriate, as the original hedged item settles.
(5) All hedging relationships are designated as cash flow hedges except for
interest rate derivative financial instruments designated as fair value
hedges with a fair value of $8 million and a notional amount of US$250
million at December 31, 2010. Net realized gains on fair value hedges
for the three and nine months ended September 30, 2010 were $1 million
and $3 million, respectively, and were included in Interest Expense. In
the three and nine months ended September 30, 2010, the Company did not
record any amounts in Net Income related to ineffectiveness for fair
value hedges.
(6) Losses included in Net income for the three and nine months ended
September 30, 2010 were nil and $1 million, respectively, for changes in
the fair value of power and natural gas cash flow hedges that were
ineffective in offsetting the change in fair value of their related
underlying positions. For the three and nine months ended September 30,
2010, there were no gains or losses included in Net Income for
discontinued cash flow hedges. No amounts were excluded from the
assessment of hedge effectiveness.
Balance Sheet Presentation of Derivative Financial Instruments
The fair value of the derivative financial instruments in the Company's Balance Sheet was as follows:
(unaudited)
(millions of dollars) September 30, 2011 December 31, 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Current
Other current assets 319 273
Accounts payable (405) (337)
Long-term
Intangibles and other assets 183 374
Deferred amounts (339) (282)
-------------------------------------
-------------------------------------
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 September 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 September 30, 2011.
During the quarter ended September 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 nine months 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 and resolution of the Sundance A PPA dispute, 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.
In September 2011, the NEB issued its decision on the application whereby it approved the interim tolls as final, including TransCanada's proposal to carry forward any revenue variances into the determination of 2012 tolls. However, the NEB determined that TransCanada's inclusion of certain elements included in the proposed 2011 revenue requirement will be examined with TransCanada's 2012-2013 Tolls Application before a final decision is rendered on the 2011 revenue requirement.
2012-2013 Tolls Application
On September 1, 2011, TransCanada filed a comprehensive application with the NEB to change the business structure and the terms and conditions of service for the Canadian Mainline, including addressing tolls for 2012 and 2013. The application includes components that affect the Alberta System and Foothills (Restructuring Proposal). The application is intended to address the long-term economic viability of the Canadian Mainline and improve the competitiveness of TransCanada's regulated Canadian natural gas transportation infrastructure and the Western Canada Sedimentary Basin (WCSB). On October 31, 2011, TransCanada filed supplementary information on cost of service and the proposed tolls for 2012 and 2013. The application results in a 2012 Nova Inventory Transfer System to Dawn toll of $1.29 per gigajoule (GJ) which is $0.80 per GJ or 38 per cent lower than the comparable tolls charged in 2011.
In addition, on October 31, 2011, TransCanada filed for interim 2012 tolls on the Alberta System and annual tolls on Foothills to be effective January 1, 2012. These applications are based on the provisions of the current settlements in place for these systems. An application for interim tolls for 2012 on the Canadian Mainline is expected to be filed in mid-November 2011. Final tolls for 2012 on the Canadian Mainline and Alberta System will be determined following the NEB's decision on the Restructuring Proposal.
In response to the application, the NEB held a Pre-hearing Planning Conference on October 12, 2011 for interested parties to provide suggestions on sequencing of the hearing, procedural steps required and the timing of these steps. Based on comments received, the NEB decided that it will hear all of TransCanada's Application, including cost of capital, in one proceeding before issuing a decision on the Application. The oral portion of the hearing will commence on June 4, 2012 in Calgary, Alberta.
Marcellus Facilities Expansion
In July, 2011, TransCanada filed an application with the NEB to construct approximately $130 million of new facilities required to transport Marcellus shale gas to eastern markets. The NEB rejected the filing in October 2011. TransCanada is considering the guidance provided by the NEB in its rejection of the application and expects to re-file an application in the near future.
Alberta System
2011 Final Tolls
In May 2011, TransCanada filed for final 2011 tolls that reflect the provisions of the Alberta System 2010 - 2012 Revenue Requirement Settlement and commercial integration of the ATCO Pipelines system. In August 2011, the NEB approved the Alberta System application for final 2011 tolls but held tolls for the last five months of the year as interim pending TransCanada's response to identify a new integration effective date. On August 30, 2011, TransCanada filed a revised integration effective date of October 1, 2011 which, along with final tolls for the last five months of the year, was approved on September 8, 2011. Integration was effected on October 1, 2011.
Expansion Projects
The Alberta System's Horn River natural gas pipeline project was approved by the NEB in January 2011 and commenced construction in March 2011, with a targeted completion date of second quarter 2012 and an estimated capital cost of $275 million. In addition, the Company has executed an agreement to extend the Horn River pipeline by approximately 100 kilometres (km) (62 miles) at an estimated capital cost of $230 million. As a result of the extension, additional contractual commitments of 100 mmcf/d are expected to commence in 2014 with volumes increasing to 300 mmcf/d by 2020. An application requesting approval to construct and operate this extension was filed with the NEB on October 14, 2011. The total currently contracted volumes for Horn River, including the extension, are expected to be approximately 900 mmcf/d by 2020.
On June 24, 2011, the NEB approved the construction and operation of a 24 km (15 mile) extension of the Groundbirch natural gas pipeline. Construction commenced in August 2011 with an expected in-service date of April 1, 2012 and an estimated capital cost of approximately $60 million. The project is required to serve 250 mmcf/d of new transportation contracts. TransCanada continues to advance further pipeline development in British Columbia (B.C.) and Alberta to transport new natural gas supplies. The Company has filed several applications with the NEB requesting approval of further expansions of the Alberta System to accommodate requests for additional natural gas transmission service throughout the northwest and northeast portions of the WCSB. As at September 30, 2011, including the projects previously discussed, the NEB had approved natural gas pipeline projects with capital costs of approximately $750 million. Further pipeline projects with a total capital cost of approximately $640 million are awaiting NEB decision.
Ongoing business with Western Canadian producers have resulted in new contracts from both the Montney and Horn River shale gas formations. Including the projects discussed above, TransCanada has firm commitments to transport 2.9 Bcf/d from northwest Alberta and northeast B.C. by 2014.
Guadalajara
TransCanada's US$360 million, 307 km (191 mile) Guadalajara natural gas pipeline went into service on June 15, 2011. All of the pipeline's utilized capacity is under a 25-year contract with Comision Federal de Electricidad (CFE), Mexico's state-owned electric company. TransCanada and the CFE have agreed to add a US$60 million compressor station to the pipeline that is expected to be operational in early 2013.
PipeLines LP
On May 3, 2011, the Company completed the sale of a 25 per cent interest in each of Gas Transmission Northwest LLC (GTN LLC) and Bison Pipeline LLC (Bison LLC) to PipeLines LP for an aggregate purchase price of US$605 million, subject to closing adjustments, which included US$81 million of long-term debt, or 25 per cent of GTN LLC debt outstanding. GTN LLC and Bison LLC own the GTN and Bison natural gas pipelines, respectively.
On May 3, 2011, PipeLines LP completed an underwritten public offering of 7,245,000 common units, including 945,000 common units purchased by the underwriters upon full exercise of an over-allotment option, at US$47.58 per unit. Gross proceeds of approximately US$345 million from this offering were used to partially fund the acquisition. The acquisition was also funded by draws of US$61 million on PipeLines LP's bridge loan facility and of US$125 million on its US$250 million senior revolving credit facility.
As part of this offering, TransCanada made a capital contribution of approximately US$7 million to maintain its two per cent general partnership interest in PipeLines LP and did not purchase any other units. As a result of the common units offering, TransCanada's ownership in PipeLines LP decreased from 38.2 per cent to 33.3 per cent and an after-tax dilution gain of $30 million ($50 million pre-tax) was recorded in Contributed Surplus.
Oil Pipelines
Keystone
On August 26, 2011, the U.S. Department of State (DOS), the lead agency for U.S. federal regulatory approvals, released its Final Environmental Impact Statement (FEIS) for TransCanada's Keystone U.S. Gulf Coast Expansion (Keystone XL). The FEIS found that the project would have limited environmental impact and the proposed route would have the least environmental impact of the alternatives considered.
Following the issuance of the FEIS, the DOS initiated a 90 day National Interest Determination (NID) process. As part of the NID process, the DOS held nine public comment meetings in September and October and will consult with other U.S. federal agencies to determine if granting approval for Keystone XL is in the national interest of the U.S. The NID period concludes on November 25, 2011 and a decision on the Presidential Permit is expected by year end.
The capital cost of Keystone XL is estimated to be US$7 billion with US$1.9 billion having been invested as at September 30, 2011. The remainder is expected to be invested between now and the in-service date, which is expected in 2013. Capital costs related to the construction of Keystone XL are subject to capital cost risk and reward sharing mechanisms with Keystone's long-term committed shippers.
In August 2011, TransCanada launched two binding open seasons both of which closed October 17, 2011. The first offered capacity to attract long-term firm service contracts for crude oil transportation from Hardisty, Alberta to Houston, Texas (Houston Lateral). The approximate US$600 million Houston Lateral project would involve the expansion of capacity through the addition of pump stations and the construction of an approximate 80 km (50 mile) pipeline extension from the proposed Keystone XL System. The proposed project would double the U.S. Gulf Coast refining market capacity accessible from the Keystone Pipeline System. TransCanada is currently analyzing the results of the open season. Pending sufficient shipper commitments and regulatory approvals, the Houston Lateral is expected to be operational in 2014.
The second binding open season offered capacity to attract additional long-term firm service contracts for crude oil transportation from Cushing Oklahoma to Port Arthur or Houston, Texas (Cushing Marketlink). The approximate US$50 million Cushing Marketlink project uses a portion of the facilities that form part of Keystone XL including the Houston Lateral. TransCanada is currently analyzing the results of the open season. Pending regulatory approvals, Cushing Marketlink is expected to begin shipping crude oil to Port Arthur in 2013 and to Houston in 2014.
The U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) issued a corrective action order on Keystone on June 3, 2011 as a result of two above-ground incidents in second quarter 2011 at pump stations in North Dakota and Kansas, both of which involved the release of small amounts of crude oil. The corrective action order required TransCanada to develop and submit a written re-start plan which included steps to facilitate the proper clean-up, investigation, and system improvements and modifications. The restart plan was approved by PHMSA on June 4, 2011. In July and August 2011, work was performed on the Keystone system to improve system reliability. The work was completed as planned and resulted in reduced pipeline capacity during those two months, however, it did not have a significant impact on EBIT.
Energy
Sundance A
The dispute arising out of TransAlta Corporation's claims of force majeure and economic destruction for the Sundance A facility will be heard through a single binding arbitration process. The arbitration panel has scheduled a hearing in March and April 2012 for these claims. Assuming the hearing concludes within the time allotted, TransCanada expects to receive a decision in mid-2012.
TransCanada does not believe the owner's claims meet the tests of force majeure or destruction as specified in the PPA and therefore continues to record revenues and costs as though this event is an interruption of supply in accordance with the terms of the PPA. For the nine months ended September 30, 2011, TransCanada has recorded $99 million of EBITDA related to the Sundance A PPA. Ultimate recovery of this amount will depend upon the outcome of the arbitration process.
Ravenswood
Since July 2011, spot prices for capacity sales in the New York Zone J market have settled at materially lower levels than prior periods as a result of the manner in which the New York Independent System Operator (NYISO) has applied pricing rules for a new power plant that recently began service in this market. TransCanada believes that this application of pricing rules by the NYISO is in direct contravention of a series of Federal Energy Regulatory Commission (FERC) orders which direct how new entrant capacity is to be treated for the purpose of determining capacity prices. TransCanada and other parties have filed formal complaints with FERC that are currently pending. The outcome of the complaints and longer-term impact that this development may have on Ravenswood is unknown.
During third quarter, the demand curve reset process was completed following FERC's acceptance of the NYISO's September 22, 2011 compliance filing. This resulted in increased demand curve rates that apply going forward to 2014 and positively impacted capacity prices in October. The impact on winter 2011/2012 capacity prices is expected to be negligible due to excess capacity in the winter months, exacerbated by the above noted NYISO actions relative to new unit pricing.
Oakville
In October 2010, the Government of Ontario announced that it would not proceed with the $1.2 billion Oakville generating station. In third quarter 2011, TransCanada, the Government of Ontario and the Ontario Power Authority reached formal agreement to use an arbitration process to settle the dispute resulting from termination of a 20-year Clean Energy Supply contract with the Ontario Power Authority, which TransCanada had been previously awarded. Pursuant to the arbitration agreement, the parties remain in discussions. TransCanada expects to be appropriately compensated for the economic consequences associated with the contract's termination.
Bruce Power
Bruce Power continues to progress through the commissioning of Units 1 and 2. Fueling of Unit 1 will commence in November 2011 and the final phases of commissioning for Unit 2 are planned to begin in fourth quarter 2011.
Subject to regulatory approval, Bruce Power expects to achieve first synchronization of Unit 2 to the electrical grid early in first quarter 2012 and commence commercial operation in late first quarter 2012. Bruce Power expects the first synchronization of Unit 1 to the electrical grid in second quarter 2012 and commercial operations to occur during third quarter 2012. TransCanada's share of the total capital cost is expected to be approximately $2.4 billion, of which $2.2 billion was incurred as of September 30, 2011.
Zephyr
In June 2011, Zephyr terminated the precedent agreements with its potential shippers as the parties were unable to resolve key commercial issues. In July 2011, one of Zephyr's potential shippers exercised its contractual rights to acquire 100 per cent of the Zephyr project from TransCanada.
Becancour
In June 2011, Hydro-Quebec notified TransCanada it would exercise its option to extend the agreement to suspend all electricity generation from the Becancour power plant throughout 2012. Under the original agreement signed in June 2009, Hydro-Quebec has the option, subject to certain conditions, to extend the suspension on an annual basis until such time as regional electricity demand levels recover. TransCanada will continue to receive payments under the agreement similar to those that would have been received under the normal course of operation.
Coolidge
The US$500 million Coolidge generating station went into service on May 1, 2011. Power from the 575 MW simple-cycle, natural gas-fired peaking facility located near Phoenix, Arizona is sold to the Salt River Project Agricultural Improvement and Power District under a 20-year PPA.
Cartier Wind
Construction continues on the five-stage, 590 MW Cartier Wind project in Quebec. As at September 30, 2011, 100 per cent of the wind turbines at Gros-Morne phase 1 and approximately 80 per cent of the wind turbines at Montagne-Seche had been erected. The 101 MW first phase of the Gros-Morne and 58 MW Montagne-Seche wind farm projects are expected to be operational in December 2011. The 111 MW Gros-Morne phase two is expected to be operational in December 2012. These are the fourth and fifth Quebec-based wind farms of Cartier Wind, which are 62 per cent owned by TransCanada. All of the power produced by Cartier Wind is sold under a 20-year PPA to Hydro-Quebec.
Share Information
At October 25, 2011, TransCanada had 703 million issued and outstanding common shares, and had 22 million Series 1, 14 million Series 3 and 14 million Series 5 issued and outstanding first preferred shares that are convertible to 22 million Series 2, 14 million Series 4 and 14 million Series 6 preferred shares, respectively. In addition, there were eight million outstanding options to purchase common shares, of which six million were exercisable as at October 25, 2011.
Selected Quarterly Consolidated Financial Data(1)
2011 2010 2009
-------------------------------------------------------------
-------------------------------------------------------------
(millions of
dollars except
per share
amounts) Third Second First Fourth Third Second First Fourth
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenues 2,393 2,143 2,243 2,057 2,129 1,923 1,955 1,986
Net income
attributable
to controlling
interests 397 367 429 283 391 295 303 387
Share
Statistics
Net income per
common share -
Basic and
Diluted $0.55 $0.50 $0.59 $0.39 $0.54 $0.41 $0.43 $0.56
Dividend
declared per
common share $0.42 $0.42 $0.42 $0.40 $0.40 $0.40 $0.40 $0.38
-------------------------------------------------------------
-------------------------------------------------------------
(1) The selected quarterly consolidated financial data has been prepared in
accordance with Canadian GAAP and is presented in Canadian dollars.
Factors Affecting Quarterly Financial Information
In Natural Gas Pipelines, which consists primarily of the Company's investments in regulated natural gas pipelines and regulated natural gas storage facilities, annual revenues, EBIT and net income fluctuate over the long term based on regulators' decisions and negotiated settlements with shippers. Generally, quarter-over-quarter revenues and net income during any particular fiscal year remain relatively stable with fluctuations resulting from adjustments being recorded due to regulatory decisions and negotiated settlements with shippers, seasonal fluctuations in short-term throughput volumes on U.S. pipelines, acquisitions and divestitures, and developments outside of the normal course of operations.
In Oil Pipelines, which consists of the Company's investment in the Keystone crude oil pipeline, annual revenues are based on contracted crude oil transportation and uncommitted spot transportation. Quarter-over-quarter revenues, EBIT and net income during any particular fiscal year remain relatively stable with fluctuations resulting from planned and unplanned outages, and changes in the amount of spot volumes transported and the associated rate charged. Spot volumes transported are affected by customer demand, market pricing, planned and unplanned outages of refineries, terminals and pipeline facilities, and developments outside of the normal course of operations.
In Energy, which consists primarily of the Company's investments in electrical power generation plants and non-regulated natural gas storage facilities, quarter-over-quarter revenues, EBIT and net income are affected by seasonal weather conditions, customer demand, market prices, capacity prices, planned and unplanned plant outages, acquisitions and divestitures, certain fair value adjustments and developments outside of the normal course of operations.
Significant developments that affected the last eight quarters' EBIT and Net Income are as follows:
-- Third Quarter 2011, Energy's EBIT included the positive impact of higher
prices for Western Power. EBIT included net unrealized losses of $47
million pre-tax ($33 million after tax) resulting from changes in the
fair value of proprietary natural gas inventory in storage and certain
risk management activities.
-- Second Quarter 2011, Natural Gas Pipelines' EBIT included incremental
earnings from Guadalajara, which was placed in service in June 2011.
Energy's EBIT included incremental earnings from Coolidge, which was
placed in service in May 2011. EBIT included net unrealized losses of $5
million pre-tax ($4 million after tax) resulting from changes in the
fair value of proprietary natural gas inventory in storage and certain
risk management activities.
-- First Quarter 2011, Natural Gas Pipelines' EBIT included incremental
earnings from Bison, which was placed in service in January 2011. Oil
Pipelines began recording EBIT for the Wood River/Patoka and Cushing
Extension sections of Keystone in February 2011. EBIT included net
unrealized losses of $17 million pre-tax ($10 million after tax)
resulting from changes in the fair value of proprietary natural gas
inventory in storage and certain risk management activities.
-- Fourth Quarter 2010, Natural Gas Pipelines' EBIT decreased as a result
of recording a $146 million pre-tax ($127 million after tax) valuation
provision for advances to the APG for the MGP. Energy's EBIT included
contributions from the second phase of Kibby Wind, which was placed in
service in October 2010, and net unrealized gains of $22 million pre-tax
($12 million after tax) resulting from changes in the fair value of
proprietary natural gas inventory in storage and certain risk management
activities.
-- Third Quarter 2010, Natural Gas Pipelines' EBIT increased as a result of
recording nine months of incremental earnings related to the Alberta
System 2010 - 2012 Revenue Requirement Settlement, which resulted in a
$33 million increase to Net Income. Energy's EBIT included contributions
from Halton Hills, which was placed in service in September 2010, and
net unrealized gains of $4 million pre-tax ($3 million after tax)
resulting from changes in the fair value of proprietary natural gas
inventory in storage and certain risk management activities.
-- Second Quarter 2010, Energy's EBIT included net unrealized gains of $15
million pre-tax ($10 million after tax) resulting from changes in the
fair value of proprietary natural gas inventory in storage and certain
risk management activities. Net Income reflected a decrease of $58
million after tax due to losses in 2010 compared to gains in 2009 for
interest rate and foreign exchange rate derivatives that did not qualify
as hedges for accounting purposes and the translation of U.S. dollar-
denominated working capital balances.
-- First Quarter 2010, Energy's EBIT included net unrealized losses of $49
million pre-tax ($32 million after tax) resulting from changes in the
fair value of proprietary natural gas inventory in storage and certain
risk management activities.
-- Fourth Quarter 2009, Natural Gas Pipelines EBIT included a dilution gain
of $29 million pre-tax ($18 million after tax) resulting from
TransCanada's reduced ownership interest in PipeLines LP, which was
caused by PipeLines LP's issue of common units to the public. Energy's
EBIT included net unrealized gains of $7 million pre-tax ($5 million
after tax) resulting from changes in the fair value of proprietary
natural gas inventory in storage and certain risk management activities.
Net Income included $30 million of favourable income tax adjustments
resulting from reductions in the Province of Ontario's corporate income
tax rates.
Consolidated Income
(unaudited) Three months ended Nine months ended
(millions of dollars except September 30 September 30
per share amounts) 2011 2010 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenues 2,393 2,129 6,779 6,007
--------------------------------------
Operating and Other Expenses
Plant operating costs and other 875 817 2,456 2,328
Commodity purchases resold 270 301 732 773
Depreciation and amortization 389 326 1,138 1,010
--------------------------------------
1,534 1,444 4,326 4,111
--------------------------------------
Financial Charges/(Income)
Interest expense 240 159 686 528
Interest expense of joint ventures 13 13 40 44
Interest income and other 44 (27) (12) (33)
--------------------------------------
297 145 714 539
--------------------------------------
Income before Income Taxes 562 540 1,739 1,357
--------------------------------------
Income Taxes Expense
Current 51 (49) 197 (167)
Future 82 169 253 453
--------------------------------------
133 120 450 286
--------------------------------------
Net Income 429 420 1,289 1,071
Net Income Attributable to Non-
Controlling Interests 32 29 96 82
--------------------------------------
Net Income Attributable to Controlling
Interests 397 391 1,193 989
Preferred Share Dividends 13 14 41 31
--------------------------------------
Net Income Attributable to Common
Shares 384 377 1,152 958
--------------------------------------
--------------------------------------
Net Income per Common Share
Basic and Diluted $ 0.55 $ 0.54 $ 1.64 $ 1.39
--------------------------------------
--------------------------------------
Average Common Shares Outstanding -
Basic (millions) 703 692 701 689
--------------------------------------
--------------------------------------
Average Common Shares Outstanding -
Diluted (millions) 704 693 702 690
--------------------------------------
--------------------------------------
See accompanying notes to the consolidated financial statements.
Consolidated Comprehensive Income
Three months ended Nine months ended
(unaudited) September 30 September 30
(millions of dollars) 2011 2010 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net Income 429 420 1,289 1,071
----------------------------------------
Other Comprehensive Income/(Loss),
Net of Income Taxes
Change in foreign currency
translation gains and losses on
investments in foreign
operations(1) 344 (127) 216 (47)
Change in gains and losses on
financial derivatives to hedge the
net investments in foreign
operations(2) (213) 47 (141) 27
Change in gains and losses on
derivative instruments designated
as cash flow hedges(3) (17) (56) (109) (176)
Reclassification to Net Income of
gains and losses on derivative
instruments designated as cash flow
hedges pertaining to prior
periods(4) 41 19 103 13
----------------------------------------
Other Comprehensive Income/(Loss) 155 (117) 69 (183)
----------------------------------------
Comprehensive Income 584 303 1,358 888
Comprehensive Income Attributable to
Non-Controlling Interests 32 36 104 86
----------------------------------------
Comprehensive Income Attributable to
Controlling Interests 552 267 1,254 802
Preferred Share Dividends 13 14 41 31
----------------------------------------
Comprehensive Income Attributable to
Common Shares 539 253 1,213 771
----------------------------------------
----------------------------------------
(1) Net of income tax recovery of $97 million and $57 million for the three
and nine months ended September 30, 2011, respectively (2010 - expense
of $36 million and $21 million, respectively).
(2) Net of income tax recovery of $78 million and $51 million for the three
and nine months ended September 30, 2011, respectively (2010 - expense
of $19 million and $11 million, respectively).
(3) Net of income tax recovery of $9 million and $48 million for the three
and nine months ended September 30, 2011, respectively (2010 - recovery
of $33 million and $117 million, respectively).
(4) Net of income tax expense of $19 million and $53 million for the three
and nine months ended September 30, 2011, respectively (2010 - expense
of $4 million and $21 million, respectively).
See accompanying notes to the consolidated financial statements.
Consolidated Cash Flows
Three months ended Nine months ended
(unaudited) September 30 September 30
(millions of dollars) 2011 2010 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Cash Generated From Operations
Net income 429 420 1,289 1,071
Depreciation and amortization 389 326 1,138 1,010
Future income taxes 82 169 253 453
Employee future benefits funding
less than/(in excess of) expense 10 8 2 (36)
Other 61 (62) 100 21
-----------------------------------------
971 861 2,782 2,519
Decrease/(increase) in operating
working capital 94 (70) 192 (271)
-----------------------------------------
Net cash provided by operations 1,065 791 2,974 2,248
-----------------------------------------
Investing Activities
Capital expenditures (696) (1,297) (2,135) (3,565)
Deferred amounts and other 66 (221) 76 (430)
-----------------------------------------
Net cash used in investing
activities (630) (1,518) (2,059) (3,995)
-----------------------------------------
Financing Activities
Dividends on common and preferred
shares (308) (184) (706) (567)
Distributions paid to non-
controlling interests (33) (28) (87) (83)
Notes payable issued/(repaid), net 160 (44) (255) (53)
Long-term debt issued, net of issue
costs 54 1,021 573 2,337
Repayment of long-term debt (206) (146) (946) (429)
Long-term debt of joint ventures
issued 15 86 46 164
Repayment of long-term debt of
joint ventures (33) (93) (82) (232)
Common shares issued 14 6 39 20
Partnership units of subsidiary
issued, net of issue costs - - 321 -
Preferred shares issued, net of
issue costs - - - 679
-----------------------------------------
Net cash (used in)/provided by
financing activities (337) 618 (1,097) 1,836
-----------------------------------------
Effect of Foreign Exchange Rate
Changes on Cash and Cash
Equivalents 30 (8) 14 8
-----------------------------------------
Increase/(Decrease) in Cash and
Cash Equivalents 128 (117) (168) 97
Cash and Cash Equivalents
Beginning of period 468 1,211 764 997
-----------------------------------------
Cash and Cash Equivalents
End of period 596 1,094 596 1,094
-----------------------------------------
-----------------------------------------
Supplementary Cash Flow Information
Income taxes (refunded)/paid, net (152) (26) (111) 17
Interest paid 251 215 736 573
-----------------------------------------
-----------------------------------------
See accompanying notes to the consolidated financial statements.
Consolidated Balance Sheet
(unaudited)
September December
(millions of dollars) 30, 2011 31, 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
ASSETS
Current Assets
Cash and cash equivalents 596 764
Accounts receivable 1,191 1,271
Inventories 428 425
Other 793 777
----------------------
3,008 3,237
Plant, Property and Equipment 37,746 36,244
Goodwill 3,729 3,570
Regulatory Assets 1,419 1,512
Intangibles and Other Assets 1,842 2,026
----------------------
47,744 46,589
----------------------
----------------------
LIABILITIES
Current Liabilities
Notes payable 1,865 2,092
Accounts payable 2,231 2,243
Accrued interest 348 367
Current portion of long-term debt 1,083 894
Current portion of long-term debt of joint ventures 106 65
----------------------
5,633 5,661
Regulatory Liabilities 292 314
Deferred Amounts 779 694
Future Income Taxes 3,409 3,222
Long-Term Debt 17,027 17,028
Long-Term Debt of Joint Ventures 749 801
Junior Subordinated Notes 1,030 985
----------------------
28,919 28,705
----------------------
EQUITY
Controlling interests 17,329 16,727
Non-controlling interests 1,496 1,157
----------------------
18,825 17,884
----------------------
47,744 46,589
----------------------
----------------------
See accompanying notes to the consolidated financial statements.
Consolidated Accumulated Other Comprehensive (Loss)/Income
Currency Cash Flow
(unaudited) Translation Hedges and
(millions of dollars) Adjustments Other Total
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Balance at December 31, 2010 (683) (194) (877)
Change in foreign currency
translation gains and losses
on investments in foreign
operations(1) 216 - 216
Change in gains and losses on
financial derivatives to hedge
the net investments in foreign
operations(2) (141) - (141)
Change in gains and losses on
derivative instruments
designated as cash flow
hedges(3) - (109) (109)
Reclassification to Net Income
of gains and losses on
derivative instruments
designated as cash flow hedges
pertaining to prior
periods(4)(5) - 95 95
---------------------------------------------
Balance at September 30, 2011 (608) (208) (816)
---------------------------------------------
---------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Balance at December 31, 2009 (592) (40) (632)
Change in foreign currency
translation gains and losses
on investments in foreign
operations(1) (47) - (47)
Change in gains and losses on
financial derivatives to hedge
the net investments in foreign
operations(2) 27 - 27
Changes in gains and losses on
derivative instruments
designated as cash flow
hedges(3) - (173) (173)
Reclassification to Net Income
of gains and losses on
derivative instruments
designated as cash flow hedges
pertaining to prior periods(4) - 6 6
---------------------------------------------
Balance at September 30, 2010 (612) (207) (819)
---------------------------------------------
---------------------------------------------
(1) Net of income tax recovery of $57 million for the nine months ended
September 30, 2011 (2010 - expense of $21 million).
(2) Net of income tax recovery of $51 million for the nine months ended
September 30, 2011 (2010 - expense of $11 million).
(3) Net of income tax recovery of $48 million for the nine months ended
September 30, 2011 (2010 - recovery of $117 million).
(4) Net of income tax expense of $53 million for the nine months ended
September 30, 2011 (2010 - expense of $21 million).
(5) Losses related to cash flow hedges reported in Accumulated Other
Comprehensive (Loss)/Income and expected to be reclassified to Net
Income in the next 12 months are estimated to be $101 million ($65
million, net of tax). These estimates assume constant commodity prices,
interest rates and foreign exchange rates over time, however, the
amounts reclassified will vary based on the actual value of these
factors at the date of settlement.
See accompanying notes to the consolidated financial statements.
Consolidated Equity
Nine months ended
(unaudited) September 30
(millions of dollars) 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Common Shares
Balance at beginning of period 11,745 11,338
Shares issued under dividend reinvestment
plan 202 271
Shares issued on exercise of stock options 40 20
------------------------------
Balance at end of period 11,987 11,629
------------------------------
Preferred Shares
Balance at beginning of period 1,224 539
Shares issued under public offering, net of
issue costs - 685
------------------------------
Balance at end of period 1,224 1,224
------------------------------
Contributed Surplus
Balance at beginning of period 331 328
Issuance of stock options, net of exercises 1 2
Dilution gain from PipeLines LP units issued 30 -
------------------------------
Balance at end of period 362 330
------------------------------
Retained Earnings
Balance at beginning of period 4,304 4,186
Net income attributable to controlling
interests 1,193 989
Common share dividends (884) (829)
Preferred share dividends (41) (31)
------------------------------
Balance at end of period 4,572 4,315
------------------------------
Accumulated Other Comprehensive (Loss)/Income
Balance at beginning of period (877) (632)
Other comprehensive income/(loss) 61 (187)
------------------------------
Balance at end of period (816) (819)
------------------------------
3,756 3,496
------------------------------
Equity Attributable to Controlling Interests 17,329 16,679
------------------------------
Equity Attributable to Non-Controlling
Interests
Balance at beginning of period 1,157 1,174
Net income attributable to non-controlling
interests
PipeLines LP 76 64
Preferred share dividends of subsidiary 17 17
Portland 3 1
Other comprehensive income/(loss)
attributable to non-controlling interests 8 4
Sale of PipeLines LP units
Proceeds, net of issue costs 321 -
Decrease in TransCanada's ownership (50) -
Distributions to non-controlling interests (95) (85)
Foreign exchange and other 59 1
------------------------------
Balance at end of period 1,496 1,176
------------------------------
Total Equity 18,825 17,855
------------------------------
------------------------------
See accompanying notes to the consolidated financial statements.
Notes to Consolidated Financial Statements
(Unaudited)
1. Basis of Presentation
The consolidated financial statements of TransCanada Corporation (TransCanada or the Company) have been prepared 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 Note 2. The accounting policies applied are consistent with those outlined in TransCanada's annual audited Consolidated Financial Statements for the year ended December 31, 2010, except as disclosed in Note 2. These Consolidated Financial Statements reflect adjustments, all of which are normal recurring adjustments that are, in the opinion of management, necessary to present fairly the financial position and results of operations for the respective periods. These Consolidated Financial Statements do not include all disclosures required in the annual financial statements and should be read in conjunction with the 2010 audited Consolidated Financial Statements included in TransCanada's 2010 Annual Report. Unless otherwise indicated, "TransCanada"or "the Company" includes TransCanada Corporation and its subsidiaries. Capitalized and abbreviated terms that are used but not otherwise defined herein are identified in the Glossary of Terms contained in TransCanada's 2010 Annual Report. Amounts are stated in Canadian dollars unless otherwise indicated.
In Natural Gas Pipelines, which consists primarily of the Company's investments in regulated natural gas pipelines and regulated natural gas storage facilities, annual revenues and net income fluctuate over the long term based on regulators' decisions and negotiated settlements with shippers. Generally, quarter-over-quarter revenues and net income during any particular fiscal year remain relatively stable with fluctuations resulting from adjustments being recorded due to regulatory decisions and negotiated settlements with shippers, seasonal fluctuations in short-term throughput volumes on U.S. pipelines, acquisitions and divestitures, and developments outside of the normal course of operations.
In Oil Pipelines, which consists of the Company's investment in the Keystone crude oil pipeline, annual revenues are based on contracted crude oil transportation and uncommitted spot transportation. Quarter-over-quarter revenues and net income during any particular fiscal year remain relatively stable with fluctuations resulting from planned and unplanned outages, and changes in the amount of spot volumes transported and the associated rate charged. Spot volumes transported are affected by customer demand, market pricing, planned and unplanned outages of refineries, terminals and pipeline facilities, and developments outside of the normal course of operations.
In Energy, which consists primarily of the Company's investments in electrical power generation plants and non-regulated natural gas storage facilities, quarter-over-quarter revenues and net income are affected by seasonal weather conditions, customer demand, market prices, capacity payments, planned and unplanned plant outages, acquisitions and divestitures, certain fair value adjustments and developments outside of the normal course of operations.
In preparing these financial statements, TransCanada is required to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be dependent on future events. The Company uses the most current information available and exercises careful judgement in making these estimates and assumptions. In the opinion of management, these consolidated financial statements have been properly prepared within reasonable limits of materiality and within the framework of the Company's significant accounting policies.
2. Changes in Accounting Policies
Changes in Accounting Policies for 2011
Business Combinations, Consolidated Financial Statements and Non-Controlling Interests
Effective January 1, 2011, the Company adopted CICA Handbook Section 1582 "Business Combinations", which is effective for business combinations with an acquisition date after January 1, 2011. This standard was amended to require additional use of fair value measurements, recognition of additional assets and liabilities, and increased disclosure. Adopting the standard is expected to have a significant impact on the way the Company accounts for future business combinations. Entities adopting Section 1582 were also required to adopt CICA Handbook Sections 1601 "Consolidated Financial Statements" and 1602 "Non-Controlling Interests". Sections 1601 and 1602 require Non-Controlling Interests to be presented as part of Equity on the balance sheet. In addition, the income statement of the controlling parent now includes 100 per cent of the subsidiary's results and presents the allocation of income between the controlling and non-controlling interests. Changes resulting from the adoption of Section 1582 were applied prospectively and changes resulting from the adoption of Sections 1601 and 1602 were applied retrospectively.
Future Accounting Changes
U.S. GAAP/International Financial Reporting Standards
The CICA's Accounting Standards Board (AcSB) previously announced that Canadian publicly accountable enterprises are required to adopt International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB), effective January 1, 2011.
In October 2010, the AcSB and the Canadian Securities Administrators amended their policies applicable to Canadian publicly accountable enterprises, such as TransCanada, that use rate-regulated accounting (RRA) in order to permit these entities to defer the adoption of IFRS for one year. TransCanada deferred its adoption and accordingly will continue to prepare its consolidated financial statements in 2011 in accordance with Canadian GAAP, as defined by Part V of the CICA Handbook, in order to continue using RRA.
In the application of Canadian GAAP, TransCanada follows specific accounting guidance under U.S. GAAP unique to a rate-regulated business. These RRA standards allow the timing of recognition of certain revenues and expenses to differ from the timing that may otherwise be expected in a non-rate-regulated business under GAAP in order to appropriately reflect the economic impact of regulators' decisions regarding the Company's revenues and tolls. The IASB has concluded that the development of RRA under IFRS requires further analysis and has removed the RRA project from its current agenda. TransCanada does not expect a final RRA standard under IFRS to be effective in the foreseeable future.
As a registrant with the U.S. Securities and Exchange Commission, TransCanada prepares and files a "Reconciliation to United States GAAP" and has the option under Canadian disclosure rules to prepare and file its consolidated financial statements using U.S. GAAP. As a result of the developments noted above, the Company's Board of Directors has approved the adoption of U.S. GAAP effective January 1, 2012. The accounting policies and financial impact of TransCanada adopting U.S. GAAP are consistent with that currently reported in the "Reconciliation to United States GAAP" and, as a result, significant changes to existing systems and processes are not required to implement U.S. GAAP as the Company's primary accounting standard.
3. Segmented Information
For the three months
ended September 30
(unaudited) Natural Gas Oil
(millions of Pipelines Pipelines(1) Energy
dollars) 2011 2010 2011 2010 2011 2010
------------------------------------- ----------------- ----------------
------------------------------------- ----------------- ----------------
Revenues 1,098 1,080 229 - 1,066 1,049
Plant operating
costs and other (377) (366) (73) - (407) (433)
Commodity purchases
resold - - - - (270) (301)
Depreciation and
amortization (247) (232) (38) - (101) (94)
---------------- ----------------- ----------------
474 482 118 - 288 221
---------------- ----------------- ----------------
---------------- ----------------- ----------------
For the three months
ended September 30
(unaudited)
(millions of Corporate Total
dollars) 2011 2010 2011 2010
------------------------------------------------------------------------
------------------------------------------------------------------------
Revenues - - 2,393 2,129
Plant operating
costs and other (18) (18) (875) (817)
Commodity purchases
resold - - (270) (301)
Depreciation and
amortization (3) - (389) (326)
----------------------------------------------------
(21) (18) 859 685
---------------
---------------
Interest expense (240) (159)
Interest expense of joint ventures (13) (13)
Interest income and other (44) 27
Income taxes expense (133) (120)
---------------
Net Income 429 420
Net Income Attributable to Non-Controlling Interests (32) (29)
--------------
Net Income Attributable to Controlling Interests 397 391
Preferred Share Dividends (13) (14)
--------------
Net Income Attributable to Common Shares 384 377
--------------
--------------
For the nine months
ended September 30
(unaudited) Natural Gas Oil
(millions of Pipelines Pipelines(1) Energy
dollars) 2011 2010 2011 2010 2011 2010
------------------------------------ ----------------- ----------------
------------------------------------ ----------------- ----------------
Revenues 3,294 3,270 575 - 2,910 2,737
Plant operating
costs and other (1,066) (1,092) (167) - (1,166) (1,170)
Commodity purchases
resold - - - - (732) (773)
Depreciation and
amortization (735) (736) (95) - (298) (274)
--------------- ----------------- ----------------
1,493 1,442 313 - 714 520
--------------- ----------------- ----------------
--------------- ----------------- ----------------
For the nine months
ended September 30
(unaudited)
(millions of Corporate Total
dollars) 2011 2010 2011 2010
----------------------------------------------------- -----------------
----------------------------------------------------- -----------------
Revenues - - 6,779 6,007
Plant operating
costs and other (57) (66) (2,456) (2,328)
Commodity purchases
resold - - (732) (773)
Depreciation and
amortization (10) - (1,138) (1,010)
-------------- ----------------
(67) (66) 2,453 1,896
--------------
--------------
Interest expense (686) (528)
Interest expense of joint ventures (40) (44)
Interest income and other 12 33
Income taxes expense (450) (286)
-------------
Net Income 1,289 1,071
Net Income Attributable to Non-Controlling Interests (96) (82)
-------------
Net Income Attributable to Controlling Interests 1,193 989
Preferred Share Dividends (41) (31)
-------------
Net Income Attributable to Common Shares 1,152 958
-------------
-------------
(1) Commencing in February 2011, TransCanada began recording earnings
related to the Wood River/Patoka and Cushing Extension sections of
Keystone.
Total Assets
(unaudited)
(millions of dollars) September 30, 2011 December 31, 2010
--------------------------------------------------- ---------------------
--------------------------------------------------- ---------------------
Natural Gas Pipelines 23,584 23,592
Oil Pipelines 9,137 8,501
Energy 13,698 12,847
Corporate 1,325 1,649
------------------- ---------------------
47,744 46,589
------------------- ---------------------
------------------- ---------------------
4. Long-Term Debt
In August 2011, TransCanada PipeLine USA Ltd. made a principal repayment of US$200 million on the US$700 million five-year term loan which matures in 2012.
In July 2011, PipeLines LP increased its senior revolving credit facility to US$500 million and extended the maturity date to July 2016. PipeLines LP's remaining US$300 million term loan matures December 2011 and it is expected it will be refinanced with fixed or floating rate debt at or prior to its maturity.
In June 2011, TCPL retired $60 million of 9.5 per cent Medium-Term Notes and, in January 2011, retired $300 million of 4.3 per cent Medium-Term Notes.
In June 2011, PipeLines LP issued US$350 million of 4.65 per cent Senior Notes due 2021 and cancelled US$175 million of its unsecured syndicated senior credit facility. The proceeds from the issuance were used to reduce PipeLines LP's term loan and senior revolving credit facility, and repay its bridge loan facility.
In the three and nine months ended September 30, 2011, the Company capitalized interest related to capital projects of $66 million and $231 million, respectively (2010 - $160 million and $437 million).
5. Equity and Share Capital
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 the three and nine months ended September 30, 2011, TransCanada issued nil and 5.4 million (2010 - 2.9 million and 7.8 million) common shares, respectively, under its Dividend Reinvestment and Share Purchase Plan (DRP), in lieu of making cash dividend payments of nil and $202 million, respectively (2010 - $101 million and $271 million). Commencing with the dividends declared April 28, 2011, dividends payable to shareholders who participate in the DRP are satisfied with common shares purchased on the open market determined on the basis of the weighted average purchase price of such common shares. Previously, common shares issued in lieu of cash dividends under the DRP were issued from treasury.
6. Financial Instruments and Risk Management
TransCanada continues to manage and monitor its exposure to counterparty credit, liquidity and market risk.
Counterparty Credit and Liquidity Risk
TransCanada's maximum counterparty credit exposure with respect to financial instruments at the balance sheet date, without taking into account security held, consisted of accounts receivable, portfolio investments recorded at fair value, the fair value of derivative assets, and notes, loans and advances receivable. The carrying amounts and fair values of these financial assets, except amounts for derivative assets, are included in Accounts Receivable and Other, and Available-For-Sale Assets in the Non-Derivative Financial Instruments Summary table below. Guarantees, letters of credit and cash are the primary types of security provided to support these amounts. The majority of counterparty credit exposure is with counterparties who are investment grade. At September 30, 2011, there were no significant amounts past due or impaired.
At September 30, 2011, the Company had a credit risk concentration of $271 million due from a creditworthy counterparty. This amount is expected to be fully collectible and is secured by a guarantee from the counterparty's parent company.
The Company continues to manage its liquidity risk by ensuring sufficient cash and credit facilities are available to meet its operating and capital expenditure obligations when due, under both normal and stressed economic conditions.
Natural Gas Storage Commodity Price Risk
At September 30, 2011, the fair value of proprietary natural gas inventory held in storage, as measured using a weighted average of forward prices for the following four months less selling costs, was $40 million (December 31, 2010 - $49 million). The change in the fair value adjustment of proprietary natural gas inventory in storage in the three and nine months ended September 30, 2011 resulted in net pre-tax unrealized losses of $1 million and nil, respectively (2010 - nil and losses of $20 million, respectively), which were recorded as adjustments to Revenues and Inventories. The change in fair value of natural gas forward purchase and sale contracts in the three and nine months ended September 30, 2011 resulted in net pre-tax unrealized losses of $3 million and $13 million, respectively (2010 - gains of $7 million and $12 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 $7 million at September 30, 2011 (December 31, 2010 - $12 million). The decrease in VAR is primarily a result of lower price volatility in Western Power.
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, 2011, the Company had designated as a net investment hedge U.S. dollar-denominated debt with a carrying value of $10 billion (US$10 billion) and a fair value of $12 billion (US$12 billion). At September 30, 2011, $66 million was included in Other Current Assets, $41 million (December 31, 2010 - $181 million) was included in Intangible and Other Assets, $44 million was included in Accounts Payable, and $83 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 foreign operations.
The fair values and notional principal amounts for the derivatives designated as a net investment hedge were as follows:
Derivatives Hedging Net Investment in Self-Sustaining Foreign Operations
September 30, 2011 December 31, 2010
-----------------------------------------------------------
Asset/(Liability)
(unaudited) Notional or Notional or
(millions of Fair Principal Fair Principal
dollars) Value(1) Amount Value(1) Amount
-------------------------------- -------------- ------------- --------------
-------------------------------- -------------- ------------- --------------
U.S. dollar
cross-currency
swaps
(maturing 2011 to
2018) 19 US 3,700 179 US 2,800
U.S. dollar
forward foreign
exchange
contracts
(maturing 2011 to
2012) (39) US 725 2 US 100
------------- -------------- ------------- --------------
(20) US 4,425 181 US 2,900
------------- -------------- ------------- --------------
------------- -------------- ------------- --------------
(1) Fair values equal carrying values.
The carrying and fair values of non-derivative financial instruments were as follows:
Non-Derivative Financial Instruments Summary
September 30, 2011 December 31, 2010
----------------------- -----------------------
(unaudited) Carrying Fair Carrying Fair
(millions of dollars) Amount Value Amount Value
--------------------------------------- ------------ ----------- -----------
--------------------------------------- ------------ ----------- -----------
Financial Assets(1)
Cash and cash equivalents 596 596 764 764
Accounts receivable and
other(2)(3) 1,518 1,563 1,555 1,595
Available-for-sale assets(2) 38 38 20 20
--------- ------------ ----------- -----------
2,152 2,197 2,339 2,379
--------- ------------ ----------- -----------
--------- ------------ ----------- -----------
Financial Liabilities(1)(3)
Notes payable 1,865 1,865 2,092 2,092
Accounts payable and
deferred amounts(4) 1,253 1,253 1,436 1,436
Accrued interest 348 348 367 367
Long-term debt 18,110 22,588 17,922 21,523
Long-term debt of joint
ventures 855 980 866 971
Junior subordinated notes 1,030 1,034 985 992
--------- ------------ ----------- -----------
23,461 28,068 23,668 27,381
--------- ------------ ----------- -----------
--------- ------------ ----------- -----------
(1) Consolidated Net Income in the three and nine months ended September 30,
2011 included losses of $7 million and $18 million, respectively, (2010
- losses of $2 million and $11 million, respectively), for fair value
adjustments related to interest rate swap agreements on US$350 million
(2010 - US$150 million) of Long-Term Debt. There were no other
unrealized gains or losses from fair value adjustments to the non-
derivative financial instruments.
(2) At September 30, 2011, the Consolidated Balance Sheet included financial
assets of $1,191 million (December 31, 2010 - $1,271 million) in
Accounts Receivable, $47 million (December 31, 2010 - $40 million) in
Other Current Assets and $318 million (December 31, 2010 - $264 million)
in Intangibles and Other Assets.
(3) Recorded at amortized cost, except for the US$350 million (December 31,
2010 - US$250 million) of Long-Term Debt that is adjusted to fair value.
(4) At September 30, 2011, the Consolidated Balance Sheet included financial
liabilities of $1,224 million (December 31, 2010 - $1,406 million) in
Accounts Payable and $29 million (December 31, 2010 - $30 million) in
Deferred Amounts.
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:
September 30, 2011
(unaudited)
(all amounts in millions
unless otherwise Natural Foreign
indicated) Power Gas Exchange Interest
------------------------------------- ----------- ----------- -----------
------------------------------------- ----------- ----------- -----------
Derivative Financial
Instruments
Held for Trading(1)
Fair Values(2)
Assets $ 133 $ 160 $ - $ 26
Liabilities $ (107) $ (195) $ (46) $ (26)
Notional Values
Volumes(3)
Purchases 21,147 136 - -
Sales 25,884 109 - -
Canadian dollars - - - 684
U.S. dollars - - US 1,366 US 250
Cross-currency - - 47/US 37 -
Net unrealized
gains/(losses) in the
period(4)
Three months ended
September 30, 2011 $ 5 $ (13) $ (41) $ 1
Nine months ended
September 30, 2011 $ 8 $ (39) $ (41) $ 1
Net realized
gains/(losses) in the
period(4)
Three months ended
September 30, 2011 $ 21 $ (20) $ (7) $ 3
Nine months ended
September 30, 2011 $ 32 $ (61) $ 26 $ 8
Maturity dates 2011-2018 2011-2016 2011-2012 2012-2016
Derivative Financial
Instruments
in Hedging
Relationships(5)(6)
Fair Values(2)
Assets $ 46 $ 7 $ 5 $ 18
Liabilities $ (182) $ (17) $ (36) $ (8)
Notional Values
Volumes(3)
Purchases 17,728 10 - -
Sales 8,732 - - -
U.S. dollars - - US 104 US 1,000
Cross-currency - - 136/US 100 -
Net realized losses in
the period(4)
Three months ended
September 30, 2011 $ (54) $ (6) $ - $ (4)
Nine months ended
September 30, 2011 $ (100) $ (14) $ - $ (13)
Maturity dates 2011-2017 2011-2013 2013-2014 2011-2015
----------- ----------- ----------- -----------
----------- ----------- ----------- -----------
(1) All derivative financial instruments in the held-for-trading
classification have been entered into for risk management purposes and
are subject to the Company's risk management strategies, policies and
limits. These include derivatives that have not been designated as
hedges or do not qualify for hedge accounting treatment but have been
entered into as economic hedges to manage the Company's exposures to
market risk.
(2) Fair values equal carrying values.
(3) Volumes for power and natural gas derivatives are in GWh and Bcf,
respectively.
(4) Realized and unrealized gains and losses on financial held-for-trading
derivatives used to purchase and sell power and natural gas are included
on a net basis in Revenues. Realized and unrealized gains and losses on
interest rate and foreign exchange derivative financial instruments
held-for-trading are included in Interest Expense and Interest Income
and Other, respectively. The effective portion of unrealized gains and
losses on derivative financial instruments in cash flow hedging
relationships is initially recognized in Other Comprehensive Income and
reclassified to Revenues, Interest Expense and Interest Income and
Other, as appropriate, as the original hedged item settles.
(5) All hedging relationships are designated as cash flow hedges except for
interest rate derivative financial instruments designated as fair value
hedges with a fair value of $18 million and a notional amount of US$350
million at September 30, 2011. Net realized gains on fair value hedges
for the three and nine months ended September 30, 2011 were $1 million
and $5 million, respectively, and were included in Interest Expense. In
the three and nine months ended September 30, 2011, the Company did not
record any amounts in Net Income related to ineffectiveness for fair
value hedges.
(6) For the three and nine months ended September 30, 2011, Net Income
included gains of $1 million and nil, respectively, for changes in the
fair value of power and natural gas cash flow hedges that were
ineffective in offsetting the change in fair value of their related
underlying positions. For the three and nine months ended September 30,
2011, there were no gains or losses included in Net Income for
discontinued cash flow hedges. No amounts have been excluded from the
assessment of hedge effectiveness.
2010
(unaudited)
(all amounts in millions
unless otherwise Natural Foreign
indicated) Power Gas Exchange Interest
------------------------------------- ------------ ------------ ------------
------------------------------------- ------------ ------------ ------------
Derivative Financial
Instruments
Held for Trading
Fair Values(1)(2)
Assets $ 169 $ 144 $ 8 $ 20
Liabilities $ (129) $ (173) $ (14) $ (21)
Notional Values(2)
Volumes(3)
Purchases 15,610 158 - -
Sales 18,114 96 - -
Canadian dollars - - - 736
U.S. dollars - - US 1,479 US 250
Cross-currency - - 47/US 37 -
Net unrealized
(losses)/gains in the
period(4)
Three months ended
September 30, 2010 $ (1) $ 4 $ 10 $ 50
Nine months ended
September 30, 2010 $ (27) $ 9 $ (1) $ 33
Net realized
gains/(losses) in the
period(4)
Three months ended
September 30, 2010 $ 13 $ (10) $ 6 $ (54)
Nine months ended
September 30, 2010 $ 50 $ (39) $ 8 $ (64)
Maturity dates(2) 2011-2015 2011-2015 2011-2012 2011-2016
Derivative Financial
Instruments
in Hedging
Relationships(5)(6)
Fair Values(1)(2)
Assets $ 112 $ 5 $ - $ 8
Liabilities $ (186) $ (19) $ (51) $ (26)
Notional Values(2)
Volumes(3)
Purchases 16,071 17 - -
Sales 10,498 - - -
U.S. dollars - - US 120 US 1,125
Cross-currency - - 136/US 100 -
Net realized losses in
the period(4)
Three months ended
September 30, 2010 $ 37 $ (19) $ - $ (7)
Nine months ended
September 30, 2010 $ (6) $ (28) $ - $ (26)
Maturity dates(2) 2011-2015 2011-2013 2011-2014 2011-2015
----------- ------------ ------------ ------------
----------- ------------ ------------ ------------
(1) Fair values equal carrying values.
(2) As at December 31, 2010.
(3) Volumes for power and natural gas derivatives are in GWh and Bcf,
respectively.
(4) Realized and unrealized gains and losses on financial held-for-trading
derivatives used to purchase and sell power and natural gas are included
on a net basis in Revenues. Realized and unrealized gains and losses on
interest rate and foreign exchange derivative financial instruments held
for trading are included in Interest Expense and Interest Income and
Other, respectively. The effective portion of unrealized gains and
losses on derivative financial instruments in cash flow hedging
relationships is initially recognized in Other Comprehensive Income and
reclassified to Revenues, Interest Expense and Interest Income and
Other, as appropriate, as the original hedged item settles.
(5) All hedging relationships are designated as cash flow hedges except for
interest rate derivative financial instruments designated as fair value
hedges with a fair value of $8 million and a notional amount of US$250
million at December 31, 2010. Net realized gains on fair value hedges
for the three and nine months ended September 30, 2010 were $1 million
and $3 million, respectively, and were included in Interest Expense. In
the three and nine months ended September 30, 2010, the Company did not
record any amounts in Net Income related to ineffectiveness for fair
value hedges.
(6) Losses included in Net income for the three and nine months ended
September 30, 2010 were nil and $1 million, respectively, for changes in
the fair value of power and natural gas cash flow hedges that were
ineffective in offsetting the change in fair value of their related
underlying positions. For the three and nine months ended September 30,
2010, there were no gains or losses included in Net Income for
discontinued cash flow hedges. No amounts were excluded from the
assessment of hedge effectiveness.
Balance Sheet Presentation of Derivative Financial Instruments
The fair value of the derivative financial instruments in the Company's Balance Sheet was as follows:
(unaudited)
(millions of dollars) September 30, 2011 December 31, 2010
------------------------------------------------------- --------------------
------------------------------------------------------- --------------------
Current
Other current assets 319 273
Accounts payable (405) (337)
Long-term
Intangibles and other assets 183 374
Deferred amounts (339) (282)
------------------- --------------------
------------------- --------------------
Fair Value Hierarchy
The Company's financial assets and liabilities recorded at fair value have been categorized into three categories based on a 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. In Level II, determination of the fair value of assets and liabilities includes valuations using inputs, other than quoted prices, for which all significant inputs are observable, directly or indirectly. This category includes fair value determined using valuation techniques such as option pricing models and extrapolation using observable inputs. In Level III, determination of the fair value of assets and liabilities is based on inputs that are not readily observable and are significant to the overall fair value measurement. Long-dated commodity transactions in certain markets are included in this category. Long-dated commodity prices are derived with a third-party modelling tool that uses market fundamentals to derive long-term prices.
There were no transfers between Level I and Level II in the three and nine months ended September 31, 2011. Financial assets and liabilities measured at fair value, including both current and non-current portions, are categorized as follows:
Significant
Quoted Prices Other
in Active Observable
Markets Inputs
Assets/(Liabilities) (Level 1) (Level II)
(unaudited) ----------------------- -----------------------
(millions of dollars, pre- Sept 30 Dec 31 Sept 30 Dec 31
tax) 2011 2010 2011 2010
--------------------------- ----------- ----------- ----------- -----------
--------------------------- ----------- ----------- ----------- -----------
Natural Gas Inventory - - 40 49
Derivative Financial
Instrument Assets:
Interest rate contracts - - 44 28
Foreign exchange contracts 5 10 107 179
Power commodity contracts - - 166 269
Natural gas commodity
contracts 88 93 79 56
Derivative Financial
Instrument Liabilities:
Interest rate contracts - - (34) (47)
Foreign exchange contracts (71) (11) (138) (54)
Power commodity contracts - - (260) (299)
Natural gas commodity
contracts (162) (178) (50) (15)
Non-Derivative Financial
Instruments:
Available-for-sale assets 38 20 - -
----------- ----------- ----------- -----------
(102) (66) (46) 166
----------- ----------- ----------- -----------
----------- ----------- ----------- -----------
Significant
Unobservable
Inputs
Assets/(Liabilities) (Level III) Total
(unaudited) ---------------------- -----------------------
(millions of dollars, pre- Sept 30 Dec 31 Sept 30 Dec 31
tax) 2011 2010 2011 2010
-------------------------------------- ----------- ----------- -----------
-------------------------------------- ----------- ----------- -----------
Natural Gas Inventory - - 40 49
Derivative Financial
Instrument Assets:
Interest rate contracts - - 44 28
Foreign exchange contracts - - 112 189
Power commodity contracts 2 5 168 274
Natural gas commodity
contracts - - 167 149
Derivative Financial
Instrument Liabilities:
Interest rate contracts - - (34) (47)
Foreign exchange contracts - - (209) (65)
Power commodity contracts (18) (8) (278) (307)
Natural gas commodity
contracts - - (212) (193)
Non-Derivative Financial
Instruments:
Available-for-sale assets - - 38 20
----------- ----------- ----------- -----------
(16) (3) (164) 97
----------- ----------- ----------- -----------
----------- ----------- ----------- -----------
The following table presents the net change in financial assets and liabilities measured at fair value and included in the Level III fair value category:
(unaudited) Derivatives(1)
(millions of dollars, pre-tax) 2011 2010
----------------------------------------------------------- --------------
----------------------------------------------------------- --------------
Balance at January 1 (3) (2)
New contracts(2) 1 (15)
Transfers out of Level III(3) (2) (20)
Settlements - (3)
Change in unrealized gains recorded in Net
Income 1 14
Change in unrealized (losses)/gains recorded
in Other Comprehensive Income (13) 38
------------ --------------
Balance at September 30 (16) 12
------------ --------------
------------ --------------
(1) The fair value of derivative assets and liabilities is presented on a
net basis.
(2) For the three and nine months ended September 30, 2011, there were no
amounts (2010 - gain of $1 million and nil, respectively), included in
Net Income attributable to derivatives that were entered into during the
period and still held at the reporting date.
(3) As contracts near maturity and inputs become observable, they are
transferred out of Level III and into Level II.
A 10 per cent increase or decrease in commodity prices, with all other variables held constant, would result in a $10 million decrease or increase, respectively, in the fair value of derivative financial instruments included in Level III and outstanding as at September 30, 2011.
7. Employee Future Benefits
The net benefit plan expense for the Company's defined benefit pension plans and other post-employment benefit plans is as follows:
Three months ended
September 30
(unaudited)(millions of Pension Benefit Plans Other Benefit Plans
dollars) 2011 2010 2011 2010
------------------------------------- ------------ ------------ ------------
------------------------------------- ------------ ------------ ------------
Current service cost 14 12 - -
Interest cost 23 22 2 2
Expected return on plan
assets (29) (27) - -
Amortization of
transitional obligation
related to regulated
business - - - -
Amortization of net
actuarial loss 5 2 - -
Amortization of past
service costs 1 1 - -
---------- ------------ ------------ ------------
Net benefit cost
recognized 14 10 2 2
---------- ------------ ------------ ------------
---------- ------------ ------------ ------------
Nine months ended
September 30
(unaudited)(millions of Pension Benefit Plans Other Benefit Plans
dollars) 2011 2010 2011 2010
------------------------------------- ------------ ------------ ------------
------------------------------------- ------------ ------------ ------------
Current service cost 41 37 1 1
Interest cost 68 67 6 6
Expected return on plan
assets (85) (81) (1) (1)
Amortization of
transitional obligation
related to regulated
business - - 1 1
Amortization of net
actuarial loss 16 6 1 1
Amortization of past
service costs 3 3 - -
---------- ------------ ------------ ------------
Net benefit cost
recognized 43 32 8 8
---------- ------------ ------------ ------------
---------- ------------ ------------ ------------
8. Dispositions
On May 3, 2011, the Company completed the sale of a 25 per cent interest in each of Gas Transmission Northwest LLC (GTN LLC) and Bison Pipeline LLC (Bison LLC) to PipeLines LP for an aggregate purchase price of US$605 million, subject to closing adjustments, which included US$81 million of long-term debt, or 25 per cent of GTN LLC debt outstanding. GTN LLC and Bison LLC own the GTN and Bison natural gas pipelines, respectively.
On May 3, 2011, PipeLines LP completed an underwritten public offering of 7,245,000 common units, including 945,000 common units purchased by the underwriters upon full exercise of an over-allotment option, at US$47.58 per unit. Gross proceeds of approximately US$345 million from this offering were used to partially fund the acquisition. The acquisition was also funded by draws of US$61 million on PipeLines LP's bridge loan facility and of US$125 million on its US$250 million senior revolving credit facility.
As part of this offering, TransCanada made a capital contribution of approximately US$7 million to maintain its two per cent general partnership interest in PipeLines LP and did not purchase any other units. As a result of the common units offering, TransCanada's ownership in PipeLines LP decreased from 38.2 per cent to 33.3 per cent and an after-tax dilution gain of $30 million ($50 million pre-tax) was recorded in Contributed Surplus.
9. Contingencies
Amounts received under the Bruce B floor price mechanism within a calendar year are subject to repayment if the monthly average spot price exceeds the floor price. With respect to 2011, TransCanada currently expects spot prices to be less than the floor price for the remainder of the year, therefore no amounts recorded in revenues in the first nine months of 2011 are expected to be repaid.
Contact Information:
TransCanada
Media Enquiries:
Terry Cunha/Shawn Howard
403.920.7859 or 800.608.7859
TransCanada
Investor & Analyst Enquiries:
David Moneta/Terry Hook/Lee Evans
403.920.7911 or 800.361.6522
www.transcanada.com