TransCanada Reports 30 Per Cent Increase in Second Quarter Comparable Earnings to $357 Million, or $0.51 Per Share
CALGARY, ALBERTA--(Marketwire - July 28, 2011) - TransCanada Corporation (TSX:TRP) (NYSE:TRP) (TransCanada or the Company) today announced comparable earnings for second quarter 2011 of $357 million or $0.51 per share. Net income attributable to common shares was $353 million or $0.50 per share. TransCanada's Board of Directors also declared a quarterly dividend of $0.42 per common share for the quarter ending September 30, 2011, equivalent to $1.68 per share on an annualized basis.
"We continue to experience strong earnings and cash flow growth as our company realizes the benefits of major projects that have started operations over the last year," said Russ Girling, TransCanada's president and chief executive officer. "Those benefits have translated into a 30 per cent increase in comparable earnings for the second quarter of 2011, compared to the same period in 2010."
TransCanada has completed and brought into service more than $10 billion of assets under its capital growth program. Most recently, the Company's Guadalajara pipeline began shipping natural gas in Mexico in mid June. In early May, TransCanada's Coolidge Generating Station began producing power in Arizona under a 20-year power purchase arrangement (PPA) with a local utility.
Earlier in 2011 and in 2010, the company brought into service the first and second phases of the Keystone oil pipeline system, the Bison and Groundbirch natural gas pipelines, Maine's largest wind project - Kibby Wind, the Halton Hills Generating Station in Ontario and the North Central Corridor gas pipeline in northern Alberta.
Looking forward, TransCanada is focused on completing the remaining projects that are part of its current capital program - the Keystone U.S. Gulf Coast Expansion (Keystone XL), additional extensions and expansions of the Alberta System, the Bruce Power restart program in Ontario and the Cartier Wind power project in Quebec. Each is expected to generate long-term, sustainable earnings and cash flow as they begin operations.
Second Quarter Highlights
(All financial figures are unaudited and in Canadian dollars unless noted otherwise)
-- Comparable earnings of $357 million, an increase of 30 per cent
-- Comparable earnings per share of $0.51, an increase of 28 per cent
-- Net income attributable to common shares of $353 million or $0.50 per
share
-- Comparable EBITDA of $1.139 billion, an increase of 23 per cent
-- Funds generated from operations of $892 million
-- Common share dividend of $0.42 per share for the quarter ending
September 30, 2011
-- Coolidge Generating Station commenced commercial operations in May
followed by the Guadalajara natural gas pipeline in June
-- Closed the sale of a 25 per cent interest in each of Gas Transmission
Northwest LLC and Bison Pipeline LLC to TC PipeLines, LP for US$605
million
Comparable earnings for second quarter 2011 were $357 million ($0.51 per share) compared to $275 million ($0.40 per share) in the same period in 2010. The increase was primarily due to incremental earnings from recently commissioned assets including Keystone, Halton Hills, Bison and Coolidge. Also contributing to the year-over-year increase in earnings were higher Natural Gas Pipeline earnings from the Alberta System and ANR and higher Energy earnings from U.S. Power and Bruce A. Partially offsetting these increases were higher interest costs and a lower contribution from Western Power and Bruce B.
Notable recent developments in Oil Pipelines, Natural Gas Pipelines, Energy and Corporate include:
Oil Pipelines:
-- Regulatory review of Keystone XL is progressing. The 45-day public
comment period for the Supplemental Draft Environmental Impact Statement
concluded June 6. The U.S. Department of State (DOS) is processing the
comments and has said it will release a Final Environmental Impact
Statement in mid-August. The DOS will then consult with other U.S.
federal agencies during a 90-day period to determine if Keystone XL is
in the national interest of the United States. A final decision on a
Presidential Permit for the project is expected by year's end.
TransCanada remains committed to building a safe, reliable pipeline,
using the most advanced technology and construction practices. The
Company voluntarily agreed to 57 additional conditions put forward by
the U.S. Department of Transportation - Pipeline and Hazardous Materials
Safety Administration - conditions that would see Keystone XL
exceed existing industry standards. The conditions include additional
safety features such as more shut-off valves and increased pipeline
inspections.
Natural Gas Pipelines:
-- The 307-kilometre (km) (191-mile) Guadalajara Pipeline began shipping
natural gas on June 15 of this year. The US$360 million project has
capacity to transport 500 million cubic feet per day (MMcf/d) of natural
gas to a nearby power plant and 320 MMcf/d to the Pemex-owned national
pipeline system near Guadalajara. TransCanada and the Comision Federal
de Electricidad have agreed to add a US$60 million compressor station to
the pipeline that is expected to be operational early in 2013.
-- TransCanada is preparing a comprehensive rate application for the
Canadian Mainline that is expected to be submitted to the National
Energy Board (NEB) by September 1, 2011, addressing tolls for 2012 and
2013. The application will include changes to the business structure,
toll design and services intended to improve the competitiveness of
TransCanada's regulated Canadian natural gas transportation
infrastructure and the Western Canada Sedimentary Basin (WCSB).
The Mainline is a very important component of the North American gas
delivery system. Total deliveries averaged 5.9 billion cubic feet per
day (Bcf/d) for the first six months of this year, making it the largest
long haul gas transportation system on the continent. Receipts from the
WCSB continue to make up the majority of the volumes, averaging 3.6
Bcf/d for the first half of the year and peaking at 5.4 Bcf/d this past
winter.
Successful new capacity open seasons for the Mainline concluded over the
past 12 months, resulting in contractual agreements to ship a total of
approximately 350 MMcf/d of Marcellus shale gas to eastern markets. Gas
deliveries from Niagara to the Toronto market are expected to begin at a
rate of 230 MMcf/d in November 2012, increasing to 350 MMcf/d in
November 2013. An application for approval to construct $130 million of
new pipeline infrastructure to accommodate these volumes was filed with
the NEB July 18, 2011.
There is ongoing shipper interest for additional capacity in the eastern
part of the Canadian Mainline and more requests for service are expected
over time.
-- The estimated $275 million Horn River natural gas pipeline project was
approved by the NEB in January 2011 and construction began in March
2011, with a targeted completion date of second quarter 2012. The
project will be further expanded and extended by approximately 100 kms
(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. The total contracted amount for Horn River, including the
extension, is expected to be approximately 900 MMcf/d in 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 is expected to commence in August 2011 with an in-service
date of April 1, 2012 and an estimated capital cost of approximately $60
million. The project is required to service 250 MMcf/d of new
transportation contracts.
TransCanada continues to advance further pipeline development in B.C.
and Alberta to transport new natural gas supplies. The Company has filed
several applications with the NEB requesting approval of expansions of
the Alberta System to accommodate requests for additional natural gas
transmission service throughout the northwest portion of the WCSB. As of
June 30, 2011, the NEB has approved pipeline projects with total capital
costs estimated at $500 million. Further pipeline projects with a total
capital cost of approximately $700 million are before the NEB for
approval.
The successful open seasons and ongoing business with Western Canadian
producers have resulted in significant contracts from both the Montney
and Horn River shale gas formations. TransCanada has firm commitments to
transport 2.9 Bcf/d from northeast British Columbia and northwest
Alberta by 2014. Further requests to transport significant additional
volumes on the Alberta System from the northwest portion of the WCSB
have been received.
Energy:
-- The 575 megawatt (MW), US$500 million Coolidge Generating Station went
into service May 1. All of the power produced at Coolidge is sold under
a 20-year PPA with the Salt River Project, a local Arizona utility.
-- Loading of fuel into the refurbished Bruce A Unit 2 began in second
quarter 2011 and was completed in July. Fuel channel assembly was
completed on Unit 1 during second quarter 2011, which was the final
stage of Atomic Energy of Canada Limited's work on the reactors. The
work continues to transition from construction to commissioning.
Subject to regulatory approval, Bruce Power expects to achieve a first
synchronization of the Unit 2 generator to the electrical grid by the
end of 2011, with commercial operation expected to occur in first
quarter 2012. Fuel loading into Unit 1 is expected to begin in third
quarter 2011, with a first synchronization of the generator during first
quarter 2012 and commercial operation is expected to occur during third
quarter 2012.
TransCanada's share of the total capital cost is expected to be
approximately $2.4 billion. The Company has invested $2.1 billion as of
June 30, 2011.
-- Construction continues on the five-stage, 590 MW Cartier Wind project in
Quebec. The 58 MW Montagne-Seche project and phase one of the Gros-Morne
wind farm with 101 MW 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.
-- The binding arbitration process to resolve the Sundance A power purchase
arrangement dispute arising out of TransAlta Corporation's claims of
force majeure and economic destruction is underway.
The arbitration panel is expected to hold a hearing in March and April
2012. Assuming the hearing concludes within the time allotted,
TransCanada expects to receive a decision in mid-2012. As the limited
information received to date does not support these claims, TransCanada
continues to record revenues and costs under the PPA as though this
event was a normal plant outage.
-- The July 2011 spot price for capacity sales in the New York Zone J
market has settled at materially lower levels than prior periods
resulting from the manner in which the New York Independent System
Operator (NYISO) has treated price mitigation for a new power plant that
recently began service in this market.
TransCanada believes that this treatment 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 price. TransCanada and a number of other
parties have brought a series of complaints before the FERC. The outcome
of the complaints and the long-term impact that this development may
have on TransCanada's operations at Ravenswood are unknown.
The demand curve reset process continues with the NYISO's June 20, 2011
compliance filing resulting in an increased demand curve for 2011 to
2014. The FERC has not yet responded to this filing and, as a result, it
is not yet known when the revised demand curves will be effective.
Corporate:
-- The Board of Directors of TransCanada declared a quarterly dividend of
$0.42 per common share for the quarter ending September 30, 2011 on
TransCanada's outstanding common shares. The quarterly amount is
equivalent to $1.68 per common share on an annual basis.
-- In June, TransCanada filed a $2 billion Canadian medium-term notes base
shelf prospectus to replace an April 2009, $2 billion prospectus, which
expired in May 2011 and had remaining capacity of $2 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 TC PipeLines, LP (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) and Bison Pipeline LLC
to PipeLines LP for an aggregate purchase price of US$605 million, which
included US$81 million or 25 per cent of GTN's debt and subject to
customary closing adjustments.
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 two per cent 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.
Teleconference and Webcast - Audio and Slide Presentation:
TransCanada will hold a teleconference and webcast to discuss its 2011 second quarter financial results. Russ Girling, TransCanada president and chief executive officer and Don Marchand, executive vice-president and chief financial officer, along with other members of the TransCanada executive leadership team, will discuss the financial results and company developments before opening the call to questions from analysts and members of the media.
Event:
TransCanada 2011 second quarter financial results teleconference and webcast
Date:
Thursday, July 28, 2011
Time:
2:30 p.m. mountain daylight time (MDT) / 4:30 p.m. eastern daylight time (EDT)
How:
Analysts, members of the media and other interested parties are invited to participate by calling (866) 223-7781 or (416) 340-8018 (Toronto area). Please dial in 10 minutes prior to the start of the call. No pass code is required. A live webcast of the teleconference will be available at www.transcanada.com.
A replay of the teleconference will be available two hours after the conclusion of the call until midnight (EDT) August 4, 2011. Please call (800) 408-3053 or (905) 694-9451 (Toronto area) and enter pass code 5762531#.
With more than 60 years experience, TransCanada is a leader in the responsible development and reliable operation of North American energy infrastructure including natural gas and oil pipelines, power generation and gas storage facilities. TransCanada's network of wholly owned natural gas pipelines extends more than 57,000 kilometres (35,500 miles), tapping into virtually all major gas supply basins in North America. TransCanada is one of the continent's largest providers of gas storage and related services with approximately 380 billion cubic feet of storage capacity. A growing independent power producer, TransCanada owns, or has interests in, over 10,800 megawatts of power generation in Canada and the United States. TransCanada is developing one of North America's largest oil delivery systems. TransCanada's common shares trade on the Toronto and New York stock exchanges under the symbol TRP. For more information visit: www.transcanada.com.
Forward-Looking Information
This news release may contain certain information that is forward-looking and is subject to important risks and uncertainties. The words "anticipate", "expect", "believe", "may", "should", "estimate", "project", "outlook", "forecast" or other similar words are used to identify such forward-looking information. Forward-looking statements in this document are intended to provide TransCanada security holders and potential investors with information regarding TransCanada and its subsidiaries, including management's assessment of TransCanada's and its subsidiaries' future financial and operational plans and outlook. Forward-looking statements in this document may include, among others, statements regarding the anticipated business prospects, projects and financial performance of TransCanada and its subsidiaries, expectations or projections about the future, strategies and goals for growth and expansion, expected and future cash flows, costs, schedules including anticipated construction and completion dates, operating and financial results and expected impact of future commitments and contingent liabilities. All forward-looking statements reflect TransCanada's beliefs and assumptions based on information available at the time the statements were made. Actual results or events may differ from those predicted in these forward-looking statements. Factors that could cause actual results or events to differ materially from current expectations include, among others, the ability of TransCanada to successfully implement its strategic initiatives and whether such strategic initiatives will yield the expected benefits, the operating performance of the Company's pipeline and energy assets, the availability and price of energy commodities, capacity payments, regulatory processes and decisions, changes in environmental and other laws and regulations, competitive factors in the pipeline and energy sectors, construction and completion of capital projects, labour, equipment and material costs, access to capital markets, interest and currency exchange rates, technological developments and economic conditions in North America. By its nature, forward-looking information is subject to various risks and uncertainties, which could cause TransCanada's actual results and experience to differ materially from the anticipated results or expectations expressed. Additional information on these and other factors is available in the reports filed by TransCanada with Canadian securities regulators and with the U.S. Securities and Exchange Commission.
Readers are cautioned not to place undue reliance on this forward-looking information, which is given as of the date it is expressed in this news release or otherwise, and not to use future-oriented information or financial outlooks for anything other than their intended purpose. TransCanada undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, except as required by law.
Non-GAAP Measures
TransCanada uses the measures Comparable Earnings, Comparable Earnings per Share, Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA), Comparable EBITDA, Earnings Before Interest and Taxes (EBIT), Comparable EBIT, Comparable Interest Expense, Comparable Interest Income and Other, Comparable Income Taxes and Funds Generated from Operations in this news release. These measures do not have any standardized meaning prescribed by Canadian generally accepted accounting principles (GAAP). They are, therefore, considered to be non-GAAP measures and may not be comparable to similar measures presented by other entities. Management of TransCanada uses these non-GAAP measures to improve its ability to compare financial results among reporting periods and to enhance its understanding of operating performance, liquidity and ability to generate funds to finance operations. These non-GAAP measures are also provided to readers as additional information on TransCanada's operating performance, liquidity and ability to generate funds to finance operations.
EBITDA is an approximate measure of the Company's pre-tax operating cash flow and is generally used to better measure performance and evaluate trends of individual assets. EBITDA comprises earnings before deducting interest and other financial charges, income taxes, depreciation and amortization, net income attributable to non-controlling interests and preferred share dividends. EBIT is a measure of the Company's earnings from ongoing operations and is generally used to better measure performance and evaluate trends within each segment. EBIT comprises earnings before deducting interest and other financial charges, income taxes, net income attributable to non-controlling interests and preferred share dividends.
Comparable Earnings, Comparable EBITDA, Comparable EBIT, Comparable Interest Expense, Comparable Interest Income and Other, and Comparable Income Taxes comprise Net Income Attributable to Common Shares, EBITDA, EBIT, Interest Expense, Interest Income and Other, and Income Taxes Expense, respectively, adjusted for specific items that are significant but are not reflective of the Company's underlying operations in the period. Specific items are subjective, however, management uses its judgement and informed decision-making when identifying items to be excluded in calculating these non-GAAP measures, some of which may recur. Specific items may include but are not limited to certain fair value adjustments relating to risk management activities, income tax refunds and adjustments, gains or losses on sales of assets, legal and bankruptcy settlements, and write-downs of assets and investments.
The table in the Non-GAAP Measures section of the Management's Discussion and Analysis presents a reconciliation of these non-GAAP measures to Net Income Attributable to Common Shares. Comparable Earnings per Share is calculated by dividing Comparable Earnings by the weighted average number of common shares outstanding for the period.
Funds Generated from Operations comprise Net Cash Provided by Operations before changes in operating working capital and allows management to better measure consolidated operating cash flow, excluding fluctuations from working capital balances which may not necessarily be reflective of underlying operations in the same period. A reconciliation of Funds Generated from Operations to Net Cash Provided by Operations is presented in the Second Quarter 2011 Financial Highlights table in this news release.
Second Quarter 2011 Financial Highlights
Operating Results
Three months ended Six months ended
(unaudited) June 30 June 30
(millions of dollars) 2011 2010 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenues 2,143 1,923 4,386 3,878
Comparable EBITDA(1) 1,139 928 2,364 1,929
Net Income Attributable to
Controlling Interests 367 295 796 598
Net Income Attributable to Common
Shares 353 285 768 581
Comparable Earnings(1) 357 275 782 603
Cash Flows
Funds generated from operations(1) 892 935 1,811 1,658
Decrease/(increase) in operating
working capital 8 (310) 98 (201)
----------------------------------------
Net cash provided by operations 900 625 1,909 1,457
----------------------------------------
----------------------------------------
Capital Expenditures 655 992 1,439 2,268
----------------------------------------
----------------------------------------
Common Share Statistics
Three months ended Six months ended
June 30 June 30
(unaudited) 2011 2010 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net Income per Share - Basic $ 0.50 $ 0.41 $ 1.10 $ 0.84
Comparable Earnings per Share(1) $ 0.51 $ 0.40 $ 1.12 $ 0.87
Dividends Declared per Share $ 0.42 $ 0.40 $ 0.84 $ 0.80
Basic Common Shares Outstanding
(millions)
Average for the period 702 689 700 688
End of period 703 690 703 690
----------------------------------------
----------------------------------------
(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 July 28, 2011 should be read in conjunction with the accompanying unaudited Consolidated Financial Statements of TransCanada Corporation (TransCanada or the Company) for the three and six months ended June 30, 2011. In 2011, the Company will prepare its consolidated financial statements in accordance with Canadian generally accepted accounting principles (GAAP) as defined in Part V of the Canadian Institute of Chartered Accountants (CICA) Handbook, which is discussed further in the Changes in Accounting Policies section in this MD&A. This MD&A should also be read in conjunction with the audited Consolidated Financial Statements and notes thereto, and the MD&A contained in TransCanada's 2010 Annual Report for the year ended December 31, 2010. Additional information relating to TransCanada, including the Company's Annual Information Form and other continuous disclosure documents, is available on SEDAR at 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), and operating and financial results, and expected impact of future commitments and contingent liabilities. All forward-looking statements reflect TransCanada's beliefs and assumptions based on information available at the time the statements were made. Actual results or events may differ from those predicted in these forward-looking statements. Factors that could cause actual results or events to differ materially from current expectations include, among others, the ability of TransCanada to successfully implement its strategic initiatives and whether such strategic initiatives will yield the expected benefits, the operating performance of the Company's pipeline and energy assets, the availability and price of energy commodities, capacity payments, regulatory processes and decisions, changes in environmental and other laws and regulations, competitive factors in the pipeline and energy sectors, construction and completion of capital projects, labour, equipment and material costs, access to capital markets, interest and currency exchange rates, technological developments and economic conditions in North America. By its nature, forward-looking information is subject to various risks and uncertainties, including those material risks discussed in the Financial Instruments and Risk Management section in this MD&A, which could cause TransCanada's actual results and experience to differ materially from the anticipated results or expectations expressed. Additional information on these and other factors is available in the reports filed by TransCanada with Canadian securities regulators and with the U.S. Securities and Exchange Commission (SEC).
Readers are cautioned not to place undue reliance on this forward-looking information, which is given as of the date it is expressed in this MD&A or otherwise specified, and not to use future-oriented information or financial outlooks for anything other than their intended purpose. TransCanada undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, except as required by law.
Non-GAAP Measures
TransCanada uses the measures Comparable Earnings, Comparable Earnings per Share, Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA), Comparable EBITDA, Earnings Before Interest and Taxes (EBIT), Comparable EBIT, Comparable Interest Expense, Comparable Interest Income and Other, Comparable Income Taxes and Funds Generated from Operations in this MD&A. These measures do not have any standardized meaning prescribed by GAAP. They are, therefore, considered to be non-GAAP measures and may not be comparable to similar measures presented by other entities. Management of TransCanada uses these non-GAAP measures to improve its ability to compare financial results among reporting periods and to enhance its understanding of operating performance, liquidity and ability to generate funds to finance operations. These non-GAAP measures are also provided to readers as additional information on TransCanada's operating performance, liquidity and ability to generate funds to finance operations.
EBITDA is an approximate measure of the Company's pre-tax operating cash flow and is generally used to better measure performance and evaluate trends of individual assets. EBITDA comprises earnings before deducting interest and other financial charges, income taxes, depreciation and amortization, net income attributable to non-controlling interests and preferred share dividends. EBIT is a measure of the Company's earnings from ongoing operations and is generally used to better measure performance and evaluate trends within each segment. EBIT comprises earnings before deducting interest and other financial charges, income taxes, net income attributable to non-controlling interests and preferred share dividends.
Comparable Earnings, Comparable EBITDA, Comparable EBIT, Comparable Interest Expense, Comparable Interest Income and Other, and Comparable Income Taxes comprise Net Income Attributable to Common Shares, EBITDA, EBIT, Interest Expense, Interest Income and Other, and Income Taxes Expense, respectively, adjusted for specific items that are significant but are not reflective of the Company's underlying operations in the period. Specific items are subjective, however, management uses its judgement and informed decision-making when identifying items to be excluded in calculating these non-GAAP measures, some of which may recur. Specific items may include but are not limited to certain fair value adjustments relating to risk management activities, income tax refunds and adjustments, gains or losses on sales of assets, legal and bankruptcy settlements, and write-downs of assets and investments.
The Company engages in risk management activities to reduce its exposure to certain financial and commodity price risks by utilizing instruments such as derivatives. The risk management activities, which TransCanada excludes from Comparable Earnings, provide effective economic hedges but do not meet the specific criteria for hedge accounting treatment and, therefore, changes in their fair values are recorded in Net Income each period. The unrealized gains or losses from changes in the fair value of these derivative contracts and natural gas inventory in storage are not considered to be representative of the underlying operations in the current period or the positive margin that will be realized upon settlement. As a result, these amounts have been excluded in the determination of Comparable Earnings.
The tables below present a reconciliation of these non-GAAP measures to Net Income Attributable to Common Shares. Comparable Earnings per Share is calculated by dividing Comparable Earnings by the weighted average number of common shares outstanding for the period.
Funds Generated from Operations comprise Net Cash Provided by Operations before changes in operating working capital and allows management to better measure consolidated operating cash flow, excluding fluctuations from working capital balances which may not necessarily be reflective of underlying operations in the same period. A reconciliation of Funds Generated from Operations to Net Cash Provided by Operations is presented in the Funds Generated from Operations table in the Liquidity and Capital Resources section in this MD&A.
Reconciliation of Non-GAAP Measures
For the three
months
ended June 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 711 696 153 - 290 254 (15) (22) 1,139 928
Depreciation
and
amortization (244) (251) (34) - (97) (90) (4) - (379) (341)
-------------------------------------------------------------
Comparable EBIT 467 445 119 - 193 164 (19) (22) 760 587
------------------------------------------------
------------------------------------------------
Other Income Statement Items
Comparable interest expense (236) (187)
Interest expense of joint ventures (11) (15)
Comparable interest income and other 26 (18)
Comparable income taxes (140) (60)
Net income attributable to non-controlling interests (28) (22)
Preferred share dividends (14) (10)
-------------
Comparable Earnings 357 275
Specific item (net of tax):
Risk management activities(1) (4) 10
-------------
Net Income Attributable to Common Shares 353 285
-------------
-------------
For the three months ended June 30
(unaudited) (millions of dollars except per share amounts) 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Comparable Interest Expense (236) (187)
Specific item:
Risk management activities(1) 1 -
-------------
Interest Expense (235) (187)
-------------
-------------
Comparable Interest Income and Other 26 (18)
Specific item:
Risk management activities(1) (3) -
-------------
Interest Income and Other 23 (18)
-------------
-------------
Comparable Income Taxes (140) (60)
Specific item:
Income taxes attributable to risk management activities(1) 1 (5)
-------------
Income Taxes Expense (139) (65)
-------------
-------------
Comparable Earnings per Share $0.51 $0.40
Specific items (net of tax):
Risk management activities (0.01) 0.01
-------------
Net Income per Share $0.50 $0.41
-------------
-------------
(1) For the three months ended June 30
(unaudited) (millions of dollars) 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Risk Management Activities Gains/(Losses):
U.S. Power derivatives 1 9
Natural Gas Storage proprietary inventory and derivatives (4) 6
Interest rate derivatives 1 -
Foreign exchange derivatives (3) -
Income taxes attributable to risk management activities 1 (5)
-------------
Risk Management Activities (4) 10
-------------
-------------
For the six
months
ended June 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 1,507 1,464 252 - 644 513 (39) (48) 2,364 1,929
Depreciation
and
amortization (488) (504) (57) - (197) (180) (7) - (749) (684)
-------------------------------------------------------------
Comparable
EBIT 1,019 960 195 - 447 333 (46) (48) 1,615 1,245
------------------------------------------------
------------------------------------------------
Other Income Statement Items
Comparable interest expense (446) (369)
Interest expense of joint ventures (27) (31)
Comparable interest income and other 57 6
Comparable income taxes (325) (178)
Net income attributable to non-controlling interests (64) (53)
Preferred share dividends (28) (17)
-------------
Comparable Earnings 782 603
Specific item (net of tax):
Risk management activities(1) (14) (22)
-------------
Net Income Attributable to Common Shares 768 581
-------------
-------------
For the six months ended June 30
(unaudited) (millions of dollars except per share amounts) 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Comparable Interest Expense (446) (369)
Specific item:
Risk management activities(1) - -
-------------
Interest Expense (446) (369)
-------------
-------------
Comparable Interest Income and Other 57 6
Specific item:
Risk management activities(1) (1) -
-------------
Interest Income and Other 56 6
-------------
-------------
Comparable Income Taxes (325) (178)
Specific item:
Income taxes attributable to risk management activities(1) 8 12
-------------
Income Taxes Expense (317) (166)
-------------
-------------
Comparable Earnings per Share $1.12 $0.87
Specific items (net of tax):
Risk management activities (0.02)(0.03)
-------------
Net Income per Share $1.10 $0.84
-------------
-------------
(1) For the six months ended June 30
(unaudited)(millions of dollars) 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Risk Management Activities (Losses)/Gains:
U.S. Power derivatives (12) (19)
Natural Gas Storage proprietary inventory and derivatives (9) (15)
Foreign exchange derivatives (1) -
Income taxes attributable to risk management activities 8 12
-------------
Risk Management Activities (14) (22)
-------------
-------------
Consolidated Results of Operations
TransCanada's Net Income Attributable to Controlling Interests in second quarter 2011 was $367 million and Net Income Attributable to Common Shares was $353 million or $0.50 per share compared to $295 million and $285 million or $0.41 per share, respectively, in second quarter 2010.
Comparable Earnings in second quarter 2011 were $357 million or $0.51 per share compared to $275 million or $0.40 per share for the same period in 2010. Comparable Earnings in second quarter 2011 excluded net unrealized after-tax losses of $4 million ($5 million pre-tax) (2010 - gains of $10 million after tax ($15 million pre-tax)) resulting from changes in the fair value of certain risk management activities.
Comparable Earnings increased $82 million or $0.11 per share in second quarter 2011 compared to the same period in 2010 and reflected the following:
-- increased Natural Gas Pipelines Comparable EBIT primarily due to higher
earnings from ANR and the Alberta System, and incremental earnings from
Bison and Guadalajara which were placed in service in January 2011 and
June 2011, respectively, partially offset by the negative impact of a
weaker U.S. dollar on U.S. operations and increased operations,
maintenance and administrative (OM&A) costs;
-- Oil Pipelines Comparable EBIT as the Company commenced recording
earnings from Keystone in first quarter 2011;
-- increased Energy Comparable EBIT primarily due to higher volumes and
realized prices at Bruce A, incremental earnings from the start-up of
Halton Hills in September 2010 and Coolidge in May 2011, and higher
capacity payments and realized prices in U.S. Power, partially offset by
lower prices for Western Power and lower volumes and realized prices at
Bruce B;
-- increased Comparable Interest Expense primarily due to decreased
capitalized interest for Keystone and Halton Hills, and incremental
interest expense on new debt issues in 2010, partially offset by
realized gains in second quarter 2011 compared to losses in second
quarter 2010 on derivatives used to manage the Company's exposure to
fluctuating interest rates, and the positive impact of a weaker U.S.
dollar on U.S. dollar-denominated interest expense;
-- increased Comparable Interest Income and Other, which included
realized gains in second quarter 2011 compared to losses in second
quarter 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 second quarter 2011 compared to second quarter 2010 and
higher positive income tax adjustments in second quarter 2010.
TransCanada's Net Income Attributable to Controlling Interests in the first six months of 2011 was $796 million and Net Income Attributable to Common Shares was $768 million or $1.10 per share compared to $598 million and $581 million or $0.84 per share, respectively, for the same period in 2010.
Comparable Earnings in the first six months of 2011 were $782 million or $1.12 per share compared to $603 million or $0.87 per share for the same period in 2010. Comparable Earnings for the first six months of 2011 excluded net unrealized after-tax losses of $14 million ($22 million pre-tax) (2010 - after-tax losses of $22 million ($34 million pre-tax)) resulting from changes in the fair value of certain risk management activities.
Comparable Earnings increased $179 million or $0.25 per share in the first six months of 2011 compared to the same period in 2010 and reflected the following:
-- 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, higher earnings from the
Alberta System and reduced business development costs relating to the
Alaska Pipeline Project, partially offset by the negative impact of a
weaker U.S. dollar and increased OM&A costs;
-- Oil Pipelines Comparable EBIT as the Company commenced recording
earnings from Keystone in first quarter 2011;
-- increased EBIT from Energy primarily due to higher volumes and lower
operating expenses due to reduced outage days, and higher realized
prices at Bruce A, higher overall realized prices at Western Power,
incremental earnings from the start-up of Halton Hills in September
2010, Coolidge in May 2011 and Kibby Wind in October 2011, and higher
revenues from U.S. Power, partially offset by lower realized prices and
reduced volumes at Bruce B, and decreased proprietary and third-party
storage revenues for Natural Gas Storage;
-- increased Comparable Interest Expense primarily due to decreased
capitalized interest for Keystone and Halton Hills, and incremental
interest expense on new debt issues in 2010, partially offset by
realized gains in 2011 compared to losses in 2010 on derivatives used to
manage the Company's exposure to fluctuating interest rates, the
positive impact of a weaker U.S. dollar on U.S. dollar-denominated
interest expense and Canadian debt maturities in 2011 and 2010;
-- increased Comparable Interest Income and Other, which included realized
gains in 2011 compared to losses in 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.
Further discussion of the significant financial results in the first three and six months in 2011 is included in the Natural Gas Pipelines, Oil Pipelines, Energy and Other Income Statement Items sections in this MD&A.
U.S. Dollar-Denominated Balances
On a consolidated basis, the impact of changes in the value of the U.S. dollar on U.S. operations is partially offset by other U.S. dollar-denominated items as set out in the following table. The resultant pre-tax net exposure is managed using derivatives, further reducing the Company's exposure to changes in Canadian-U.S. foreign exchange rates. The average U.S. dollar to Canadian dollar exchange rate for the three and six months ended June 30, 2011 was 0.97 and 0.98, respectively (2010 - 1.03 and 1.03, respectively).
Summary of Significant U.S. Dollar-Denominated Amounts
Three months ended Six months ended
(unaudited) June 30 June 30
(millions of U.S. dollars, pre-tax) 2011 2010 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
U.S. Natural Gas Pipelines
Comparable EBIT(1) 175 147 424 373
U.S. Oil Pipelines Comparable
EBIT(1) 81 - 132 -
U.S. Power Comparable EBIT(1) 65 42 97 81
Interest on U.S. dollar-denominated
long-term debt (180) (163) (362) (322)
Capitalized interest on U.S capital
expenditures 25 65 72 133
U.S. non-controlling interests and
other (44) (36) (95) (81)
----------------------------------------
122 55 268 184
----------------------------------------
----------------------------------------
(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 $467 million and $1.0 billion in
the three and six months ended June 30, 2011, respectively, compared to $445
million and $960 million, respectively, for the same periods in 2010.
Natural Gas Pipelines Results
Three months ended Six months ended
(unaudited) June 30 June 30
(millions of dollars) 2011 2010 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Canadian Natural Gas Pipelines
Canadian Mainline 267 263 532 528
Alberta System 181 176 366 351
Foothills 32 35 65 68
Other (TQM, Ventures LP) 13 14 25 27
----------------------------------------
Canadian Natural Gas Pipelines
Comparable EBITDA(1) 493 488 988 974
Depreciation and amortization (181) (185) (361) (368)
----------------------------------------
Canadian Natural Gas Pipelines
Comparable EBIT(1) 312 303 627 606
----------------------------------------
U.S. Natural Gas Pipelines (in U.S.
dollars)
ANR 70 59 181 174
GTN(2) 31 40 76 83
Great Lakes(3) 25 25 55 57
PipeLines LP(4)(5) 23 22 50 47
Iroquois 16 17 35 35
Bison(2)(6) 14 - 27 -
Portland(5)(7) 3 1 13 11
International (Tamazunchale,
Guadalajara TransGas, Gas
Pacifico/INNERGY)(8) 15 14 25 24
General, administrative and support
costs(9) (2) (3) (4) (9)
Non-controlling interests(5) 46 36 96 82
----------------------------------------
U.S. Natural Gas Pipelines
Comparable EBITDA(1) 241 211 554 504
Depreciation and amortization (66) (64) (130) (131)
----------------------------------------
U.S. Natural Gas Pipelines
Comparable EBIT(1) 175 147 424 373
Foreign exchange (5) 5 (9) 14
----------------------------------------
U.S. Natural Gas Pipelines
Comparable EBIT(1)(in Canadian
dollars) 170 152 415 387
----------------------------------------
Natural Gas Pipelines Business
Development Comparable EBITDA(1) (15) (10) (23) (33)
----------------------------------------
Natural Gas Pipelines Comparable
EBIT(1) 467 445 1,019 960
----------------------------------------
----------------------------------------
Summary:
Natural Gas Pipelines Comparable
EBITDA(1) 711 696 1,507 1,464
Depreciation and amortization (244) (251) (488) (504)
----------------------------------------
Natural Gas Pipelines Comparable
EBIT(1) 467 445 1,019 960
----------------------------------------
----------------------------------------
(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 the Company'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's operations since January 2011.
(7) Represents the Company'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 the Company's pipelines.
Net Income for Wholly Owned Canadian Natural Gas Pipelines
Three months ended Six months ended
(unaudited) June 30 June 30
(millions of dollars) 2011 2010 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Canadian Mainline 63 64 125 130
Alberta System 50 37 98 75
Foothills 6 7 12 13
----------------------------------------
----------------------------------------
Canadian Natural Gas Pipelines
Canadian Mainline's net income for the three and six months ended June 30, 2011 decreased $1 million and $5 million, respectively, compared to the same periods in 2010 primarily due to a lower rate of return on common equity (ROE), as determined by the National Energy Board (NEB), of 8.08 per cent in 2011 compared to 8.52 per cent in 2010, as well as a lower average investment base. The impact of the lower ROE and average investment base was partially offset by higher incentive earnings in 2011.
Canadian Mainline's Comparable EBITDA for the three and six months ended June 30, 2011 of $267 million and $532 million, respectively, increased $4 million compared to each of the same periods in 2010. An increase in revenues as a result of higher incentive earnings and higher flow-through costs was partially offset by a lower overall return, associated with the reduced ROE and financial charges, on a reduced average investment base. The flow-through costs do not impact net income and increased primarily due to higher income taxes.
The Alberta System's net income was $50 million in second quarter 2011 and $98 million for the first six months of 2011 compared to $37 million and $75 million for the same periods in 2010. The increases reflect an ROE of 9.70 per cent on 40 per cent deemed common equity approved by the NEB in September 2010 as part of the Company's 2010 - 2012 Revenue Requirement Settlement application. Net income in 2010 reflected an ROE of 8.75 per cent on 35 per cent deemed common equity.
The Alberta System's Comparable EBITDA was $181 million in second quarter 2011 and $366 million for the first six months of 2011 compared to $176 million and $351 million for the same periods in 2010. The increases were primarily due to the increased ROE included in the 2010 - 2012 Revenue Requirement Settlement.
U.S. Natural Gas Pipelines
ANR's Comparable EBITDA for the three and six months ended June 30, 2011 was US$70 million and US$181 million, respectively, compared to US$59 million and US$174 million for the same periods in 2010. The increases were primarily due to higher transportation and storage revenues, a settlement with a counterparty and increased incidental commodity sales, partially offset by higher OM&A costs.
GTN's Comparable EBITDA for the three and six months ended June 30, 2011 was US$31 million and US$76 million, respectively, compared to US$40 million and US$83 million for the same periods in 2010. The decreases were primarily due to TransCanada's sale of 25 per cent of GTN to PipeLines LP in May 2011.
The Bison pipeline was placed in service in January 2011. TransCanada's portion of Comparable EBITDA was US$14 million and US$27 million for the three and six months ended June 30, 2011, respectively. EBIDTA reflects TransCanada's sale of 25 per cent of Bison to PipeLines LP in May 2011.
Comparable EBITDA for the remainder of the U.S. Natural Gas Pipelines was US$157 million and US$346 million for the three and six months ended June 30, 2011, respectively, compared to US$152 million and US$333 million for the same periods in 2010. The increases were primarily due to higher revenues for Northern Border, lower general, administrative and support costs, and incremental earnings from the Guadalajara pipeline which was placed in service on June 15, 2011.
Depreciation
Natural Gas Pipelines' depreciation decreased $7 million and $16 million for the three and six months ended June 30, 2011, respectively, compared to the same periods in 2010. The decreases were primarily due to lower depreciation rates included in the Great Lakes and Alberta System rate settlements, and the effect of a weaker U.S. dollar on U.S. asset depreciation, partially offset by incremental depreciation for Bison.
Business Development
Natural Gas Pipelines' Business Development Comparable EBITDA loss increased $5 million and decreased $10 million in the three and six months ended June 30, 2011, respectively, compared to the same periods in 2010. Business development costs increased in second quarter 2011 compared to second quarter 2010 primarily due to greater activity in 2011 for the Alaska Pipeline Project, partially offset by a 90 per cent reimbursement by the State of Alaska for eligible project costs effective July 31, 2010 versus a 50 per cent reimbursement prior to this date. Business development costs in the first six months of 2011 were lower primarily due to the increased reimbursement by the State of Alaska. Project applicable expenses and reimbursements are shared proportionately with ExxonMobil, TransCanada's joint venture partner in the Alaska Pipeline Project. The decrease in business development costs in the first six months of 2011 was partially offset by a levy charged by the NEB in March 2011 to recover the Aboriginal Pipeline Group's proportionate share of costs relating to the Mackenzie Gas Project hearings.
Operating Statistics
Canadian Alberta
Six months ended June 30 Mainline(1) System(2) Foothills ANR(3)
(unaudited) 2011 2010 2011 2010 2011 2010 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Average investment base
(millions of dollars) 6,328 6,572 4,993 4,975 617 666 n/a n/a
Delivery volumes (Bcf)
Total 1,059 844 1,788 1,723 630 680 870 795
Average per day 5.9 4.7 9.9 9.5 3.5 3.8 4.8 4.4
------------------------------------------------
------------------------------------------------
(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 six months ended June 30, 2011 were 643 billion cubic feet (Bcf)
(2010 - 645 Bcf); average per day was 3.6 Bcf (2010 - 3.6 Bcf).
(2) Field receipt volumes for the Alberta System for the six months ended
June 30, 2011 were 1,733 Bcf (2010 - 1,740 Bcf); average per day was 9.6
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
In the three and five months ended June 30, 2011, the Company recorded $119 million and $195 million, respectively, of Comparable EBIT related to the Oil Pipelines segment. In late January 2011, work was completed to allow Keystone to increase its operating pressure following the NEB's decision to remove the maximum operating pressure restriction along the conversion section of the system in December 2010. At the beginning of February 2011, the Company commenced recording EBITDA for the Wood River/Patoka section of Keystone and for the Cushing Extension, which was placed in service at that time.
Oil Pipelines Results
Three months ended Five months ended
For the period February 1 to June 30 June 30 June 30
(unaudited)(millions of dollars) 2011 2011
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Canadian Oil Pipelines Comparable EBITDA(1) 55 90
Depreciation and amortization (13) (22)
------------------------------
Canadian Oil Pipelines Comparable EBIT(1) 42 68
------------------------------
U.S. Oil Pipelines Comparable EBITDA(1) (in
U.S. dollars) 103 168
Depreciation and amortization (22) (36)
------------------------------
U.S. Oil Pipelines Comparable EBIT(1) 81 132
Foreign exchange (3) (4)
------------------------------
U.S. Oil Pipelines Comparable EBIT(1) (in
Canadian dollars) 78 128
------------------------------
Oil Pipelines Business Development Comparable
EBITDA(1) (1) (1)
------------------------------
Oil Pipelines Comparable EBIT(1) 119 195
------------------------------
------------------------------
Summary:
Oil Pipelines Comparable EBITDA(1) 153 252
Depreciation and amortization (34) (57)
------------------------------
Oil Pipelines Comparable EBIT(1) 119 195
------------------------------
------------------------------
(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 Five months
ended ended
For the period February 1 to June 30 June 30 June 30
(unaudited) 2011 2011
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Delivery volumes (thousands of barrels)(1)
Total 30,167 52,633
Average per day 332 351
------------------------------
------------------------------
(1) Delivery volumes reflect physical deliveries.
Energy
Energy's Comparable EBIT was $193 million and $447 million for the three and
six months ended June 30, 2011, respectively, compared to $164 million and
$333 million, respectively, for the same periods in 2010.
Energy Results
Three months ended Six months ended
(unaudited) June 30 June 30
(millions of dollars) 2011 2010 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Canadian Power
Western Power(1) 74 85 194 127
Eastern Power(2) 71 46 151 98
Bruce Power 56 47 133 110
General, administrative and support
costs (9) (5) (17) (15)
----------------------------------------
Canadian Power Comparable EBITDA(3) 192 173 461 320
Depreciation and amortization (69) (58) (136) (118)
----------------------------------------
Canadian Power Comparable EBIT(3) 123 115 325 202
----------------------------------------
U.S. Power (in U.S. dollars)
Northeast Power(4) 99 78 170 151
General, administrative and support
costs (10) (9) (19) (18)
----------------------------------------
U.S. Power Comparable EBITDA(3) 89 69 151 133
Depreciation and amortization (24) (27) (54) (52)
----------------------------------------
U.S. Power Comparable EBIT(3) 65 42 97 81
Foreign exchange (3) 2 (3) 3
----------------------------------------
U.S. Power Comparable EBIT(3) (in
Canadian dollars) 62 44 94 84
----------------------------------------
Natural Gas Storage
Alberta Storage 21 20 52 73
General, administrative and support
costs (3) (2) (5) (4)
----------------------------------------
Natural Gas Storage Comparable
EBITDA(3) 18 18 47 69
Depreciation and amortization (4) (4) (8) (8)
----------------------------------------
Natural Gas Storage Comparable
EBIT(3) 14 14 39 61
----------------------------------------
Energy Business Development
Comparable EBITDA(3) (6) (9) (11) (14)
----------------------------------------
Energy Comparable EBIT(3) 193 164 447 333
----------------------------------------
----------------------------------------
Summary:
Energy Comparable EBITDA(3) 290 254 644 513
Depreciation and amortization (97) (90) (197) (180)
----------------------------------------
Energy Comparable EBIT(3) 193 164 447 333
----------------------------------------
----------------------------------------
(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 Six months ended
(unaudited) June 30 June 30
(millions of dollars) 2011 2010 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenues
Western power 182 202 461 366
Eastern power 113 65 231 132
Other(3) 18 15 41 37
----------------------------------------
313 282 733 535
----------------------------------------
Commodity Purchases Resold
Western power (101) (99) (244) (205)
Other(4) (4) (7) (9) (12)
----------------------------------------
(105) (106) (253) (217)
----------------------------------------
Plant operating costs and other (63) (45) (135) (93)
General, administrative and support
costs (9) (5) (17) (15)
----------------------------------------
Comparable EBITDA(1) 136 126 328 210
Depreciation and amortization (41) (32) (80) (69)
----------------------------------------
Comparable EBIT(1) 95 94 248 141
----------------------------------------
----------------------------------------
(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 Six months ended
June 30 June 30
(unaudited) 2011 2010 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Sales Volumes (GWh)
Supply
Generation
Western Power(1) 626 594 1,307 1,179
Eastern Power(2) 770 395 1,848 824
Purchased
Sundance A & B and Sheerness PPAs(3) 1,855 2,459 3,960 5,114
Other purchases 174 73 376 222
----------------------------------------
3,425 3,521 7,491 7,339
----------------------------------------
----------------------------------------
Sales
Contracted
Western Power(1) 2,038 2,573 4,307 4,842
Eastern Power(2) 770 395 1,848 840
Spot
Western Power 617 553 1,336 1,657
----------------------------------------
3,425 3,521 7,491 7,339
----------------------------------------
----------------------------------------
Plant Availability(4)
Western Power(1)(5) 97% 94% 97% 94%
Eastern Power(2)(6) 92% 97% 95% 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 $74 million and Power Revenues of $182 million in second quarter 2011 decreased $11 million and $20 million, respectively, compared to the same period in 2010, primarily due to lower realized power prices in Alberta, partially offset by incremental earnings from Coolidge, which went into service under a 20-year power purchase arrangement (PPA) in May 2011. Average spot market power prices in Alberta decreased 35 per cent to $52 per megawatt hour (MWh) in second quarter 2011 compared to $80 per MWh in second quarter 2010 when certain unplanned plant and transmission outages resulted in significantly higher spot prices.
Western Power's Comparable EBITDA of $194 million and Power Revenues of $461 million in the first six months of 2011 increased $67 million and $95 million, respectively, compared to the same period in 2010 primarily due to higher overall realized prices and incremental earnings from Coolidge.
Western Power's Comparable EBITDA in the three and six months ended June 30, 2011 included $12 million and $51 million, respectively, of accrued earnings from the Sundance A PPA, the revenues and costs of which have been recorded as though Sundance A Units 1 and 2 were on normal plant outages. Refer to the Recent Developments section in this MD&A for further discussion regarding the Sundance A outage.
Western Power's Commodity Purchases Resold increased $39 million for the six months ended June 30, 2011 compared to the same period in 2010 primarily due to higher volumes at Sheerness and increased retail contracts.
Eastern Power's Comparable EBITDA of $71 million and $151 million for the three and six months ended June 30, 2011, respectively, increased $25 million and $53 million, respectively, compared to the same periods in 2010. Power Revenues of $113 million and $231 million for the three and six months ended June 30, 2011, respectively, increased $48 million and $99 million, respectively, compared to the same periods in 2010. The increases were primarily due to incremental earnings from Halton Hills, which went into service in September 2010.
Plant Operating Costs and Other of $63 million and $135 million for the three and six months ended June 30, 2011, respectively, which includes fuel gas consumed in power generation, increased $18 million and $42 million, respectively, compared to the same periods in 2010 primarily due to incremental fuel consumed at Halton Hills.
Depreciation and amortization increased $9 million and $11 million for the three and six months ended June 30, 2011, respectively, compared to the same periods in 2010 primarily due to incremental depreciation from Halton Hills and Coolidge.
Western Power manages the sale of its supply volumes on a portfolio basis. A portion of its supply is sold into the spot market to assure supply in the event of an unexpected plant outage. The overall amount of spot market volumes sold is dependent upon the ability to transact in forward sales markets at acceptable contract terms. This approach to portfolio management helps to minimize costs in situations where Western Power would otherwise have to purchase electricity in the open market to fulfill its contractual sales obligations. Approximately 77 per cent of Western Power sales volumes were sold under contract in second quarter 2011, compared to 82 per cent in second quarter 2010. To reduce its exposure to spot market prices on uncontracted volumes, as at June 30, 2011, Western Power had entered into fixed-price power sales contracts to sell approximately 4,600 gigawatt hours (GWh) for the remainder of 2011 and 7,500 GWh for 2012.
Eastern Power is focused on selling power under long-term contracts. In second quarter 2011 and 2010, 100 per cent of Eastern Power's sales volumes were sold under contract and are expected to continue to be 100 per cent sold under contract for the remainder of 2011 and in 2012.
Bruce Power Results
(TransCanada's proportionate share)
(unaudited) Three months ended Six months ended
(millions of dollars unless June 30 June 30
otherwise indicated) 2011 2010 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenues(1) 202 197 415 422
Operating Expenses (146) (150) (282) (312)
----------------------------------------
Comparable EBITDA(2) 56 47 133 110
----------------------------------------
----------------------------------------
Bruce A Comparable EBITDA(2) 32 10 66 23
Bruce B Comparable EBITDA(2) 24 37 67 87
----------------------------------------
Comparable EBITDA(2) 56 47 133 110
Depreciation and amortization (28) (26) (56) (49)
----------------------------------------
Comparable EBIT(2) 28 21 77 61
----------------------------------------
----------------------------------------
Bruce Power - Other Information
Plant availability
Bruce A 97% 72% 98% 69%
Bruce B 80% 86% 86% 92%
Combined Bruce Power 85% 82% 89% 85%
Planned outage days
Bruce A 8 25 8 60
Bruce B 49 47 70 47
Unplanned outage days
Bruce A 5 22 9 48
Bruce B 19 - 27 6
Sales volumes (GWh)
Bruce A 1,436 1,121 2,936 2,110
Bruce B 1,760 1,944 3,792 4,099
----------------------------------------
3,196 3,065 6,728 6,209
----------------------------------------
Results per MWh
Bruce A power revenues $ 66 $ 65 $ 66 $ 64
Bruce B power revenues(3) $ 55 $ 59 $ 54 $ 58
Combined Bruce Power revenues $ 59 $ 60 $ 58 $ 60
----------------------------------------
----------------------------------------
(1) Revenues include Bruce A's fuel cost recoveries of $7 million and $15
million for the three and six months ended June 30, 2011, respectively
(2010 - $9 million and $14 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 for the three and six months ended June 30, 2011 of $32 million and $66 million, respectively, increased from $10 million and $23 million, respectively, in the same periods in 2010 as a result of higher volumes and lower operating expenses due to lower planned and unplanned outage days. Results for the six months ended June 30, 2010 included a payment made from Bruce B to Bruce A regarding 2009 amendments to a long-term agreement with the Ontario Power Authority (OPA). The net positive impact reflected TransCanada's higher percentage ownership interest in Bruce A.
TransCanada's proportionate share of Bruce B's Comparable EBITDA for the three and six months ended June 30, 2011 of $24 million and $67 million, respectively, decreased from $37 million and $87 million, respectively, in the same periods in 2010 primarily due to lower volumes and higher operating costs due to increased outage days, as well as lower realized prices resulting from the expiration of fixed-price contracts at higher prices. Results for the six months ended June 30, 2010 included the above-noted payment in first quarter 2010 to Bruce A.
Under a contract with the OPA, all output from Bruce A in second quarter 2011 was sold at a fixed price of $66.33 per MWh (before recovery of fuel costs from the OPA) compared to $64.71 per MWh in second quarter 2010. Also under a contract with the OPA, all output from the Bruce B units was subject to a floor price of $50.18 per MWh in second quarter 2011 compared to $48.96 per MWh in second quarter 2010. Both the Bruce A and Bruce B contract prices are adjusted annually for inflation on April 1.
Amounts received under the Bruce B floor price mechanism within a calendar year are subject to repayment if the monthly average spot price exceeds the floor price. With respect to 2011, TransCanada currently expects spot prices to be less than the floor price for the remainder of the year, therefore no amounts recorded in revenues in the first six months of 2011 are expected to be repaid.
Bruce B enters into fixed-price contracts whereby Bruce B receives or pays the difference between the contract price and the spot price. Bruce B's realized price decreased to $55 per MWh and $54 per MWh for the three and six months ended June 30, 2011, respectively, a decrease of $4 per MWh from each of the same periods in 2010, and reflected revenues recognized from both the floor price mechanism and contract sales. The decreases were a result of the majority of higher-priced contracts entered into in previous years having expired by the end of December 2010. As the remainder of these higher-priced contracts continue to expire, a further reduction in realized prices at Bruce B in future periods is expected.
The overall plant availability percentage in 2011 is expected to be in the mid-80s for the two operating Bruce A units and in the mid-80s for the four Bruce B units. Bruce B commenced an approximately three week outage on Unit 6 in late July 2011. For further information on Bruce Power's planned maintenance outages, refer to the MD&A in TransCanada's 2010 Annual Report.
As at June 30, 2011, Bruce A had incurred approximately $4.4 billion in costs for the refurbishment and restart of Units 1 and 2, and approximately $0.3 billion for the refurbishment of Units 3 and 4.
U.S. Power Comparable EBIT(1)(2)
Three months ended Six months ended
(unaudited) June 30 June 30
(millions of U.S. dollars) 2011 2010 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenues
Power(3) 224 237 479 469
Capacity 74 66 113 106
Other(4) 13 15 43 40
----------------------------------------
311 318 635 615
Commodity purchases resold (84) (112) (215) (248)
Plant operating costs and other(4) (128) (128) (250) (216)
General, administrative and support
costs (10) (9) (19) (18)
----------------------------------------
Comparable EBITDA(1) 89 69 151 133
Depreciation and amortization (24) (27) (54) (52)
----------------------------------------
Comparable EBIT(1) 65 42 97 81
----------------------------------------
----------------------------------------
(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 Six months ended
June 30 June 30
(unaudited) 2011 2010 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Physical Sales Volumes (GWh)
Supply
Generation 1,941 1,789 3,232 2,680
Purchased 1,181 2,061 3,120 4,547
----------------------------------------
3,122 3,850 6,352 7,227
----------------------------------------
----------------------------------------
Plant Availability(2)(3) 86% 92% 84% 89%
----------------------------------------
----------------------------------------
(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 three and six months ended June 30,
2011 due to the impact of planned outages at Ravenswood and OSP.
U.S Power's Comparable EBITDA of US$89 million and US$151 million for the three and six months ended June 30, 2011, respectively, increased US$20 million and US$18 million, respectively, compared to the same periods in 2010. The increases were primarily due to increased capacity revenues, higher realized power prices and incremental earnings from phase two of Kibby Wind which went into service in October 2010.
U.S. Power's Power Revenues of US$224 for the three months ended June 30, 2011 decreased US$13 million compared to the same period in 2010, primarily due to lower physical volumes of power sold, partially offset by higher realized power prices, incremental revenues from the second phase of Kibby Wind, new sales activity in the PJM Interconnection area (PJM) and an increase in the New York commercial customer base. For the six months ended June 30, 2011, U.S. Power's Power Revenues were US$479 million, an increase of US$10 million from the same period in 2010 as a result of higher realized power prices, incremental revenues from the second phase of Kibby Wind and additional revenue from PJM and New York commercial customers, partially offset by lower volumes of power sold.
Capacity Revenues of US$74 million and US$113 million for the three and six months ended June 30, 2011, respectively, increased from US$66 million and US$106 million, respectively, in the same periods in 2010 primarily due to a reduction in forced outage rates at Ravenswood, partially offset by lower capacity prices in the New England power market.
Commodity Purchases Resold of US$84 million and US$215 million for the three and six months ended June 30, 2011, respectively, decreased from US$112 million and US$248 million, respectively, in the same periods in 2010 primarily due to a decrease in the quantity of power purchased for resale, partially offset by higher power prices per MWh purchased.
Plant Operating Costs and Other, including fuel gas consumed in generation, of US$128 million in second quarter 2011, was consistent with second quarter 2010. For the six months ended June 30, 2011, Plant Operating Costs and Other were US$250 million, an increase of US$34 million from the same period in 2010 primarily due to higher fuel costs as a result of increased generation, incremental operating costs from the second phase of Kibby Wind and reduced lease costs related to Ravenswood in 2010.
U.S. Power focuses on selling power under short- and long-term contracts to wholesale, commercial and industrial customers in the New England, New York and PJM power markets. Exposure to fluctuations in spot prices on these power sales commitments are hedged with a combination of forward purchases of power, forward purchases of fuel to generate power and through the use of financial contracts. As at June 30, 2011, approximately 3,100 GWh or 67 per cent of U.S. Power's planned generation is contracted for the remainder of 2011. Planned generation fluctuates depending on hydrology, wind conditions, commodity prices and the resulting dispatch of the assets, and power sales fluctuate based on customer usage. The seasonal nature of the U.S. Power business generally results in higher generation volumes in the summer months.
Natural Gas Storage
Natural Gas Storage's Comparable EBITDA for the three and six month periods ended June 30, 2011, was $18 million and $47 million, respectively, compared to $18 million and $69 million, respectively, for the same periods in 2010. The decrease in Comparable EBITDA in the six months ended June 30, 2011 compared to the same period in 2010 was primarily due to decreased proprietary and third-party storage revenues as a result of lower realized natural gas price spreads.
Other Income Statement Items
Comparable Interest Expense(1)
Three months ended Six months ended
(unaudited) June 30 June 30
(millions of dollars) 2011 2010 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Interest on long-term debt(2)
Canadian dollar-denominated 122 129 244 260
U.S. dollar-denominated 180 163 362 322
Foreign exchange (5) 5 (8) 11
----------------------------------------
297 297 598 593
Other interest and amortization 7 33 13 53
Capitalized interest (68) (143) (165) (277)
----------------------------------------
Comparable Interest Expense(1) 236 187 446 369
----------------------------------------
----------------------------------------
(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 second quarter 2011 increased $49 million to $236 million from $187 million in second quarter 2010. Comparable Interest Expense for the six months ended June 30, 2011 increased $77 million to $446 million from $369 million for the six months ended June 30, 2010. The increases reflected lower capitalized interest for Keystone and Halton Hills as assets were placed into service, and incremental interest expense on debt issues of US$1.25 billion in June 2010 and US$1.0 billion in September 2010. These increases were partially offset by realized gains in 2011 compared to losses in 2010 from derivatives used to manage the Company's exposure to rising interest rates, the positive impact of a weaker U.S. dollar on U.S. dollar-denominated interest and Canadian dollar-denominated debt maturities in 2011 and 2010.
Comparable Interest Income and Other for second quarter 2011 increased $44 million to income of $26 million from an expense of $18 million in second quarter 2010. Comparable Interest Income and Other for the six months ended June 30, 2011 increased $51 million to income of $57 million from income of $6 million for the six months ended June 30, 2010. The increases reflected realized gains in 2011 compared to losses in 2010 on derivatives used to manage the Company's net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income and from the translation of working capital balances due to a weakening of the U.S. dollar.
Comparable Income Taxes were $140 million in second quarter 2011 compared to $60 million for the same period in 2010. Comparable Income Taxes for the six months ended June 30, 2011 were $325 million compared to $178 million for the same period in 2010. The increases were primarily due to higher pre-tax earnings in 2011 compared to 2010 and higher positive income tax adjustments in 2010 compared to 2011.
Liquidity and Capital Resources
TransCanada believes that its financial position remains sound and consistent with recent years as does its ability to generate cash in the short and long term to provide liquidity, maintain financial capacity and flexibility, and provide for planned growth. TransCanada's liquidity is underpinned by predictable cash flow from operations, cash balances on hand and unutilized committed revolving bank lines of US$1.0 billion, $2.0 billion, US$1.0 billion and US$200 million, maturing in November 2011, December 2012, December 2012 and February 2013, respectively. These facilities also support the Company's commercial paper programs. In addition, at June 30, 2011, TransCanada's proportionate share of unutilized capacity on committed bank facilities at TransCanada-operated affiliates was $169 million with maturity dates in 2011 and 2012. As at June 30, 2011, TransCanada had remaining capacity of $1.75 billion, $2.0 billion and US$1.75 billion under its equity, Canadian debt and U.S. debt shelf prospectuses, respectively. TransCanada's liquidity, market and other risks are discussed further in the Risk Management and Financial Instruments section in this MD&A.
At June 30, 2011, the Company held Cash and Cash Equivalents of $468 million compared to $764 million at December 31, 2010. The decrease in Cash and Cash Equivalents was primarily due to expenditures for the Company's capital program, debt repayments and dividend payments, partially offset by increased cash generated from operations.
Operating Activities
Funds Generated from Operations(1)
Three months ended Six months ended
(unaudited) June 30 June 30
(millions of dollars) 2011 2010 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Cash Flows
Funds generated from operations(1) 892 935 1,811 1,658
Decrease/(increase) in operating
working capital 8 (310) 98 (201)
----------------------------------------
Net cash provided by operations 900 625 1,909 1,457
----------------------------------------
----------------------------------------
(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 $275 million and $452 million for the three and six months ended June 30, 2011, respectively, compared to the same periods in 2010, largely as a result of changes in operating working capital. The six months ended June 30, 2011 also reflected an increase in Funds Generated from Operations. Funds Generated from Operations for the three and six months ended June 30, 2011 were $892 million and $1.8 billion, respectively, compared to $935 million and $1.7 billion, respectively, for the same periods in 2010. The decrease for the three months ended June 30, 2011 was primarily due to the second quarter 2010 income tax benefit generated from bonus depreciation for U.S. tax purposes on Keystone assets placed in service in June 2010. Cash generated through earnings increased in second quarter 2011 compared to second quarter 2010 excluding the 2010 income tax benefit from bonus depreciation. The increase for the six months ended June 30, 2011 was primarily due to an increase in cash generated through earnings, partially offset by the 2010 income tax benefit from bonus depreciation.
As at June 30, 2011, TransCanada's current liabilities were $4.6 billion and current assets were $2.8 billion resulting in a working capital deficiency of $1.8 billion. Excluding $1.6 billion of Notes Payable under the Company's commercial paper programs and draws on its line-of-credit facilities, TransCanada's working capital deficiency was $0.2 billion. The Company believes this shortfall can be managed through its ability to generate cash flow from operations as well as its ongoing access to capital markets.
Investing Activities
TransCanada remains committed to executing its remaining $11 billion capital expenditure program. For the three and six months ended June 30, 2011, capital expenditures totalled $0.7 billion and $1.4 billion, respectively (2010 - $1.0 billion and $2.3 billion, respectively), primarily related to the construction of Keystone, the refurbishment and restart of Bruce A Units 1 and 2, and expansion of the Alberta System.
Financing Activities
On July 13, 2011, PipeLines LP entered into a five-year, US$500 million senior syndicated revolving credit facility, maturing July 2016. The proceeds from the credit facility were used to reduce PipeLines LP's term loan and senior revolving credit facility, and repay its bridge loan facility. PipeLines LP's remaining US$300 million term loan matures December 2011.
In June 2011, TCPL retired $60 million of 9.5 per cent Medium-Term Notes and, in January 2011, retired $300 million of 4.3 per cent Medium-Term Notes.
In June 2011, PipeLines LP issued US$350 million of 4.65 per cent Senior Notes due 2021 and cancelled US$175 million of its unsecured syndicated senior credit facility.
In May 2011, PipeLines LP completed a public offering of 7,245,000 common units at a price of US$47.58 per unit, resulting in gross proceeds of approximately US$345 million. TransCanada contributed an additional approximate US$7 million to maintain its general partnership interest and did not purchase any other units. Upon completion of this offering, TransCanada's ownership interest in PipeLines LP decreased from 38.2 per cent to 33.3 per cent. In addition, PipeLines LP made draws of US$61 million on a bridge loan facility and of US$125 million on its senior revolving credit facility.
In June 2011, TCPL filed a $2.0 billion Canadian Medium-Term Notes base shelf prospectus to replace an April 2009 $2.0 billion Canadian Medium-Term Notes base shelf prospectus, which expired in May 2011 and had remaining capacity of $2.0 billion.
The Company believes it has the capacity to fund its existing capital program through internally-generated cash flow, continued access to capital markets and liquidity underpinned by in excess of $4 billion of committed credit facilities. TransCanada's financial flexibility is further bolstered by opportunities for portfolio management, including an ongoing role for PipeLines LP.
Dividends
On July 28, 2011, TransCanada's Board of Directors declared a quarterly dividend of $0.42 per share for the quarter ending September 30, 2011 on the Company's outstanding common shares. The dividend is payable on October 31, 2011 to shareholders of record at the close of business on September 30, 2011. In addition, quarterly dividends of $0.2875 and $0.25 per Series 1 and Series 3 preferred share, respectively, were declared for the quarter ending September 30, 2011. The dividends are payable on September 30, 2011 to shareholders of record at the close of business on August 31, 2011. Furthermore, a quarterly dividend of $0.275 per Series 5 preferred share was declared for the three month period ending October 30, 2011, payable on October 31, 2011 to shareholders of record at the close of business on September 30, 2011.
Commencing with the dividends declared April 28, 2011, common shares purchased with reinvested cash dividends under TransCanada's Dividend Reinvestment and Share Purchase Plan (DRP) will no longer be satisfied with shares issued from treasury at a discount but rather will be acquired on the open market at 100 per cent of the weighted average purchase price. The DRP is available for dividends payable on TransCanada's common and preferred shares, and TCPL's preferred shares. In the three and six months ended June 30, 2011, TransCanada issued 2.8 million and 5.4 million (2010 - 2.6 million and 4.9 million) common shares, respectively, under its DRP, in lieu of making cash dividend payments of $109 million and $202 million, respectively (2010 - $92 million and $170 million).
Contractual Obligations
In the first six months of 2011, TransCanada had a net reduction to its purchase obligations primarily due to the settlement of its commitments in the normal course of business. There have been no other material changes to TransCanada's contractual obligations from December 31, 2010 to June 30, 2011, including payments due for the next five years and thereafter. For further information on these contractual obligations, refer to the MD&A in TransCanada's 2010 Annual Report.
Significant Accounting Policies and Critical Accounting Estimates
To prepare financial statements that conform with GAAP, TransCanada is required to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be dependent on future events. The Company uses the most current information available and exercises careful judgement in making these estimates and assumptions.
TransCanada's significant accounting policies and critical accounting estimates have remained unchanged since December 31, 2010. For further information on the Company's accounting policies and estimates refer to the MD&A in TransCanada's 2010 Annual Report.
Changes in Accounting Policies
The Company's accounting policies have not changed materially from those described in TransCanada's 2010 Annual Report except as follows:
Changes in Accounting Policies for 2011
Business Combinations, Consolidated Financial Statements and Non-Controlling Interests
Effective January 1, 2011, the Company adopted CICA Handbook Section 1582 "Business Combinations", which is effective for business combinations with an acquisition date after January 1, 2011. This standard was amended to require additional use of fair value measurements, recognition of additional assets and liabilities, and increased disclosure. Adopting the standard is expected to have a significant impact on the way the Company accounts for future business combinations. Entities adopting Section 1582 were also required to adopt CICA Handbook Sections 1601 "Consolidated Financial Statements" and 1602 "Non-Controlling Interests". Sections 1601 and 1602 require Non-Controlling Interests to be presented as part of Equity on the balance sheet. In addition, the income statement of the controlling parent now includes 100 per cent of the subsidiary's results and presents the allocation of income between the controlling and non-controlling interests. Changes resulting from the adoption of Section 1582 were applied prospectively and changes resulting from the adoption of Sections 1601 and 1602 were applied retrospectively.
Future Accounting Changes
U.S. GAAP/International Financial Reporting Standards
The CICA's Accounting Standards Board (AcSB) previously announced that Canadian publicly accountable enterprises are required to adopt International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB), effective January 1, 2011.
In accordance with GAAP, TransCanada follows specific accounting policies unique to a rate-regulated business. These rate-regulated accounting (RRA) standards allow the timing of recognition of certain revenues and expenses to differ from the timing that may otherwise be expected in a non-rate-regulated business under GAAP in order to appropriately reflect the economic impact of regulators' decisions regarding the Company's revenues and tolls.
In July 2009, the IASB issued an Exposure Draft "Rate-Regulated Activities", which proposed a form of RRA under IFRS. At its September 2010 meeting, the IASB concluded that the development of RRA under IFRS requires further analysis and removed the RRA project from its current agenda. TransCanada does not expect a final RRA standard under IFRS to be effective in the foreseeable future.
In October 2010, the AcSB and the Canadian Securities Administrators amended their policies applicable to Canadian publicly accountable enterprises that use RRA in order to permit these entities to defer the adoption of IFRS for one year. TransCanada deferred its adoption and accordingly will continue to prepare its consolidated financial statements in 2011 in accordance with Canadian GAAP, as defined by Part V of the CICA Handbook, in order to continue using RRA.
As an SEC registrant, TransCanada prepares and files a "Reconciliation to United States GAAP" and has the option to prepare and file its consolidated financial statements using U.S. GAAP. As a result of the developments noted above, the Company's Board of Directors has approved the adoption of U.S. GAAP effective January 1, 2012.
U.S. GAAP Conversion Project
Effective January 1, 2012, the Company will begin reporting using U.S. GAAP. TransCanada's IFRS conversion team has been redeployed to support the conversion to U.S. GAAP. The conversion team is led by a multi-disciplinary Steering Committee that provides directional leadership for the adoption of U.S. GAAP. Management also updates TransCanada's Audit Committee on the progress of the U.S. GAAP project at each Audit Committee meeting and reports regularly to the Company's Board of Directors on the status of the conversion project.
U.S. GAAP training sessions continue for TransCanada staff who are impacted by the conversion and will be ongoing as needed throughout 2011. Significant changes to existing systems and processes are not required to implement U.S. GAAP as the Company's primary accounting standard since TransCanada prepares and files a "Reconciliation to United States GAAP". The impact to internal controls over financial reporting and disclosure controls and procedures will be addressed over the remainder of 2011.
Identified differences between Canadian GAAP and U.S. GAAP that are significant to the Company are explained below and are consistent with those currently reported in the Company's publicly-filed "Reconciliation to United States GAAP."
Joint Ventures
Canadian GAAP requires the Company to account for certain investments using the proportionate consolidation method of accounting whereby TransCanada's proportionate share of assets, liabilities, revenues, expenses and cash flows are included in the Company's financial statements. U.S. GAAP does not permit the use of proportionate consolidation with respect to TransCanada's joint ventures and requires that such investments be recorded using the equity method of accounting.
Inventory
Canadian GAAP allows the Company's proprietary natural gas inventory held in storage to be recorded at its fair value. Under U.S. GAAP, inventory is recorded at the lower of cost or market.
Income Tax
Canadian GAAP requires an entity to record income tax assets and liabilities resulting from substantively enacted income tax legislation. Under U.S. GAAP, the legislation must be fully enacted for income tax adjustments to be recorded.
Employee Benefits
Canadian GAAP requires an entity to recognize an accrued benefit asset or liability for defined benefit pension and other postretirement benefit plans. Under U.S. GAAP, an employer is required to recognize the overfunded or underfunded status of defined benefit pension and other postretirement benefit plans as an asset or liability in its balance sheet and to recognize changes in the funded status through Other Comprehensive Income in the year in which the change occurs.
Debt Issue Costs
Canadian GAAP requires debt issue costs to be included in long-term debt. Under U.S. GAAP these costs are classified as deferred assets.
Financial Instruments and Risk Management
TransCanada continues to manage and monitor its exposure to counterparty credit, liquidity and market risk.
Counterparty Credit and Liquidity Risk
TransCanada's maximum counterparty credit exposure with respect to financial instruments at the balance sheet date, without taking into account security held, consisted of accounts receivable, portfolio investments recorded at fair value, the fair value of derivative assets, and notes, loans and advances receivable. The carrying amounts and fair values of these financial assets, except amounts for derivative assets, are included in Accounts Receivable and Other, and Available-For-Sale Assets in the Non-Derivative Financial Instruments Summary table below. Guarantees, letters of credit and cash are the primary types of security provided to support these amounts. The majority of counterparty credit exposure is with counterparties who are investment grade. At June 30, 2011, there were no significant amounts past due or impaired.
At June 30, 2011, the Company had a credit risk concentration of $286 million due from a creditworthy counterparty. This amount is expected to be fully collectible and is secured by a guarantee from the counterparty's parent company.
The Company continues to manage its liquidity risk by ensuring sufficient cash and credit facilities are available to meet its operating and capital expenditure obligations when due, under both normal and stressed economic conditions.
Natural Gas Storage Commodity Price Risk
At June 30, 2011, the fair value of proprietary natural gas inventory held in storage, as measured using a weighted average of forward prices for the following four months less selling costs, was $47 million (December 31, 2010 - $49 million). The change in the fair value adjustment of proprietary natural gas inventory in storage in the three and six months ended June 30, 2011 resulted in net pre-tax unrealized losses of $1 million and gains of $1 million, respectively (2010 - gains of $4 million and losses of $20 million, respectively), which were recorded as adjustments to Revenues and Inventories. The change in fair value of natural gas forward purchase and sale contracts in the three and six months ended June 30, 2011 resulted in net pre-tax unrealized losses of $3 million and $10 million, respectively (2010 - gains of $2 million and $5 million, respectively), which were included in Revenues.
VaR Analysis
TransCanada uses a Value-at-Risk (VaR) methodology to estimate the potential impact from its exposure to market risk on its liquid open positions. VaR represents the potential change in pre-tax earnings over a given holding period. It is calculated assuming a 95 per cent confidence level that the daily change resulting from normal market fluctuations in its open positions will not exceed the reported VaR. Although losses are not expected to exceed the statistically estimated VaR on 95 per cent of occasions, losses on the other five per cent of occasions could be substantially greater than the estimated VaR. TransCanada's consolidated VaR was $11 million at June 30, 2011, which was consistent with VaR at December 31, 2010 of $12 million.
Net Investment in Self-Sustaining Foreign Operations
The Company hedges its net investment in self-sustaining foreign operations (on an after-tax basis) with U.S. dollar-denominated debt, cross-currency interest rate swaps, forward foreign exchange contracts and foreign exchange options. At June 30, 2011, the Company had designated as a net investment hedge U.S. dollar-denominated debt with a carrying value of $9.5 billion (US$9.8 billion) and a fair value of $10.8 billion (US$11.2 billion). At June 30, 2011, $279 million (December 31, 2010 - $181 million) was included in Other Current Assets and Intangibles and Other Assets for the fair value of forwards and swaps used to hedge the Company's net U.S. dollar investment in foreign operations.
The fair values and notional principal amounts for the derivatives designated as a net investment hedge were as follows:
Derivatives Hedging Net Investment in Self-Sustaining Foreign Operations
June 30, 2011 December 31, 2010
----------------------------------------
----------------------------------------
Notional Notional
Asset/(Liability) or 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) 276 US 3,550 179 US 2,800
U.S. dollar forward foreign exchange
contracts (maturing 2011) 3 US 600 2 US 100
----------------------------------------
279 US 4,150 181 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
June 30, 2011 December 31, 2010
----------------------------------------
----------------------------------------
(unaudited) Carrying Fair Carrying Fair
(millions of dollars) Amount Value Amount Value
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Financial Assets(1)
Cash and cash equivalents 468 468 764 764
Accounts receivable and other(2)(3) 1,488 1,520 1,555 1,595
Available-for-sale assets(2) 22 22 20 20
----------------------------------------
1,978 2,010 2,339 2,379
----------------------------------------
----------------------------------------
Financial Liabilities(1)(3)
Notes payable 1,628 1,628 2,092 2,092
Accounts payable and deferred
amounts(4) 1,076 1,076 1,436 1,436
Accrued interest 347 347 367 367
Long-term debt 17,340 20,498 17,922 21,523
Long-term debt of joint ventures 839 946 866 971
Junior subordinated notes 955 962 985 992
----------------------------------------
22,185 25,457 23,668 27,381
----------------------------------------
----------------------------------------
(1) Consolidated Net Income in the three and six months ended June 30, 2011
included losses of $2 million and $11 million, respectively, (2010 -
losses of $2 million and $9 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 June 30, 2011, the Consolidated Balance Sheet included financial
assets of $1,167 million (December 31, 2010 - $1,271 million) in
Accounts Receivable, $38 million (December 31, 2010 - $40 million) in
Other Current Assets and $305 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 June 30, 2011, the Consolidated Balance Sheet included financial
liabilities of $1,041 million (December 31, 2010 - $1,406 million) in
Accounts Payable and $35 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:
June 30, 2011
(unaudited)
(all amounts in millions unless Natural Foreign
otherwise indicated) Power Gas Exchange Interest
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Derivative Financial
Instruments Held for
Trading(1)
Fair Values(2)
Assets $ 149 $ 118 $ 6 $ 18
Liabilities $ (114) $ (146) $ (15) $ (19)
Notional Values
Volumes(3)
Purchases 21,569 155 - -
Sales 23,961 123 - -
Canadian dollars - - - 634
U.S. dollars - - US 1,622 US 250
Cross-currency - - 47/US 37 -
Net unrealized gains/(losses)
in the period(4)
Three months ended June 30,
2011 $ 4 $ (9) $ (2) $ 1
Six months ended June 30, 2011 $ 3 $ (26) $ - $ -
Net realized gains/(losses) in
the period(4)
Three months ended June 30,
2011 $ 8 $ (15) $ 12 $ 3
Six months ended June 30, 2011 $ 11 $ (41) $ 33 $ 5
Maturity dates 2011-2018 2011-2016 2011-2012 2012-2016
Derivative Financial
Instruments in Hedging
Relationships(5)(6)
Fair Values(2)
Assets $ 57 $ 5 $ - $ 11
Liabilities $ (197) $ (17) $ (56) $ (14)
Notional Values
Volumes(3)
Purchases 18,524 14 - -
Sales 9,187 - - -
U.S. dollars - - US 120 US 1,000
Cross-currency - - 136/US 100 -
Net realized losses in the
period(4)
Three months ended June 30,
2011 $ (8) $ (5) $ - $ (4)
Six months ended June 30, 2011 $ (46) $ (8) $ - $ (9)
Maturity dates 2011-2017 2011-2013 2011-2014 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 held-for-trading derivative
financial instruments 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 $11 million and a notional amount of US$350
million at June 30, 2011. Net realized gains on fair value hedges for
the three and six months ended June 30, 2011 were $2 million and $4
million, respectively, and were included in Interest Expense. In the
three and six months ended June 30, 2011, the Company did not record any
amounts in Net Income related to ineffectiveness for fair value hedges.
(6) For the three and six months ended June 30, 2011, Net Income included
gains of $2 million and losses of $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 six months ended June 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 Natural Foreign
otherwise 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 June 30,
2010 $ (10) $ 3 $ (11) $ (13)
Six months ended June 30, 2010 $ (26) $ 5 $ (11) $ (17)
Net realized gains/(losses) in
the period(4)
Three months ended June 30,
2010 $ 15 $ (17) $ (6) $ (6)
Six months ended June 30, 2010 $ 37 $ (29) $ 2 $ (10)
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 June 30,
2010 $ (36) $ (6) $ - $ (9)
Six months ended June 30, 2010 $ (43) $ (9) $ - $ (19)
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 held-for-trading derivative
financial instruments 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 six months ended June 30, 2010 were $1 million and $2
million, respectively, and were included in Interest Expense. In the
three and six months ended June 30, 2010, the Company did not record any
amounts in Net Income related to ineffectiveness for fair value hedges.
(6) For the three and six months ended June 30, 2010, Net Income included
gains of $7 million and losses of $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 six months ended June 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) June 30, December 31,
(millions of dollars) 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Current
Other current assets 299 273
Accounts payable (314) (337)
Long-term
Intangibles and other assets 344 374
Deferred amounts (264) (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 June 30, 2011, an evaluation was carried out under the supervision of, and with the participation of management, including the President and Chief Executive Officer and the Chief Financial Officer, of the effectiveness of TransCanada's disclosure controls and procedures as defined under the rules adopted by the Canadian securities regulatory authorities and by the SEC. Based on this evaluation, the President and Chief Executive Officer and the Chief Financial Officer concluded that the design and operation of TransCanada's disclosure controls and procedures were effective at a reasonable assurance level as at June 30, 2011.
During the quarter ended June 30, 2011, there have been no changes in TransCanada's internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, TransCanada's internal control over financial reporting.
Outlook
Since the disclosure in TransCanada's 2010 Annual Report, the Company's overall earnings outlook for 2011 has improved due to higher realized power prices in Western Power in the first half of 2011, with relatively strong prices expected throughout the remainder of 2011. The Company's earnings outlook could also be affected by the uncertainty and ultimate resolution of the capacity pricing issues in New York, as discussed in the Recent Developments section of this MD&A. For further information on outlook, refer to the MD&A in TransCanada's 2010 Annual Report.
Recent Developments
Natural Gas Pipelines
Canadian Mainline
2011 Final Tolls
In April 2011, TransCanada filed an application with the NEB for approval of Canadian Mainline's final tolls for 2011 determined in accordance with the existing 2007-2011 Tolls Settlement.
TransCanada proposed to continue charging the interim 2011 tolls for the remainder of 2011 and to carry forward to 2012 the difference between the revenue that would have been generated from the final tolls and the revenue actually generated from the interim tolls. The interim 2011 tolls were implemented on March 1, 2011 and reflected a firm transportation toll from Empress, Saskatchewan to Dawn, Ontario of $1.89 per gigajoule. Adjusting for the difference in 2012 will result in greater Canadian Mainline toll certainty and stability.
In May 2011, the NEB solicited comments on the application for final tolls from interested parties, requesting their position and recommended process with respect to the application. Subsequently, the NEB solicited additional comments on the application and required TransCanada to file a reply submission by July 29, 2011.
2012 - 2013 Tolls Application
As part of its 2011 final tolls application, TransCanada informed the NEB of its intent to file an application for 2012 and 2013 tolls by October 31, 2011 that will include changes to the business structure, toll design and services. These changes are intended to improve the competitiveness of TransCanada's regulated Canadian natural gas transportation infrastructure and the Western Canada Sedimentary Basin (WCSB).
In June 2011, the NEB directed TransCanada to file the 2012 and 2013 tolls application by September 1, 2011. TransCanada will comply with the NEB's direction, however, certain elements of the application which cannot be available on September 1, 2011 will be filed by the end of October 2011.
Marcellus Facilities Expansion
The Company has concluded new capacity open seasons for the Canadian Mainline that resulted in contractual agreements to transport a total of approximately 350 million cubic feet per day (mmcf/d) of Marcellus shale gas to eastern markets for deliveries that are expected to commence in 2012 and 2013. An application for approval to construct approximately $130 million of new facilities required to provide this service was filed with the NEB on July 18, 2011.
Ongoing shipper interest is expected to result in additional requests for new capacity on the eastern part of the Canadian Mainline over time.
Alberta System
The Alberta System continues to operate under 2011 interim tolls approved by the NEB in 2010. 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.
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. The total contracted volumes for Horn River, including the extension, are expected to be approximately 900 mmcf/d in 2020.
On June 24, 2011, the NEB approved the construction and operation of a 24 km (15 miles) extension of the Groundbirch natural gas pipeline. Construction is expected to commence in August 2011 with an in-service date of April 1, 2012 and an estimated capital cost of approximately $60 million. The project is required to service 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 portion of the WCSB. As at June 30, 2011, in addition to the projects previously discussed, the NEB had approved natural gas pipeline projects with capital costs of approximately $500 million. Further pipeline projects with a total capital cost of approximately $700 million at June 30, 2011 are awaiting NEB approval.
The successful open seasons and 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. Further requests for significant additional volumes on the Alberta System from the northwest portion of the WCSB have been received.
Guadalajara
TransCanada's US$360 million, 307 km (191 miles) 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 early in 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 May 1, 2011, revised fixed tolls came into effect for the Wood River/Patoka section of the system. These revised tolls reflect the final project costs of the Wood River/Patoka section of Keystone.
Keystone experienced two above-ground incidents in second quarter 2011, both of which involved the release of small amounts of crude oil at pump stations in North Dakota and Kansas. In each instance, Keystone's monitoring system worked as designed, allowing for the entire system to be shut down within minutes. As a result of these incidents, the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) issued a corrective action order on June 3, 2011 which required TransCanada to develop and submit a written re-start plan prior to resuming operation of the pipeline. TransCanada's re-start plan, which included steps to facilitate the proper clean-up, investigation, and system improvements and modifications, was approved by PHMSA on June 4, 2011. As a result of these shut downs, Keystone was not able to transport all of the shippers' nominated volumes in May and June 2011, however, the impact to EBITDA was not significant. TransCanada remains committed to building and operating a safe, reliable pipeline. Additional work to improve and modify the system will continue into July and August 2011, which will result in a reduction in available pipeline capacity of approximately 20 per cent in each month. The impact to EBITDA is not expected to be significant.
TransCanada's Keystone U.S. Gulf Coast Expansion (Keystone XL) is now entering the final stages of regulatory review. On April 15, 2011, the U.S. Department of State (DOS), the lead agency for U.S. federal regulatory approvals, issued a Supplemental Draft Environmental Impact Statement (SDEIS) in response to comments received on a Draft Environmental Impact Statement (DEIS) issued in April 2010 and to address new and additional information received. The SDEIS provided additional information on key environmental issues, but did not change the conclusion reached in the DEIS that the project would enhance U.S. energy security, benefit the U.S. economy and have limited environmental impact. A 45-day comment period on the SDEIS concluded June 6, 2011. The DOS is processing the comments and has announced it plans to issue a Final Environmental Impact Statement (FEIS) in third quarter 2011. Following the publication of an FEIS, the DOS will consult with other U.S. federal agencies during a 90-day period to determine if granting approval for Keystone XL is in the U.S. national interest. The DOS has indicated it will make a final decision regarding the Presidential Permit prior to the end of 2011.
The capital cost of Keystone, including Keystone XL, is estimated to be US$13 billion. At June 30, 2011, US$7.9 billion had been invested, including US$1.7 billion related to Keystone XL. The remainder is expected to be invested between now and the in-service date of the expansion, which is expected in 2013. Capital costs related to the construction of Keystone are subject to capital cost risk- and reward-sharing mechanisms with Keystone's long-term committed shippers.
Energy
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.
Sundance A
The binding arbitration process to resolve the Sundance A PPA dispute arising out of TransAlta Corporation's claims of force majeure and economic destruction has commenced. The arbitration panel is expected to hold 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. As the limited information received by TransCanada to date does not support these claims, TransCanada continues to record revenues and costs under the PPA as though this event was a normal plant outage.
Ravenswood
The July 2011 spot price for capacity sales in the New York Zone J market has settled at materially lower levels than prior periods resulting from the manner in which the New York Independent System Operator (NYISO) has treated price mitigation for a new power plant that recently began service in this market. TransCanada believes that this treatment 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 price. TransCanada and a number of other parties have filed a series of complaints with the FERC. The outcome of the complaints and the long-term impact that this development may have on TransCanada's Ravenswood operations are unknown.
The demand curve reset process continues with the NYISO's June 20, 2011 compliance filing resulting in an increased demand curve for 2011 to 2014. The FERC has not yet responded to this filing and, as a result, it is not yet known when the revised demand curves will be effective.
Bruce Power
Loading of fuel commenced on the refurbished Bruce A Unit 2 in second quarter 2011 and was completed in July. Fuel channel assembly was completed on Unit 1 during second quarter 2011, which was the final stage of Atomic Energy of Canada Limited's work on the reactors. Demobilization of refurbishment activity continues as the work transitions from construction to commissioning.
Subject to regulatory approval, Bruce Power expects to achieve a first synchronization of the Unit 2 generator to the electrical grid by the end of 2011, with commercial operation expected to occur in first quarter 2012. Bruce Power expects to load fuel into Unit 1 in third quarter 2011, with a first synchronization of the generator during first quarter 2012 and commercial operation is expected to occur during third quarter 2012. TransCanada's share of the total capital cost is expected to be approximately $2.4 billion, of which $2.1 billion was incurred as of June 30, 2011.
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.
Oakville
In October 2010, the Government of Ontario announced that it would not proceed with the $1.2 billion Oakville generating station. The Company continues to negotiate a settlement with the Ontario government and its agencies that would terminate the 20-year Clean Energy Supply contract TransCanada had previously been awarded and would compensate TransCanada for the economic consequences associated with the contract's termination.
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.
Cartier Wind
Construction continues on the five-stage, 590 MW Cartier Wind project in Quebec. The 58 MW Montagne-Seche project and the 101 MW first phase of the Gros-Morne wind farm 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 July 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 July 25, 2011.
Selected Quarterly Consolidated Financial Data(1)
(unaudited)
(millions of dollars
except per share 2011 2010 2009
amounts) Second First Fourth Third Second First Fourth Third
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenues 2,143 2,243 2,057 2,129 1,923 1,955 1,986 2,049
Net income
attributable to
controlling
interests 367 429 283 391 295 303 387 345
Share Statistics
Net income per
common share -
Basic and Diluted $0.50 $0.59 $0.39 $0.54 $0.41 $0.43 $0.56 $0.50
Dividend declared
per common share $0.42 $0.42 $0.40 $0.40 $0.40 $0.40 $0.38 $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 payments, 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:
-- 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.
-- Third Quarter 2009, Energy's EBIT included net unrealized gains of $14
million pre-tax ($10 million after tax) due to changes in the fair value
of proprietary natural gas inventory in storage and certain risk
management activities.
Consolidated Income
Three months ended Six months ended
(unaudited) June 30 June 30
(millions of dollars except per share
amounts) 2011 2010 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenues 2,143 1,923 4,386 3,878
--------------------------------------
Operating and Other Expenses
Plant operating costs and other 822 764 1,581 1,511
Commodity purchases resold 185 216 462 472
Depreciation and amortization 379 341 749 684
--------------------------------------
1,386 1,321 2,792 2,667
--------------------------------------
Financial Charges/(Income)
Interest expense 235 187 446 369
Interest expense of joint ventures 11 15 27 31
Interest income and other (23) 18 (56) (6)
--------------------------------------
223 220 417 394
--------------------------------------
Income before Income Taxes 534 382 1,177 817
--------------------------------------
Income Taxes Expense
Current 42 (199) 146 (118)
Future 97 264 171 284
--------------------------------------
139 65 317 166
--------------------------------------
Net Income 395 317 860 651
Net Income Attributable to Non-
Controlling Interests 28 22 64 53
--------------------------------------
Net Income Attributable to Controlling
Interests 367 295 796 598
Preferred Share Dividends 14 10 28 17
--------------------------------------
Net Income Attributable to Common
Shares 353 285 768 581
--------------------------------------
--------------------------------------
Net Income per Common Share
Basic and Diluted $0.50 $0.41 $1.10 $ 0.84
--------------------------------------
--------------------------------------
Average Common Shares Outstanding -
Basic (millions) 702 689 700 688
--------------------------------------
--------------------------------------
Average Common Shares Outstanding -
Diluted (millions) 703 690 701 689
--------------------------------------
--------------------------------------
See accompanying notes to the consolidated financial statements.
Consolidated Comprehensive Income
Three months ended Six months ended
(unaudited) June 30 June 30
(millions of dollars) 2011 2010 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net Income 395 317 860 651
Other Comprehensive (Loss)/Income,
Net of Income Taxes
Change in foreign currency
translation gains and losses on
investments in foreign
operations(1) (30) 227 (128) 80
Change in gains and losses on
financial derivatives to hedge the
net investments in foreign
operations(2) 23 (79) 72 (20)
Change in gains and losses on
derivative instruments designated
as cash flow hedges(3) (41) (44) (92) (120)
Reclassification to Net Income of
gains and losses on derivative
instruments designated as cash flow
hedges pertaining to prior
periods(4) 18 (5) 62 (6)
--------------------------------------
Other Comprehensive (Loss)/Income (30) 99 (86) (66)
--------------------------------------
Comprehensive Income 365 416 774 585
Comprehensive Income Attributable to
Non Controlling Interests 33 20 72 50
--------------------------------------
Comprehensive Income Attributable to
Controlling Interests 332 396 702 535
Preferred Share Dividends 14 10 28 17
--------------------------------------
Comprehensive Income Attributable to
Common Shares 318 386 674 518
--------------------------------------
--------------------------------------
(1) Net of income tax expense of $11 million and $40 million for the three
and six months ended June 30, 2011, respectively (2010 - recovery of $45
million and $15 million, respectively).
(2) Net of income tax expense of $8 million and $27 million for the three
and six months ended June 30, 2011, respectively (2010 - recovery of
$34 million and $8 million, respectively).
(3) Net of income tax recovery of $21 million and $39 million for the three
and six months ended June 30, 2011, respectively (2010 - recovery of
$27 million and $84 million, respectively).
(4) Net of income tax expense of $10 million and $34 million for the three
and six months ended June 30, 2011, respectively (2010 - expense of
$16 million and $17 million, respectively).
See accompanying notes to the consolidated financial statements.
Consolidated Cash Flows
Three months ended Six months ended
(unaudited) June 30 June 30
(millions of dollars) 2011 2010 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Cash Generated From Operations
Net income 395 317 860 651
Depreciation and amortization 379 341 749 684
Future income taxes 97 264 171 284
Employee future benefits funding
less than/ (in excess of) expense 3 (12) (8) (44)
Other 18 25 39 83
--------------------------------------
892 935 1,811 1,658
Decrease/(increase) in operating
working capital 8 (310) 98 (201)
--------------------------------------
Net cash provided by operations 900 625 1,909 1,457
--------------------------------------
Investing Activities
Capital expenditures (655) (992) (1,439) (2,268)
Deferred amounts and other 5 7 10 (209)
--------------------------------------
Net cash used in investing
activities (650) (985) (1,429) (2,477)
--------------------------------------
Financing Activities
Dividends on common and preferred
shares (198) (195) (398) (383)
Distributions paid to non-
controlling interests (27) (28) (54) (55)
Notes payable repaid, net (548) (441) (415) (9)
Long-term debt issued, net of
issue costs 519 1,306 519 1,316
Reduction of long-term debt (419) (142) (740) (283)
Long-term debt of joint ventures
issued 31 70 31 78
Reduction of long-term debt of
joint ventures (38) (113) (49) (139)
Common shares issued 4 5 25 14
Partnership units of subsidiary
issued, net of issue costs 321 - 321 -
Preferred shares issued, net of
issue costs - 340 - 679
--------------------------------------
Net cash (used in)/provided by
financing activities (355) 802 (760) 1,218
--------------------------------------
Effect of Foreign Exchange Rate
Changes on Cash and Cash
Equivalents (3) 33 (16) 16
--------------------------------------
(Decrease)/Increase in Cash and
Cash Equivalents (108) 475 (296) 214
Cash and Cash Equivalents
Beginning of period 576 736 764 997
--------------------------------------
Cash and Cash Equivalents
End of period 468 1,211 468 1,211
--------------------------------------
--------------------------------------
Supplementary Cash Flow Information
Income taxes (refunded)/paid,
including refunds (47) 39 41 43
Interest paid 232 119 485 358
--------------------------------------
--------------------------------------
See accompanying notes to the consolidated financial statements.
Consolidated Balance Sheet
(unaudited)
(millions of dollars) June 30, 2011 December 31, 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
ASSETS
Current Assets
Cash and cash equivalents 468 764
Accounts receivable 1,167 1,271
Inventories 427 425
Other 692 777
----------------------------------
2,754 3,237
Plant, Property and Equipment 36,234 36,244
Goodwill 3,461 3,570
Regulatory Assets 1,449 1,512
Intangibles and Other Assets 1,989 2,026
----------------------------------
45,887 46,589
----------------------------------
----------------------------------
LIABILITIES
Current Liabilities
Notes payable 1,628 2,092
Accounts payable 1,884 2,243
Accrued interest 347 367
Current portion of long-term debt 537 894
Current portion of long-term debt of
joint ventures 159 65
----------------------------------
4,555 5,661
Regulatory Liabilities 340 314
Deferred Amounts 710 694
Future Income Taxes 3,357 3,222
Long-Term Debt 16,803 17,028
Long-Term Debt of Joint Ventures 680 801
Junior Subordinated Notes 955 985
----------------------------------
27,400 28,705
----------------------------------
EQUITY
Controlling interests 17,071 16,727
Non-controlling interests 1,416 1,157
----------------------------------
18,487 17,884
----------------------------------
45,887 46,589
----------------------------------
----------------------------------
See accompanying notes to the consolidated financial statements.
Consolidated Accumulated Other Comprehensive (Loss)/Income
Cash
Flow
Currency Hedges
(unaudited) Translation 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) (128) - (128)
Change in gains and losses on
financial derivatives to hedge
the net investments
in foreign operations(2) 72 - 72
Change in gains and losses on
derivative instruments designated
as cash flow hedges(3) - (95) (95)
Reclassification to Net Income
of gains and losses on derivative
instruments designated as cash
flow hedges pertaining to prior
periods(4)(5) - 57 57
------------------------------------------
Balance at June 30, 2011 (739) (232) (971)
------------------------------------------
------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Balance at December 31, 2009 (592) (40) (632)
Change in foreign currency translation
gains and losses on investments in
foreign operations(1) 80 - 80
Change in gains and losses on financial
derivatives to hedge the net
investments in foreign operations(2) (20) - (20)
Changes in gains and losses on
derivative instruments designated
as cash flow hedges(3) - (121) (121)
Reclassification to Net Income of
gains and losses on derivative
instruments designated as cash flow
hedges pertaining
to prior periods(4) - (2) (2)
------------------------------------------
Balance at June 30, 2010 (532) (163) (695)
------------------------------------------
------------------------------------------
(1) Net of income tax expense of $40 million for the six months ended June
30, 2011 (2010 - recovery of $15 million).
(2) Net of income tax expense of $27 million for the six months ended June
30, 2011 (2010 - recovery of $8 million).
(3) Net of income tax recovery of $39 million for the six months ended June
30, 2011 (2010 - recovery of $84 million).
(4) Net of income tax expense of $34 million for the six months ended June
30, 2011 (2010 - expense of $17 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 $103 million
($68 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
(unaudited) Six months ended June 30
(millions of dollars) 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Common Shares
Balance at beginning of period 11,745 11,338
Shares issued under dividend reinvestment
plan 202 170
Shares issued on exercise of stock options 26 14
----------------------------------
Balance at end of period 11,973 11,522
----------------------------------
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 796 598
Common share dividends (589) (552)
Preferred share dividends (28) (17)
----------------------------------
Balance at end of period 4,483 4,215
----------------------------------
Accumulated Other Comprehensive (Loss)/Income
Balance at beginning of period (877) (632)
Other comprehensive (loss)/income (94) (63)
----------------------------------
Balance at end of period (971) (695)
----------------------------------
3,512 3,520
----------------------------------
Equity Attributable to Controlling Interests 17,071 16,596
----------------------------------
Equity Attributable to Non-Controlling
Interests
Balance at beginning of period 1,157 1,174
Net income attributable to non-controlling
interests
PipeLines LP 49 39
Preferred share dividends of subsidiary 11 11
Portland 4 3
Other comprehensive income/(loss)
attributable to non-controlling interests 8 (3)
Sale of PipeLines LP units
Proceeds, net of issue costs 321 -
Decrease in TransCanada's ownership (50) -
Distributions to non-controlling interests (54) (55)
Other (30) 17
----------------------------------
Balance at end of period 1,416 1,186
----------------------------------
Total Equity 18,487 17,782
----------------------------------
----------------------------------
See accompanying notes to the consolidated financial statements.
Notes to Consolidated Financial Statements
(Unaudited)
1. Significant Accounting Policies
The consolidated financial statements of TransCanada Corporation (TransCanada or the Company) have been prepared in accordance with Canadian generally accepted accounting principles (GAAP) 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. These Consolidated Financial Statements reflect all normal recurring adjustments that are, in the opinion of management, necessary to present fairly the financial position and results of operations for the respective periods. These Consolidated Financial Statements do not include all disclosures required in the annual financial statements and should be read in conjunction with the 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 accordance with GAAP, TransCanada follows specific accounting policies unique to a rate-regulated business. These rate-regulated accounting (RRA) standards allow the timing of recognition of certain revenues and expenses to differ from the timing that may otherwise be expected in a non-rate-regulated business under GAAP in order to appropriately reflect the economic impact of regulators' decisions regarding the Company's revenues and tolls. 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.
In October 2010, the AcSB and the Canadian Securities Administrators amended their policies applicable to Canadian publicly accountable enterprises that use RRA in order to permit these entities to defer the adoption of IFRS for one year. TransCanada deferred its adoption and accordingly will continue to prepare its consolidated financial statements in 2011 in accordance with Canadian GAAP, as defined by Part V of the CICA Handbook, in order to continue using RRA.
As a registrant with the U.S. Securities and Exchange Commission, TransCanada prepares and files a "Reconciliation to United States GAAP" and has the option to prepare and file its consolidated financial statements using U.S. GAAP. As a result of the developments noted above, the Company's Board of Directors has approved the adoption of U.S. GAAP effective January 1, 2012. 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
June 30
(unaudited) Natural Gas Oil
(millions of Pipelines Pipelines(1) Energy Corporate Total
dollars) 2011 2010 2011 2010 2011 2010 2011 2010 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenues 1,067 1,061 211 - 865 862 - - 2,143 1,923
Plant operating
costs and other (356) (365) (58) - (393)(377) (15) (22) (822) (764)
Commodity purchases
resold - - - - (185)(216) - - (185) (216)
Depreciation and
Amortization (244) (251) (34) - (97) (90) (4) - (379) (341)
---------------------------------------------------------
467 445 119 - 190 179 (19) (22) 757 602
---------------------------------------------
---------------------------------------------
Interest expense (235) (187)
Interest expense of joint ventures (11) (15)
Interest income and other 23 (18)
Income taxes expense (139) (65)
------------
Net Income 395 317
Net Income Attributable to Non-Controlling Interests (28) (22)
------------
Net Income Attributable to Controlling Interests 367 295
Preferred Share Dividends (14) (10)
------------
Net Income Attributable to Common Shares 353 285
------------
------------
For the six
months ended
June 30
(unaudited) Natural Gas Oil
(millions of Pipelines Pipelines(1) Energy Corporate Total
dollars) 2011 2010 2011 2010 2011 2010 2011 2010 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenues 2,196 2,190 346 - 1,844 1,688 - - 4,386 3,878
Plant operating
costs and
other (689) (726) (94) - (759) (737)(39) (48)(1,581)(1,511)
Commodity purchases
resold - - - - (462) (472) - - (462) (472)
Depreciation and
amortization (488) (504) (57) - (197) (180) (7) - (749) (684)
------------------------------------------------------------
1,019 960 195 - 426 299 (46) (48) 1,594 1,211
-----------------------------------------------
-----------------------------------------------
Interest expense (446) (369)
Interest expense of joint ventures (27) (31)
Interest income and other 56 6
Income taxes expense (317) (166)
------------
Net Income 860 651
Net Income Attributable to Non-Controlling Interests (64) (53)
------------
Net Income Attributable to Controlling Interests 796 598
Preferred Share Dividends (28) (17)
------------
Net Income Attributable to Common Shares 768 581
------------
------------
(1) Commencing in February 2011, TransCanada began recording earnings
related to the Wood River/Patoka and Cushing Extension sections of
Keystone.
Total Assets
(unaudited) December 31,
(millions of dollars) June 30, 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Natural Gas Pipelines 22,903 23,592
Oil Pipelines 8,781 8,501
Energy 12,788 12,847
Corporate 1,415 1,649
-----------------------------------
45,887 46,589
-----------------------------------
-----------------------------------
4. Long-Term Debt
On July 13, 2011, PipeLines LP entered into a five-year, US$500 million senior syndicated revolving credit facility, maturing July 2016. The proceeds from the credit facility were used to reduce PipeLines LP's term loan and senior revolving credit facility, and repay its bridge loan facility. PipeLines LP's remaining US$300 million term loan matures December 2011.
In June 2011, TCPL retired $60 million of 9.5 per cent Medium-Term Notes and, in January 2011, retired $300 million of 4.3 per cent Medium-Term Notes.
In June 2011, PipeLines LP issued US$350 million of 4.65 per cent Senior Notes due 2021 and cancelled US$175 million of its unsecured syndicated senior credit facility.
In the three and six months ended June 30, 2011, the Company capitalized interest related to capital projects of $68 million and $165 million, respectively (2010 - $143 million and $277 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 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 the three and six months ended June 30, 2011, TransCanada issued 2.8 million and 5.4 million (2010 - 2.6 million and 4.9 million) common shares, respectively, under its Dividend Reinvestment and Share Purchase Plan (DRP), in lieu of making cash dividend payments of $109 million and $202 million, respectively (2010 - $92 million and $170 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 June 30, 2011, there were no significant amounts past due or impaired.
At June 30, 2011, the Company had a credit risk concentration of $286 million due from a creditworthy counterparty. This amount is expected to be fully collectible and is secured by a guarantee from the counterparty's parent company.
The Company continues to manage its liquidity risk by ensuring sufficient cash and credit facilities are available to meet its operating and capital expenditure obligations when due, under both normal and stressed economic conditions.
Natural Gas Storage Commodity Price Risk
At June 30, 2011, the fair value of proprietary natural gas inventory held in storage, as measured using a weighted average of forward prices for the following four months less selling costs, was $47 million (December 31, 2010 - $49 million). The change in the fair value adjustment of proprietary natural gas inventory in storage in the three and six months ended June 30, 2011 resulted in net pre-tax unrealized losses of $1 million and gains of $1 million, respectively (2010 - gains of $4 million and losses of $20 million, respectively), which were recorded as adjustments to Revenues and Inventories. The change in fair value of natural gas forward purchase and sale contracts in the three and six months ended June 30, 2011 resulted in net pre-tax unrealized losses of $3 million and $10 million, respectively (2010 - gains of $2 million and $5 million, respectively), which were included in Revenues.
VaR Analysis
TransCanada uses a Value-at-Risk (VaR) methodology to estimate the potential impact from its exposure to market risk on its liquid open positions. VaR represents the potential change in pre-tax earnings over a given holding period. It is calculated assuming a 95 per cent confidence level that the daily change resulting from normal market fluctuations in its open positions will not exceed the reported VaR. Although losses are not expected to exceed the statistically estimated VaR on 95 per cent of occasions, losses on the other five per cent of occasions could be substantially greater than the estimated VaR. TransCanada's consolidated VaR was $11 million at June 30, 2011, which was consistent with VaR at December 31, 2010 of $12 million.
Net Investment in Self-Sustaining Foreign Operations
The Company hedges its net investment in self-sustaining foreign operations (on an after-tax basis) with U.S. dollar-denominated debt, cross-currency interest rate swaps, forward foreign exchange contracts and foreign exchange options. At June 30, 2011, the Company had designated as a net investment hedge U.S. dollar-denominated debt with a carrying value of $9.5 billion (US$9.8 billion) and a fair value of $10.8 billion (US$11.2 billion). At June 30, 2011, $279 million (December 31, 2010 - $181 million) was included in Other Current Assets and Intangibles and Other Assets for the fair value of forwards and swaps used to hedge the Company's net U.S. dollar investment in foreign operations.
The fair values and notional principal amounts for the derivatives designated as a net investment hedge were as follows:
Derivatives Hedging Net Investment in Self-Sustaining Foreign Operations
June 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) 276 US 3,550 179 US 2,800
U.S. dollar forward
foreign exchange
contracts
(maturing 2011) 3 US 600 2 US 100
---------------------------------------------------
279 US 4,150 181 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
June 30, 2011 December 31, 2010
---------------------------------------------------
---------------------------------------------------
(unaudited) Carrying Fair Carrying Fair
(millions of dollars) Amount Value Amount Value
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Financial Assets(1)
Cash and cash
equivalents 468 468 764 764
Accounts receivable
and other(2)(3) 1,488 1,520 1,555 1,595
Available-for-sale
assets(2) 22 22 20 20
------------------------------------------------------
1,978 2,010 2,339 2,379
------------------------------------------------------
------------------------------------------------------
Financial
Liabilities(1)(3)
Notes payable 1,628 1,628 2,092 2,092
Accounts payable and
deferred amounts(4) 1,076 1,076 1,436 1,436
Accrued interest 347 347 367 367
Long-term debt 17,340 20,498 17,922 21,523
Long-term debt of
joint ventures 839 946 866 971
Junior subordinated
notes 955 962 985 992
------------------------------------------------------
22,185 25,457 23,668 27,381
------------------------------------------------------
------------------------------------------------------
(1) Consolidated Net Income in the three and six months ended June 30, 2011
included losses of $2 million and $11 million, respectively, (2010 -
losses of $2 million and $9 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 June 30, 2011, the Consolidated Balance Sheet included financial
assets of $1,167 million (December 31, 2010 - $1,271 million) in
Accounts Receivable, $38 million (December 31, 2010 - $40 million) in
Other Current Assets and $305 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 June 30, 2011, the Consolidated Balance Sheet included financial
liabilities of $1,041 million (December 31, 2010 - $1,406 million) in
Accounts Payable and $35 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:
June 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 $ 149 $ 118 $ 6 $ 18
Liabilities $ (114) $ (146) $ (15) $ (19)
Notional Values
Volumes(3)
Purchases 21,569 155 - -
Sales 23,961 123 - -
Canadian dollars - - - 634
U.S. dollars - - US 1,622 US 250
Cross-currency - - 47/US 37 -
Net unrealized gains/
(losses) in the period(4)
Three months ended June
30, 2011 $ 4 $ (9) $ (2) $ 1
Six months ended June
30, 2011 $ 3 $ (26) $ - $ -
Net realized gains/
(losses) in the period(4)
Three months ended June
30, 2011 $ 8 $ (15) $ 12 $ 3
Six months ended June
30, 2011 $ 11 $ (41) $ 33 $ 5
Maturity dates 2011-2018 2011-2016 2011-2012 2012-2016
Derivative Financial
Instruments in Hedging
Relationships(5)(6)
Fair Values(2)
Assets $ 57 $ 5 $ - $ 11
Liabilities $ (197) $ (17) $ (56) $ (14)
Notional Values
Volumes(3)
Purchases 18,524 14 - -
Sales 9,187 - - -
U.S. dollars - - US 120 US 1,000
Cross-currency - - 136/US 100 -
Net realized losses in
the period(4)
Three months ended June
30, 2011 $ (8) $ (5) $ - $ (4)
Six months ended June
30, 2011 $ (46) $ (8) $ - $ (9)
Maturity dates 2011-2017 2011-2013 2011- 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 gigawatt hours
(GWh) and billion cubic feet (Bcf), respectively.
(4) Realized and unrealized gains and losses on held-for-trading derivative
financial instruments 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 $11 million and a notional amount of US$350
million at June 30, 2011. Net realized gains on fair value hedges for
the three and six months ended June 30, 2011 were $2 million and $4
million, respectively, and were included in Interest Expense. In the
three and six months ended June 30, 2011, the Company did not record any
amounts in Net Income related to ineffectiveness for fair value hedges.
(6) For the three and six months ended June 30, 2011, Net Income included
gains of $2 million and losses of $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 six months ended June 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 Natural Foreign
otherwise 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 June
30, 2010 $ (10) $ 3 $ (11) $ (13)
Six months ended June 30, 2010 $ (26) $ 5 $ (11) $ (17)
Net realized gains/(losses) in
the period(4)
Three months ended June
30, 2010 $ 15 $ (17) $ (6) $ (6)
Six months ended June 30, 2010 $ 37 $ (29) $ 2 $ (10)
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 June
30, 2010 $ (36) $ (6) $ - $ (9)
Six months ended June 30, 2010 $ (43) $ (9) $ - $ (19)
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 held-for-trading derivative
financial instruments 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 six months ended June 30, 2010 were $1 million and $2
million, respectively, and were included in Interest Expense. In the
three and six months ended June 30, 2010, the Company did not record any
amounts in Net Income related to ineffectiveness for fair value hedges.
(6) For the three and six months ended June 30, 2010, Net Income included
gains of $7 million and losses of $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 six months ended June 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) June 30, 2011 December 31, 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Current
Other current assets 299 273
Accounts payable (314) (337)
Long-term
Intangibles and other assets 344 374
Deferred amounts (264) (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 six months ended June 30, 2011. Financial assets and liabilities measured at fair value, including both current and non-current portions, are categorized as follows:
Significant
Quoted Prices Other Significant
in Active Observable Unobservable
Assets/ Markets Inputs Inputs
(Liabilities) (Level 1) (Level II) (Level III) Total
---------------------------------------------------------------
---------------------------------------------------------------
(unaudited)
(millions of
dollars, June 30 Dec 31 June 30 Dec 31 June 30 Dec 31 June 30 Dec 31
pre-tax) 2011 2010 2011 2010 2011 2010 2011 2010
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Natural Gas
Inventory - - 47 49 - - 47 49
Derivative
Financial
Instrument
Assets:
Interest
rate
contracts - - 29 28 - - 29 28
Foreign
exchange
contracts 11 10 278 179 - - 289 189
Power
commodity
contracts - - 194 269 3 5 197 274
Natural gas
commodity
contracts 68 93 53 56 - - 121 149
Derivative
Financial
Instrument
Liabilities:
Interest
rate
contracts - - (32) (47) - - (32) (47)
Foreign
exchange
contracts (17) (11) (59) (54) - - (76) (65)
Power
commodity
contracts - - (272) (299) (30) (8) (302) (307)
Natural gas
commodity
contracts (133) (178) (28) (15) - - (161) (193)
Non-
Derivative
Financial
Instruments:
Available-
for-sale
assets 22 20 - - - - 22 20
---------------------------------------------------------------
(49) (66) 210 166 (27) (3) 134 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:
Derivatives(1)
(unaudited) ----------------------
(millions of dollars, pre-tax) 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Balance at January 1 (3) (2)
New contracts(2) 1 (10)
Transfers out of Level III(3) (4) (15)
Settlements - (2)
Change in unrealized gains recorded in Net Income 1 14
Change in unrealized (losses)/gains recorded in Other
Comprehensive Income (22) 10
----------------------
Balance at June 30 (27) (5)
----------------------
----------------------
(1) The fair value of derivative assets and liabilities is presented on a
net basis.
(2) For the three and six months ended June 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, 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 $12 million decrease or increase, respectively, in the fair value of derivative financial instruments included in Level III and outstanding as at June 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:
Pension Benefit Other Benefit
Plans Plans
Three months ended June 30 ---------------------------------------
(unaudited)(millions of dollars) 2011 2010 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Current service cost 13 13 1 1
Interest cost 22 22 2 2
Expected return on plan assets (28) (27) (1) (1)
Amortization of transitional
obligation related to
regulated business - - 1 1
Amortization of net actuarial
loss 5 2 1 1
Amortization of past service
costs 1 1 - -
---------------------------------------
Net benefit cost recognized 13 11 4 4
---------------------------------------
---------------------------------------
Pension Benefit Other Benefit
Plans Plans
Six months ended June 30 ---------------------------------------
(unaudited)(millions of dollars) 2011 2010 2011 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Current service cost 27 25 1 1
Interest cost 45 45 4 4
Expected return on plan assets (56) (54) (1) (1)
Amortization of transitional
obligation related to
regulated business - - 1 1
Amortization of net actuarial
loss 11 4 1 1
Amortization of past service
costs 2 2 - -
---------------------------------------
Net benefit cost recognized 29 22 6 6
---------------------------------------
---------------------------------------
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. No amounts recorded in revenues in the first six months of 2011 are expected to be repaid.
TransCanada welcomes questions from shareholders and potential investors. Please telephone:
Investor Relations, at (800) 361-6522 (Canada and U.S. Mainland) or direct dial David Moneta/Terry Hook/Lee Evans at (403) 920-7911. The investor fax line is (403) 920-2457. Media Relations: James Millar/Terry Cunha/Shawn Howard (403) 920-7859 or (800) 608-7859.
TransCanada Corporation
Media Enquiries:
Terry Cunha/Shawn Howard
403.920.7859 or 800.608.7859
TransCanada Corporation
Analyst Enquiries:
David Moneta/Terry Hook/Lee Evans
403.920.7911 or 800.361.6522
www.transcanada.com