CALGARY, ALBERTA--(Marketwire - July 27, 2012) - TransCanada Corporation (TSX:TRP) (NYSE:TRP) (TransCanada or the Company) today announced comparable earnings for second quarter 2012 of $300 million or $0.43 per share. Excluding an after-tax charge of $22 million related to the Sundance A PPA arbitration decision received in July 2012, comparable earnings for second quarter 2012 were $322 million or $0.46 per share. TransCanada's Board of Directors also declared a quarterly dividend of $0.44 per common share for the quarter ending September 30, 2012, equivalent to $1.76 per common share on an annualized basis.
"TransCanada's diverse, high-quality energy infrastructure assets performed well in the second quarter," said Russ Girling, TransCanada's president and chief executive officer. "While historically high natural gas storage levels and low natural gas and power prices adversely affected certain aspects of our business, the majority of our assets continued to generate stable and predictable earnings and cash flow. Looking forward, TransCanada is well positioned to grow earnings, cash flow and dividends as we progress our current capital program, secure attractive new opportunities and benefit from a recovery in natural gas and power prices."
Over the next three years, TransCanada expects to complete $13 billion of projects that are currently in advanced stages of development. They include the restart of two reactors at Bruce Power, the Gulf Coast Project, Keystone XL, the Tamazunchale extension, Canadian Solar and the ongoing expansion of the Alberta System.
TransCanada also continues to advance various other large scale initiatives that will help shape the North American energy marketplace. They include the recently announced $4 billion Coastal GasLink Project that would move Canadian natural gas to Asian markets and various other initiatives in its three core businesses. TransCanada expects each of these projects to generate significant, sustained earnings and cash flow and deliver superior returns to its shareholders.
Highlights
(All financial figures are unaudited and in Canadian dollars unless noted
otherwise)
-- Second quarter financial results
-- Comparable earnings of $300 million or $0.43 per share
-- Net income attributable to common shares of $272 million or $0.39
per share
-- Comparable earnings before interest, taxes, depreciation and
amortization (EBITDA) of $1.0 billion
-- Funds generated from operations of $729 million
-- Declared a quarterly dividend of $0.44 per common share for the quarter
ending September 30
-- Selected to develop a proposed $4 billion pipeline that would transport
natural gas to the recently announced LNG Canada liquefied natural gas
export facility near Kitimat, British Columbia
-- Continued to advance several growth initiatives in the Oil Pipelines
business
-- Received the necessary regulatory permits required for the Gulf
Coast Project - construction expected to begin this summer
-- Filed a Presidential Permit application for the Keystone XL Pipeline
from the U.S./Canada border to Steele City, Nebraska - the U.S.
Department of State (DOS) indicated it expects to make a decision on
the project by the first quarter 2013
-- Secured binding long-term commitments to support the development of
the 2.6 million barrel Keystone Hardisty Terminal
-- Bruce Power returned Unit 3 to service after completing a planned outage
that is expected to extend the operating life of the nuclear reactor
until at least 2021
-- Canadian Mainline tolls hearing commenced June 4 - a decision is
expected late 2012 or early 2013
-- Received a decision on the Sundance A PPA arbitration
Comparable earnings for second quarter 2012 were $300 million or $0.43 per share. Excluding an after-tax charge of $22 million related to the Sundance A PPA arbitration decision received in July, comparable earnings for second quarter 2012 were $322 million or $0.46 per share compared to $355 million or $0.51 per share for the same period in 2011. Incremental earnings from Keystone and other recently commissioned assets were more than offset by lower contributions from U.S. Power and certain natural gas pipelines including the Canadian Mainline, ANR and Great Lakes.
Net income attributable to common shares for second quarter 2012 was $272 million or $0.39 per share. Excluding an after-tax charge of $37 million related to the Sundance A arbitration decision, net income attributable to common shares for the second quarter 2012 was $309 million or $0.44 per share compared to $353 million or $0.50 per share in second quarter 2011.
Notable recent developments in Oil Pipelines, Natural Gas Pipelines, Energy and Corporate include:
Oil Pipelines:
-- Gulf Coast Project: During second quarter 2012, TransCanada continued to
advance the US$2.3 billion Gulf Coast Project. The 36-inch pipeline,
which will extend from Cushing, Oklahoma to the U.S. Gulf Coast, is
expected to have an initial capacity of up to 700,000 barrels per day
(bbl/d) with an ultimate capacity of 830,000 bbl/d. TransCanada expects
to start construction this summer and place the Gulf Coast Project in
service in mid to late 2013. Included in the US$2.3 billion cost is
US$300 million for the 76 kilometre (km) (47-mile) Houston Lateral
pipeline that will transport crude oil to Houston refineries. As of June
30, 2012, approximately US$900 million has been invested in the project.
-- Keystone XL: In May 2012, TransCanada filed a Presidential Permit
application (cross border permit) with the DOS for the Keystone XL
Pipeline which will extend from the U.S./Canada border in Montana to
Steele City, Nebraska. TransCanada will supplement the application with
an alternative route in Nebraska as soon as that route is selected.
The Company continues to work collaboratively with the Nebraska
Department of Environmental Quality (NDEQ) to finalize an alternative
route for the Keystone XL Pipeline that avoids the Nebraska Sandhills
and has submitted alternative routing corridors and a preferred corridor
to the NDEQ. The NDEQ has conducted public open houses on the proposed
routes and expects to complete its review in the coming months.
The over three year environmental review completed last summer for the
Keystone XL Pipeline was the most comprehensive process ever for a cross
border pipeline. Based on that work, TransCanada expects its cross
border permit should be processed expeditiously and a decision made once
a new route in Nebraska is determined. The DOS has indicated it expects
to make a decision on the project by the first quarter of 2013.
Subject to regulatory approvals, TransCanada expects the Keystone XL
Pipeline to be in service in late 2014 or early 2015. The approximate
cost of the 36-inch, 830,000 bbl/d line is US$5.3 billion. As of June
30, 2012, US$1.5 billion has been invested in the project.
-- Keystone Hardisty Terminal: In May 2012, TransCanada announced that it
had secured binding long-term commitments exceeding 500,000 bbl/d for
the Keystone Hardisty Terminal (Hardisty Terminal). As a result of
strong commercial support for the project, the Company will expand the
proposed two million barrel project to a 2.6 million barrel terminal.
The Hardisty Terminal will provide new crude oil batch accumulation
tankage and pipeline infrastructure for Western Canadian producers and
access to the Keystone Pipeline System. Subject to regulatory approvals,
the Hardisty Terminal is expected to be operational in late 2014 and
cost approximately $275 million.
Natural Gas Pipelines:
-- Coastal GasLink: In June 2012, TransCanada announced that it had been
selected by Shell Canada Limited (Shell) and its partners to design,
build, own and operate the proposed Coastal GasLink project, an
estimated $4 billion pipeline that would transport natural gas from the
Montney gas- producing region near Dawson Creek, British Columbia to the
recently announced LNG Canada liquefied natural gas export facility near
Kitimat, British Columbia. The LNG Canada project is a joint venture led
by Shell, with partners Korea Gas Corporation, Mitsubishi Corporation
and PetroChina Company Limited. The approximate 700 km (420-mile)
pipeline is expected to have an initial capacity of more than 1.7
billion cubic feet per day (bcf/d) and be placed into service toward the
end of the decade.
-- Alberta System: During the first half of 2012, TransCanada continued to
expand its Alberta System by completing and placing into service 10
separate pipeline projects at a total cost of approximately $600
million. This included the completion of the approximate $250 million
Horn River project in May 2012 that extended the Alberta System into the
Horn River shale play in British Columbia.
The National Energy Board (NEB) has approved additional Alberta System
expansions of approximately $630 million, including the Leismer-Kettle
River Crossover project, a 30-inch, 77 km (46-mile) pipeline that was
approved in June 2012. This project has an estimated cost of $162
million and is intended to provide increased capacity to meet demand in
Northeast Alberta. Approximately $340 million of additional projects are
still awaiting NEB approval, including the Komie North project that
would extend the Alberta System further into the Horn River area.
-- Canadian Mainline: On June 4, 2012, a NEB hearing began to address
TransCanada's application to change the business structure and the terms
and conditions of service for the Canadian Mainline, including
addressing tolls for 2012 and 2013. The hearing is expected to conclude
at the end of September, with a decision expected in late 2012 or early
2013.
In May 2012, TransCanada received NEB approval to construct new pipeline
facilities to provide Southern Ontario with additional natural gas
supply from the Marcellus shale basin. As a result of a number of
compliance requirements associated with the approval, the current
November 2012 in-service date may be delayed.
Energy:
-- Sundance A: The binding arbitration hearing to address the Sundance A
PPA force majeure and economic destruction claims concluded during the
second quarter and a decision was received in July 2012. The arbitration
panel determined the PPA should not be terminated and ordered TransAlta
to rebuild Units 1 and 2. The panel also limited TransAlta's force
majeure claim from November 20, 2011 until such time the units can
reasonably be returned to service. According to the terms of the
arbitration decision, TransAlta has an obligation under the PPA to
exercise all reasonable efforts to mitigate or limit the effects of the
force majeure. TransAlta announced that it expects the units to be
returned to service in the fall of 2013.
TransCanada had accrued $188 million of pre-tax income from the
commencement of the outages in December 2010 to the end of March 2012 as
it considered the outages to be an interruption of supply. As a result
of the decision, the Company is entitled to receive approximately $138
million of this amount. The difference of $50 million has been recorded
as a charge to second quarter earnings, of which $30 million related to
amounts recorded in first quarter 2012 and is included in comparable
earnings, and $20 million related to fourth quarter 2011 which is
excluded from 2012 comparable earnings.
Going forward, until TransAlta returns the Sundance A units to service,
TransCanada will not realize the generation or related revenues it would
otherwise be entitled to under the PPA but will be relieved of the
associated capacity payments.
-- Bruce Power: In June 2012, Bruce Power returned Unit 3 to service after
completing the approximate $300 million West Shift Plus planned outage
which commenced in November 2011. This investment is an important part
of Bruce Power's strategy to maximize the operating life of its reactors
and is expected to allow Unit 3 to produce low-cost electricity until at
least 2021.
In March 2012, Bruce Power received authorization from the Canadian
Nuclear Safety Commission (CNSC) to restart Unit 2. In May 2012, an
incident occurred within the Unit 2 electrical generator on the non-
nuclear side of the plant that delayed the synchronization of Unit 2 to
the Ontario electrical grid. As a result, Bruce Power has submitted a
force majeure claim to the Ontario Power Authority (OPA) and if
accepted, the price received for power generated from the operating
units at Bruce A would not be impacted. Work is currently underway to
repair the Unit 2 electrical generator and Bruce Power expects
commercial operations for Unit 2 to commence in fourth quarter 2012.
Commissioning work is continuing on Unit 1. Bruce Power has received
approval from the CNSC to remove the reactor shutdown guarantees and is
proceeding with restarting the Unit 1 reactor. Synchronization to the
Ontario electrical grid is expected to occur during mid-third quarter
2012.
TransCanada's share of the total net capital cost for the refurbishment
project is expected to be approximately $2.4 billion. Once the
refurbishment is complete, Bruce Power will be capable of producing
6,200 megawatts (MW) of emission-free power.
-- Ravenswood: In 2011, TransCanada and other parties jointly filed two
formal complaints with the Federal Energy Regulatory Commission (FERC)
regarding application of capacity pricing rules by the New York
Independent System Operator. In June 2012, the FERC addressed the first
of the two complaints and indicated it will take steps to increase
transparency and accountability with regard to future Mitigation
Exemption Test decisions. The outcome of the second and potentially more
significant complaint is still pending.
-- Canadian Solar: In 2011, TransCanada agreed to purchase nine Ontario
solar projects from Canadian Solar Solutions Inc., with a combined
capacity of 86 MW, for approximately $470 million. Each project will be
purchased once construction and acceptance testing have been completed
and operations have begun under 20-year PPAs with the OPA under the
Feed-In Tariff program in Ontario. Construction on the first two solar
projects has commenced and both projects are expected to be placed in
service in late 2012. TransCanada anticipates the remaining projects
will be placed in service in 2013 or early 2014, subject to regulatory
approvals.
Corporate:
-- The Board of Directors of TransCanada declared a quarterly dividend of
$0.44 per share for the quarter ending September 30, 2012 on
TransCanada's outstanding common shares. The quarterly amount is
equivalent to $1.76 per common share on an annual basis.
-- As previously disclosed, TransCanada adopted U.S. generally accepted
accounting principles (U.S. GAAP) effective January 1, 2012.
Accordingly, the 2012 financial information, along with comparative
financial information for 2011, has been prepared in accordance with
U.S. GAAP.
Teleconference - Audio and Slide Presentation:
TransCanada will hold a teleconference and webcast on Friday, July 27, 2012 to discuss its second quarter 2012 financial results. Russ Girling, TransCanada president and chief executive officer and Don Marchand, executive vice-president and chief financial officer, along with other members of the TransCanada executive leadership team, will discuss the financial results and Company developments at 9:00 a.m. (MDT) / 11:00 a.m. (EDT).
Analysts, members of the media and other interested parties are invited to participate by calling 866.226.1793 or 416.340.2218 (Toronto area). Please dial in 10 minutes prior to the start of the call. No pass code is required. A live webcast of the teleconference will be available at www.transcanada.com.
A replay of the teleconference will be available two hours after the conclusion of the call until midnight (EDT) August 13, 2012. Please call 905.694.9451 or 800.408.3053 (North America only) and enter pass code 8130635.
The unaudited interim Consolidated Financial Statements and Management's Discussion and Analysis (MD&A) are available on SEDAR at www.sedar.com, with the U.S. Securities and Exchange Commission on EDGAR at www.sec.gov/info/edgar.shtml and on the TransCanada website at www.transcanada.com.
With more than 60 years experience, TransCanada is a leader in the responsible development and reliable operation of North American energy infrastructure including natural gas and oil pipelines, power generation and gas storage facilities. TransCanada operates a network of natural gas pipelines that extends more than 68,500 kilometres (42,500 miles), tapping into virtually all major gas supply basins in North America. TransCanada is one of the continent's largest providers of gas storage and related services with approximately 380 billion cubic feet of storage capacity. A growing independent power producer, TransCanada owns or has interests in over 10,800 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 or check us out on Twitter @TransCanada.
Forward Looking Information
This news release contains certain information that is forward-looking and is subject to important risks and uncertainties (such statements are usually accompanied by words such as "anticipate", "expect", "would", "believe", "may", "will", "plan", "intend" or other similar words). Forward-looking statements in this document are intended to provide TransCanada security holders and potential investors with information regarding TransCanada and its subsidiaries, including management's assessment of TransCanada's and its subsidiaries' future financial and operational plans and outlook. All forward-looking statements reflect TransCanada's beliefs and assumptions based on information available at the time the statements were made and as such are not guarantees of future performance. Readers are cautioned not to place undue reliance on this forward-looking information, which is given as of the date it is expressed in this news release, and not to use future-oriented information or financial outlooks for anything other than their intended purpose. TransCanada undertakes no obligation to update or revise any forward-looking information except as required by law. For additional information on the assumptions made, and the risks and uncertainties which could cause actual results to differ from the anticipated results, refer to TransCanada's MD&A dated February 15, 2012 under TransCanada's profile on SEDAR at www.sedar.com and other reports filed by TransCanada with Canadian securities regulators and with the U.S. Securities and Exchange Commission.
Non-GAAP Measures
This news release contains references to non-GAAP measures that do not have any standardized meaning as prescribed by U.S. GAAP and may therefore not be comparable to similar measures used by other companies. These non-GAAP measures are calculated on a consistent basis from period to period and are adjusted for specific items in each period, as applicable. For more information on non-GAAP measures, refer to TransCanada's Quarterly Report to Shareholders dated July 26, 2012.
Second Quarter 2012 Financial Highlights
Operating Results
Three months ended Six months ended
(unaudited) June 30 June 30
(millions of dollars) 2012 2011 2012 2011
============================================================================
Revenues 1,806 1,797 3,717 3,665
Comparable EBITDA(1) 997 1,074 2,110 2,236
Net Income Attributable to Common
Shares 272 353 624 764
Comparable Earnings(1) 300 355 663 778
Cash Flows
Funds generated from operations(1) 729 847 1,600 1,691
Decrease/(increase) in operating
working capital 14 46 (155) 65
----------------------------------------
Net cash provided by operations 743 893 1,445 1,756
========================================
Capital Expenditures 397 487 861 1,088
========================================
Common Share Statistics
Three months ended Six months ended
June 30 June 30
(unaudited) 2012 2011 2012 2011
============================================================================
Net Income per Common Share - Basic $0.39 $0.50 $0.89 $1.09
Comparable Earnings per Common
Share(1) $0.43 $0.51 $0.94 $1.11
Dividends Declared per Common Share $0.44 $0.42 $0.88 $0.84
Basic Common Shares Outstanding
(millions)
Average for the period 704 702 704 700
End of period 704 703 704 703
======================================
(1) Refer to the Non-GAAP Measures section in TransCanada's Quarterly Report
to Shareholders dated July 26, 2012 for further discussion of Comparable
EBITDA, Comparable Earnings, Funds Generated from Operations and
Comparable Earnings per Share.
TRANSCANADA CORPORATION - SECOND QUARTER 2012
Quarterly Report to Shareholders
Management's Discussion and Analysis
This Management's Discussion and Analysis (MD&A) dated July 26, 2012 should be read in conjunction with the accompanying unaudited Condensed Consolidated Financial Statements of TransCanada Corporation (TransCanada or the Company) for the three and six months ended June 30, 2012. The condensed consolidated financial statements of the Company have been prepared in accordance with United States (U.S.) generally accepted accounting principles (U.S. GAAP). Comparative figures, which were previously presented in accordance with Canadian generally accepted accounting principles as defined in Part V of the Canadian Institute of Chartered Accountants Handbook (CGAAP), have been adjusted as necessary to be compliant with the Company's accounting policies under U.S. GAAP, which is discussed further in the Changes in Accounting Policies section in this MD&A. This MD&A should also be read in conjunction with the audited Consolidated Financial Statements and notes thereto, and the MD&A contained in TransCanada's 2011 Annual Report, as prepared in accordance with CGAAP, for the year ended December 31, 2011. Additional information relating to TransCanada, including the Company's Annual Information Form and other continuous disclosure documents, is available on SEDAR at 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 2011 Annual Report.
Forward-Looking Information
This MD&A contains certain information that is forward looking and is subject to important risks and uncertainties. The words "anticipate", "expect", "believe", "may", "will", "should", "estimate", "project", "outlook", "forecast", "intend", "target", "plan" or other similar words are typically used to identify such forward-looking information. Forward-looking statements in this document are intended to provide TransCanada security holders and potential investors with information regarding TransCanada and its subsidiaries, including management's assessment of TransCanada's and its subsidiaries' future plans and financial outlook. Forward-looking statements in this document may include, but are not limited to, statements regarding:
-- anticipated business prospects;
-- financial performance of TransCanada and its subsidiaries and
affiliates;
-- expectations or projections about strategies and goals for growth and
expansion;
-- expected cash flows;
-- expected costs;
-- expected costs for projects under construction;
-- expected schedules for planned projects (including anticipated
construction and completion dates);
-- expected regulatory processes and outcomes;
-- expected outcomes with respect to legal proceedings, including
arbitration;
-- expected capital expenditures and contractual obligations;
-- expected operating and financial results; and
-- expected impact of future commitments and contingent liabilities.
These forward-looking statements reflect TransCanada's beliefs and assumptions based on information available at the time the statements were made and, as such, are not guarantees of future performance. By their nature, forward-looking statements are subject to various assumptions, risks and uncertainties which could cause TransCanada's actual results and achievements to differ materially from the anticipated results or expectations expressed or implied in such statements.
Key assumptions on which TransCanada's forward-looking statements are based include, but are not limited to, assumptions about:
-- commodity and capacity prices;
-- inflation rates;
-- timing of debt issuances and hedging;
-- regulatory decisions and outcomes;
-- arbitration decisions and outcomes;
-- foreign exchange rates;
-- interest rates;
-- tax rates;
-- planned and unplanned outages and utilization of the Company's pipeline
and energy assets;
-- asset reliability and integrity;
-- access to capital markets;
-- anticipated construction costs, schedules and completion dates; and
-- acquisitions and divestitures.
The risks and uncertainties that could cause actual results or events to differ materially from current expectations include, but are not limited to:
-- 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;
-- amount of capacity payments and revenues from the Company's energy
business;
-- regulatory decisions and outcomes;
-- outcomes with respect to legal proceedings, including arbitration;
-- counterparty performance;
-- 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;
-- weather;
-- technological developments; and
-- economic conditions in North America.
Additional information on these and other factors is available in the reports filed by TransCanada with Canadian securities regulators and with the U.S. Securities and Exchange Commission (SEC).
Readers are cautioned against placing undue reliance on forward-looking information, which is given as of the date it is expressed in this MD&A or otherwise stated, and not to use future-oriented information or financial outlooks for anything other than their intended purpose. TransCanada undertakes no obligation to publicly update or revise any forward-looking information in this MD&A or otherwise stated, whether as a result of new information, future events or otherwise, except as required by law.
Non-GAAP Measures
TransCanada uses the measures Comparable Earnings, Comparable Earnings per Share, Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA), Comparable EBITDA, Earnings Before Interest and Taxes (EBIT), Comparable EBIT, Comparable Interest Expense, Comparable Interest Income and Other, Comparable Income Taxes and Funds Generated from Operations in this MD&A. These measures do not have any standardized meaning as prescribed by U.S. GAAP. They are, therefore, considered to be non-GAAP measures and are unlikely to be comparable to similar measures presented by other entities. Management of TransCanada uses these non-GAAP measures to improve its ability to compare financial results among reporting periods and to enhance its understanding of operating performance, liquidity and ability to generate funds to finance operations. These non-GAAP measures are also provided to readers as additional information on TransCanada's operating performance, liquidity and ability to generate funds to finance operations.
EBITDA is an approximate measure of the Company's pre-tax operating cash flow and is generally used to better measure performance and evaluate trends of individual assets. EBITDA comprises earnings before deducting interest and other financial charges, income taxes, depreciation and amortization, net income attributable to non-controlling interests and preferred share dividends. EBITDA includes income from equity investments. EBIT is a measure of the Company's earnings from ongoing operations and is generally used to better measure performance and evaluate trends within each segment. EBIT comprises earnings before deducting interest and other financial charges, income taxes, net income attributable to non-controlling interests and preferred share dividends. EBIT includes income from equity investments.
Comparable Earnings, Comparable EBITDA, Comparable EBIT, Comparable Interest Expense, Comparable Interest Income and Other, and Comparable Income Taxes comprise Net Income Applicable to Common Shares, EBITDA, EBIT, Interest Expense, Interest Income and Other, and Income Taxes, respectively, and are adjusted for specific items that are significant but are not reflective of the Company's underlying operations in the period. Specific items are subjective, however, management uses its judgement and informed decision-making when identifying items to be excluded in calculating these non-GAAP measures, some of which may recur. Specific items may include but are not limited to certain fair value adjustments relating to risk management activities, income tax adjustments, gains or losses on sales of assets, legal and bankruptcy settlements, and write-downs of assets and investments. These non-GAAP measures are calculated on a consistent basis from period to period. The specific items for which such measures are adjusted in each applicable period may only be relevant in certain periods and are disclosed in the Reconciliation of Non-GAAP Measures table in this MD&A.
The Company engages in risk management activities to reduce its exposure to certain financial and commodity price risks by utilizing derivatives. The risk management activities which TransCanada excludes from Comparable Earnings provide effective economic hedges but do not meet the specific criteria for hedge accounting treatment and, therefore, changes in their fair values are recorded in Net Income each year. The unrealized gains or losses from changes in the fair value of these derivative contracts are not considered to be representative of the underlying operations in the current period or the positive margin that will be realized upon settlement. As a result, these amounts have been excluded in the determination of Comparable Earnings.
The Reconciliation of Non-GAAP Measures table in this MD&A presents a reconciliation of these non-GAAP measures to Net Income Attributable to Common Shares. Comparable Earnings per Common Share is calculated by dividing Comparable Earnings by the weighted average number of common shares outstanding for the period.
Funds Generated from Operations comprise Net Cash Provided by Operations before changes in operating working capital and allows management to better measure consolidated operating cash flow, excluding fluctuations from working capital balances which may not necessarily be reflective of underlying operations in the same period. A reconciliation of Funds Generated from Operations to Net Cash Provided by Operations is presented in the Summarized Cash Flow table in the Liquidity and Capital Resources section in this MD&A.
Reconciliation of Non-GAAP Measures
Three months ended
June 30 Natural Gas Oil
(unaudited) Pipelines Pipelines Energy Corporate Total
(millions of dollars) 2012 2011 2012 2011 2012 2011 2012 2011 2012 2011
============================================================================
Comparable EBITDA 666 688 176 153 170 248 (15) (15) 997 1,074
Depreciation and
amortization (234) (229) (36) (34) (72) (63) (4) (4)(346) (330)
------------------------------------------------------
Comparable EBIT 432 459 140 119 98 185 (19) (19) 651 744
===========================================
Other Income Statement Items
Comparable interest expense (239) (236)
Comparable interest income and other 19 28
Comparable income taxes (91) (139)
Net income attributable to non-controlling interests (26) (28)
Preferred share dividends (14) (14)
-----------
Comparable Earnings 300 355
Specific items (net of tax):
Sundance A PPA arbitration decision (15) -
Risk management activities(1) (13) (2)
-----------
Net Income Attributable to Common Shares 272 353
===========
Three months ended June 30
(unaudited)(millions of dollars) 2012 2011
============================================================================
Comparable Interest Expense (239) (236)
Specific item:
Risk management activities(1) - 1
--------------------
Interest Expense (239) (235)
====================
Comparable Interest Income and Other 19 28
Specific item:
Risk management activities(1) (14) (3)
--------------------
Interest Income and Other 5 25
====================
Comparable Income Taxes (91) (139)
Specific items:
Income taxes attributable to Sundance A PPA
arbitration decision 5 -
Income taxes attributable to risk management
activities(1) 1 1
--------------------
Income Taxes Expense (85) (138)
====================
Comparable Earnings per Common Share $0.43 $0.51
Specific items (net of tax):
Sundance A PPA arbitration decision (0.02) -
Risk management activities (0.02) (0.01)
--------------------
Net Income per Share $0.39 $0.50
====================
(1) Three months ended June 30
(unaudited)(millions of dollars) 2012 2011
============================================================================
Risk Management Activities Gains/(Losses):
Canadian Power 1 1
U.S. Power 16 1
Natural Gas Storage (17) (3)
Interest rate - 1
Foreign exchange (14) (3)
Income taxes attributable to risk management
activities 1 1
--------------------
Risk Management Activities (13) (2)
====================
Reconciliation of Non-GAAP Measures
Six months
ended June 30
(unaudited) Natural Gas Oil
(millions of Pipelines Pipelines Energy Corporate Total
dollars) 2012 2011 2012 2011 2012 2011 2012 2011 2012 2011
============================================================================
Comparable
EBITDA 1,391 1,461 349 252 414 562 (44) (39) 2,110 2,236
Depreciation and
amortization (466) (457) (72) (57) (145) (129) (7) (7) (690) (650)
-------------------------------------------------------------
Comparable EBIT 925 1,004 277 195 269 433 (51) (46) 1,420 1,586
================================================
Other Income Statement Items
Comparable interest expense (481) (446)
Comparable interest income and other 44 56
Comparable income taxes (231) (326)
Net income attributable to non-controlling interests (61) (64)
Preferred share dividends (28) (28)
-------------
Comparable Earnings 663 778
Specific items (net of tax):
Sundance A PPA arbitration decision (15) -
Risk management activities(1) (24) (14)
-------------
Net Income Attributable to Common Shares 624 764
=============
Six months ended June 30
(unaudited)(millions of dollars) 2012 2011
============================================================================
Comparable Interest Expense (481) (446)
Specific item:
Risk management activities(1) - -
--------------------
Interest Expense (481) (446)
====================
Comparable Interest Income and Other 44 56
Specific item:
Risk management activities(1) (8) (1)
--------------------
Interest Income and Other 36 55
====================
Comparable Income Taxes (231) (326)
Specific items:
Income taxes attributable to Sundance A PPA
arbitration decision 5 -
Income taxes attributable to risk management
activities(1) 12 8
--------------------
Income Taxes Expense (214) (318)
====================
Comparable Earnings per Common Share $0.94 $1.11
Specific items (net of tax):
Sundance A PPA arbitration decision (0.02) -
Risk management activities (0.03) (0.02)
--------------------
Net Income per Share $0.89 $1.09
====================
(1) Six months ended June 30
(unaudited)(millions of dollars) 2012 2011
============================================================================
Risk Management Activities Gains/(Losses):
Canadian Power (1) 1
U.S. Power (16) (12)
Natural Gas Storage (11) (10)
Interest rate - -
Foreign exchange (8) (1)
Income taxes attributable to risk management
activities 12 8
--------------------
Risk Management Activities (24) (14)
====================
Consolidated Results of Operations
Second Quarter Results
Comparable Earnings in second quarter 2012 were $300 million or $0.43 per share compared to $355 million or $0.51 per share for the same period in 2011. Results for second quarter 2012 included an after-tax charge of $37 million ($50 million pre-tax) related to the impact of the Sundance A power purchase arrangement (PPA) arbitration decision which was received in July 2012. Of this amount, $15 million ($20 million pre-tax) is excluded from Comparable Earnings as it relates to amounts recorded in fourth quarter 2011 and $22 million ($30 million pre-tax) is included in Comparable Earnings as it relates to amounts recorded in first quarter 2012. In addition, the Company did not recognize any pre-tax income from the Sundance A PPA in second quarter 2012 or in the first six months of 2012. Refer to the Recent Developments section of this MD&A for further discussion regarding the Sundance A PPA arbitration decision. Comparable Earnings also excluded net unrealized after-tax losses of $13 million ($14 million pre-tax) (2011 - losses of $2 million after tax ($3 million pre-tax)) resulting from changes in the fair value of certain risk management activities.
Comparable Earnings decreased $55 million or $0.08 per share in second quarter 2012 compared to the same period in 2011 and reflected the following:
-- decreased Canadian Natural Gas Pipelines Comparable net income primarily
due to lower earnings from the Canadian Mainline which excluded
incentive earnings and reflected a lower investment base;
-- decreased U.S. and International Natural Gas Pipelines EBIT which
reflected lower earnings from ANR as well as the impact of uncontracted
capacity and capacity sold at lower rates on Great Lakes, partially
offset by incremental earnings from the Guadalajara pipeline which was
placed in service in June 2011;
-- increased Oil Pipelines Comparable EBIT which reflected higher final
fixed tolls for the Wood River/Patoka section of the Keystone Pipeline
system which came into effect in May 2011, as well as higher volumes;
-- decreased Energy Comparable EBIT primarily due to the impacts of the
Sundance A PPA arbitration decision, lower realized power prices in
U.S. Power and reduced waterflows at the U.S. hydro facilities, as
well as lower volumes generated under Alberta PPAs, partially offset by
higher contributions from Eastern Power due to higher Becancour
contractual earnings, and incremental earnings from Montagne-Seche and
phase one of Gros-Morne at Cartier Wind which were both placed in
service in November 2011, and an increase in Equity Income from Bruce
Power primarily due to lower lease and operating costs;
-- decreased Comparable Interest Income and Other due to lower realized
gains in 2012 compared to 2011 on derivatives used to manage the
Company's exposure to foreign exchange rate fluctuations on U.S. dollar-
denominated income; and
-- decreased Comparable Income Taxes primarily due to lower pre-tax
earnings in 2012 compared to 2011, partially offset by changes in the
proportion of income earned between Canadian and foreign jurisdictions.
Comparable Earnings in the first six months of 2012 were $663 million or $0.94 per share compared to $778 million or $1.11 per share for the same period in 2011. Comparable Earnings in the first six months of 2012 excluded the after-tax charge of $15 million ($20 million pre-tax) related to the Sundance A PPA arbitration decision recorded in second quarter 2012 and net unrealized after-tax losses of $24 million ($36 million pre-tax) (2011 - losses of $14 million after tax ($22 million pre-tax)) resulting from changes in the fair value of certain risk management activities.
Comparable Earnings decreased $115 million or $0.17 per share for the first six months of 2012 compared to the same period in 2011 and reflected the following:
-- decreased Canadian Natural Gas Pipelines Comparable net income primarily
due to lower earnings from the Canadian Mainline which excluded
incentive earnings and reflected a lower investment base;
-- decreased U.S. and International Natural Gas Pipelines EBIT which
reflected lower revenue resulting from uncontracted capacity and lower
rates on Great Lakes as well as lower earnings from ANR, partially
offset by incremental earnings from the Guadalajara pipeline, which was
placed in service in June 2011;
-- increased Oil Pipelines Comparable EBIT as the Company commenced
recording earnings from the Keystone Pipeline System in February 2011
and higher final fixed tolls for the Wood River/Patoka section which
came into effect in May 2011, as well as higher volumes;
-- decreased Energy Comparable EBIT primarily as a result of not
recognizing earnings from the Sundance A PPA in 2012 following the
arbitration decision, lower realized power prices and reduced waterflows
at U.S. hydro facilities, a decrease in Equity Income from Bruce Power
primarily due to lower volumes resulting from increased planned outage
days and lower Natural Gas Storage revenue, partially offset by higher
contributions from Eastern Power primarily due to higher Becancour
contractual earnings and incremental earnings from Montagne-Seche and
phase one of Gros-Morne which were placed in service in November 2011;
-- increased Comparable Interest Expense due to incremental interest
expense on debt issues, lower capitalized interest for assets placed in
service and the negative impact of a stronger U.S. dollar on U.S.
dollar-denominated interest;
-- decreased Comparable Interest Income and Other due to lower realized
gains on derivatives used to manage the Company's exposure to foreign
exchange rate fluctuations on U.S. dollar-denominated income in 2012
compared to 2011; and
-- decreased Comparable Income Taxes primarily due to lower pre-tax
earnings in 2012 compared to 2011, and changes in the proportion of
income earned between Canadian and foreign jurisdictions.
U.S. Dollar-Denominated Balances
On a consolidated basis, the impact of changes in the value of the U.S. dollar on U.S. operations is partially offset by other U.S. dollar-denominated items as set out in the following table. The resultant pre-tax net exposure is managed using derivatives, further reducing the Company's exposure to changes in Canadian-U.S. foreign exchange rates. The average exchange rates to convert a U.S. dollar to a Canadian dollar for the three and six months ended June 30, 2012 were 1.01 and 1.01, respectively (2011 - 0.97 and 0.98, 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) 2012 2011 2012 2011
============================================================================
U.S. Natural Gas Pipelines Comparable EBIT(1) 147 169 362 412
U.S. Oil Pipelines Comparable EBIT(1) 88 81 177 132
U.S. Power Comparable EBIT(1) 8 65 14 97
Interest on U.S. dollar-denominated long-term
debt (183) (180) (369) (362)
Capitalized interest on U.S. capital
expenditures 27 25 53 72
U.S. non-controlling interests and other (45) (44) (96) (95)
----------------------------
42 116 141 256
============================
(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 $432 million and $925 million in the three and six months ended June 30, 2012, respectively, compared to $459 million and $1.0 billion, respectively, for the same periods in 2011.
Natural Gas Pipelines Results
Three months ended Six months ended
(unaudited) June 30 June 30
(millions of dollars) 2012 2011 2012 2011
===========================================================================
Canadian Natural Gas Pipelines
Canadian Mainline 247 267 497 532
Alberta System 183 181 360 366
Foothills 30 32 61 65
Other (TQM(1), Ventures LP) 7 9 15 17
--------------------------------
Canadian Natural Gas Pipelines Comparable
EBITDA(2) 467 489 933 980
Depreciation and amortization(3) (177) (178) (354) (356)
--------------------------------
Canadian Natural Gas Pipelines Comparable
EBIT(2) 290 311 579 624
--------------------------------
U.S. and International Natural Gas Pipelines
(in U.S. dollars)
ANR 53 69 150 178
GTN(4) 26 31 56 76
Great Lakes(5) 17 25 35 55
TC PipeLines, LP(1)(6)(7) 18 19 38 42
Other U.S. Pipelines (Iroquois(1), Bison(8),
Portland(7)(9)) 23 26 57 62
International (Tamazunchale,
Guadalajara(10), TransGas(1), Gas
Pacifico/INNERGY(1)) 30 15 58 25
General, administrative and support costs(11) (2) (2) (4) (4)
Non-controlling interests(7) 38 39 83 82
-------------------------------
U.S. and International Natural Gas Pipelines
Comparable EBITDA(2) 203 222 473 516
Depreciation and amortization(3) (56) (53) (111) (104)
-------------------------------
U.S. and International Natural Gas Pipelines
Comparable EBIT(2) 147 169 362 412
Foreign exchange 2 (6) 2 (9)
--------------------------------
U.S. and International Natural Gas Pipelines
Comparable EBIT(2) (in Canadian dollars) 149 163 364 403
--------------------------------
Natural Gas Pipelines Business Development
Comparable EBITDA and EBIT(2) (7) (15) (18) (23)
--------------------------------
Natural Gas Pipelines Comparable EBIT(2) 432 459 925 1,004
================================
Summary:
Natural Gas Pipelines Comparable EBITDA(2) 666 688 1,391 1,461
Depreciation and amortization(3) (234) (229) (466) (457)
--------------------------------
Natural Gas Pipelines Comparable EBIT(2) 432 459 925 1,004
================================
(1) Results from TQM, Northern Border, Iroquois, TransGas and Gas Pacifico
/INNERGY reflect the Company's share of equity income from these
investments.
(2) Refer to the Non-GAAP Measures section in this MD&A for further
discussion of Comparable EBITDA and Comparable EBIT.
(3) Does not include depreciation and amortization from equity investments.
(4) Results reflect TransCanada's direct ownership interest of 75 per cent
effective May 2011 and 100 per cent prior to that date.
(5) Represents TransCanada's 53.6 per cent direct ownership interest.
(6) Effective May 2011, TransCanada's ownership interest in TC PipeLines,
LP decreased from 38.2 per cent to 33.3 per cent. As a result, the TC
PipeLines, LP results include TransCanada's decreased ownership in TC
PipeLines, LP and TransCanada's effective ownership through TC
PipeLines, LP of 8.3 per cent of each of GTN and Bison since May 2011.
(7) Non-Controlling Interests reflects Comparable EBITDA for the portions
of TC PipeLines, LP and Portland not owned by TransCanada.
(8) Results reflect TransCanada's direct ownership of 75 per cent of Bison
effective May 2011 when 25 per cent was sold to TC PipeLines, LP and
100 per cent since January 2011 when Bison was placed in service.
(9) Represents TransCanada's 61.7 per cent ownership interest.
(10) Includes Guadalajara's operations since June 2011.
(11) Represents General, Administrative and Support Costs associated with
certain of TransCanada's pipelines.
Net Income for Wholly Owned Canadian Natural Gas Pipelines
Three months ended Six months ended
(unaudited) June 30 June 30
(millions of U.S. dollars) 2012 2011 2012 2011
===========================================================================
Canadian Mainline 46 63 93 125
Alberta System 52 50 100 98
Foothills 4 6 9 12
========================================
Canadian Natural Gas Pipelines
Canadian Mainline's net income of $46 million and $93 million in the three and six months ended June 30, 2012, respectively, decreased $17 million and $32 million from $63 million and $125 million in the same periods in 2011. Canadian Mainline's net income for the three and six months ended June 30, 2011 included incentive earnings earned under an incentive arrangement in the five-year tolls settlement which expired December 31, 2011. Absent a National Energy Board (NEB) decision with respect to 2012 tolls, Canadian Mainline's 2012 year-to-date results reflect the last approved rate of return on common equity of 8.08 per cent on deemed common equity of 40 per cent and exclude incentive earnings. In addition, Canadian Mainline's 2012 year-to-date net income decreased compared to the prior year as a result of a lower average investment base.
The Alberta System's net income in the three and six months ended June 30, 2012 was $52 million and $100 million, respectively, compared to $50 million and $98 million for the same periods in 2011. The positive impact on 2012 net income from a higher average investment base was partially offset by lower incentive earnings.
EBITDA from the Canadian Mainline and the Alberta System reflect the net income variances discussed above as well as variances in depreciation, financial charges and income taxes which are recovered in revenue on a flow-through basis and, therefore, do not impact net income.
U.S. and International Natural Gas Pipelines
ANR's Comparable EBITDA in the three and six months ended June 30, 2012 was US$53 million and US$150 million, respectively, compared to US$69 million and US$178 million for the same periods in 2011. The decreases were primarily due to lower transportation and storage revenues, a second quarter 2011 settlement with a counterparty and lower incidental commodity sales.
GTN's Comparable EBITDA in the three and six months ended June 30, 2012 was US$26 million and US$56 million, respectively, compared to US$31 million and US$76 million for the same periods in 2011. The decreases were primarily due to TransCanada's sale of a 25 per cent interest in GTN to TC PipeLines, LP in May 2011 as well as lower contracted transportation revenues.
Great Lakes' Comparable EBITDA in the three and six months ended June 30, 2012 was US$17 million and US$35 million, respectively, compared to US$25 million and US$55 million for the same periods in 2011. The decreases were due to lower transportation revenue resulting from unsold long-term, long-haul winter capacity as well as summer capacity sold under short-term contracts at lower rates compared to the same period in 2011.
International Comparable EBITDA increased US$15 million and US$33 million for the three and six months ended June 30, 2012, respectively, compared to the same periods in 2011. The increases were primarily due to incremental earnings from the Guadalajara pipeline, which was placed in service in June 2011.
Business Development
Natural Gas Pipelines' Business Development Comparable EBITDA loss from business development expenses decreased $8 million and $5 million in the three and six months ended June 30, 2012, respectively, compared to the same periods in 2011. The decreases in business development costs were primarily related to reduced activity in 2012 for the Alaska Pipeline project and a levy charged by the NEB in March 2011 to recover the Aboriginal Pipeline Group's proportionate share of costs relating to the Mackenzie Gas Project hearings.
Depreciation and Amortization
Natural Gas Pipelines' Depreciation and Amortization increased $5 million and $9 million for the three and six months ended June 30, 2012, respectively, compared to the same periods in 2011. The increases were primarily due to incremental depreciation for the Guadalajara pipeline which was placed in service in June 2011.
Operating Statistics
Canadian Alberta
Six months ended June 30 Mainline(1) System(2) ANR(3)
(unaudited) 2012 2011 2012 2011 2012 2011
===========================================================================
Average investment base (millions of
dollars) 5,775 6,328 5,359 4,993 n/a n/a
Delivery volumes (Bcf)
Total 804 1,059 1,844 1,788 844 870
Average per day 4.4 5.9 10.1 9.9 4.6 4.8
=======================================
(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, 2012 were 455 billion cubic feet (Bcf)
(2011 - 643 Bcf); average per day was 2.5 Bcf (2011 - 3.6 Bcf).
(2) Field receipt volumes for the Alberta System for the six months ended
June 30, 2012 were 1,856 Bcf (2011 - 1,733 Bcf); average per day was
10.2 Bcf (2011 - 9.6 Bcf).
(3) Under its current rates, which are approved by the FERC, ANR's results
are not impacted by changes in its average investment base.
Oil Pipelines
Oil Pipelines Comparable EBIT for the three and six months ended June 30, 2012 was $140 million and $277 million, respectively, compared to $119 million and $195 million for the same periods in 2011.
Oil Pipelines Results
Three Six Five
months months months
ended ended ended
(unaudited) June 30 June 30 June 30
(millions of dollars) 2012 2011 2012 2011
============================================================================
Keystone Pipeline System 178 154 352 253
Oil Pipeline Business Development (2) (1) (3) (1)
----------------------------------------
Oil Pipelines Comparable EBITDA(1) 176 153 349 252
Depreciation and amortization (36) (34) (72) (57)
----------------------------------------
Oil Pipelines Comparable EBIT(1) 140 119 277 195
========================================
Comparable EBIT denominated as follows:
Canadian dollars 51 41 99 67
U.S. dollars 88 81 177 132
Foreign exchange 1 (3) 1 (4)
----------------------------------------
Oil Pipelines Comparable EBIT(1) 140 119 277 195
========================================
(1) Refer to the Non-GAAP Measures section in this MD&A for further
discussion of Comparable EBITDA and Comparable EBIT.
Keystone Pipeline System
The Keystone Pipeline System's Comparable EBITDA of $178 million and $352 million for the three and six months ended June 30, 2012, respectively, increased $24 million and $99 million, compared to 2011. These increases reflected higher contracted revenues resulting primarily from the incremental impact of higher final fixed tolls which came into effect in May 2011 on the Wood River/Patoka section of the system, higher volumes and six months of earnings being recorded in 2012 compared to five months in 2011.
EBITDA from the Keystone Pipeline System is primarily generated from payments received under long-term commercial arrangements for committed capacity that are not dependant on actual throughput. Uncontracted capacity is offered to the market on a spot basis and, when capacity is available, provides opportunities to generate incremental EBITDA.
Depreciation and Amortization
Oil Pipelines depreciation and amortization increased $15 million for the six months ended June 30, 2012 compared to the same period in 2011 and primarily reflected six months of operations compared to five months in 2011 for the Wood River/Patoka and Cushing Extension sections of the Keystone Pipeline System.
Operating Statistics
Three Six Five
months months months
ended ended ended
June 30 June 30 June 30
(unaudited) 2012 2011 2012 2011
============================================================================
Delivery volumes (thousands
of barrels)(1)
Total 45,933 30,167 94,697 52,633
Average per day 505 332 520 351
================================================
(1) Delivery volumes reflect physical deliveries.
Energy
Energy's Comparable EBIT was $98 million and $269 million for the three and six months ended June 30, 2012, respectively, compared to $185 million and $433 million, respectively, for the same periods in 2011.
Energy Results
Three months ended Six months ended
(unaudited) June 30 June 30
(millions of dollars) 2012 2011 2012 2011
============================================================================
Canadian Power
Western Power(1)(2) 27 72 158 191
Eastern Power(1)(3) 73 67 166 143
Bruce Power(1) 31 21 18 64
General, administrative and support
costs (11) (9) (22) (17)
----------------------------------------
Canadian Power Comparable EBITDA(4) 120 151 320 381
Depreciation and amortization(5) (39) (35) (79) (69)
----------------------------------------
Canadian Power Comparable EBIT(4) 81 116 241 312
----------------------------------------
U.S. Power (in U.S. dollars)
Northeast Power 49 99 95 170
General, administrative and support
costs (11) (10) (21) (19)
----------------------------------------
U.S. Power Comparable EBITDA(4) 38 89 74 151
Depreciation and amortization (30) (24) (60) (54)
----------------------------------------
U.S. Power Comparable EBIT(4) 8 65 14 97
Foreign exchange 1 (3) 1 (3)
----------------------------------------
U.S. Power Comparable EBIT(4) (in
Canadian dollars) 9 62 15 94
----------------------------------------
Natural Gas Storage
Alberta Storage(1) 19 20 34 50
General, administrative and support
costs (2) (3) (4) (5)
----------------------------------------
Natural Gas Storage Comparable
EBITDA(4) 17 17 30 45
Depreciation and amortization(5) (3) (4) (6) (7)
----------------------------------------
Natural Gas Storage Comparable
EBIT(4) 14 13 24 38
----------------------------------------
Energy Business Development
Comparable EBITDA and EBIT(1)(4) (6) (6) (11) (11)
----------------------------------------
Energy Comparable EBIT(1)(4) 98 185 269 433
========================================
Summary:
Energy Comparable EBITDA(4) 170 248 414 562
Depreciation and amortization(5) (72) (63) (145) (129)
----------------------------------------
Energy Comparable EBIT(4) 98 185 269 433
========================================
(1) Results from ASTC Power Partnership, Portlands Energy, Bruce Power and
CrossAlta reflect the Company's share of equity income from these
investments.
(2) Includes Coolidge effective May 2011.
(3) Includes Montagne-Seche and phase one of Gros-Morne at Cartier Wind
effective November 2011.
(4) Refer to the Non-GAAP Measures section in this MD&A for further
discussion of Comparable EBITDA and Comparable EBIT.
(5) Does not include depreciation and amortization of equity investments.
Canadian Power
Western and Eastern Canadian Power Comparable EBIT(1)(2)(3)
Three months ended Six months ended
(unaudited) June 30 June 30
(millions of dollars) 2012 2011 2012 2011
============================================================================
Revenue
Western Power(2) 106 143 330 364
Eastern Power(3) 98 91 201 187
Other(4) 22 17 47 40
----------------------------------------
226 251 578 591
----------------------------------------
(Loss)/Income from Equity
Investments(5) (6) 19 17 46
----------------------------------------
Commodity Purchases Resold
Western power (43) (72) (137) (176)
Other(6) - (4) (2) (9)
----------------------------------------
(43) (76) (139) (185)
----------------------------------------
Plant operating costs and other (47) (55) (102) (118)
Sundance A PPA arbitration
decision(7) (30) - (30) -
General, administrative and support
costs (11) (9) (22) (17)
----------------------------------------
Comparable EBITDA(1) 89 130 302 317
Depreciation and amortization (39) (35) (79) (69)
----------------------------------------
Comparable EBIT(1) 50 95 223 248
========================================
(1) Refer to the Non-GAAP Measures section in this MD&A for further
discussion of Comparable EBITDA and Comparable EBIT.
(2) Includes Coolidge effective May 2011.
(3) Includes Montagne-Seche and phase one of Gros-Morne at Cartier Wind
effective November 2011.
(4) Includes sales of excess natural gas purchased for generation and
thermal carbon black.
(5) Results reflect equity income from TransCanada's 50 per cent ownership
interest in each of ASTC Power Partnership, which holds the Sundance B
PPA, and Portlands Energy.
(6) Includes the cost of excess natural gas not used in operations.
(7) Refer to the Recent Developments section in this MD&A for more
information regarding the Sundance A PPA arbitration decision.
Western and Eastern Canadian Power Operating Statistics(1)
Three months ended Six months ended
June 30 June 30
(unaudited) 2012 2011 2012 2011
============================================================================
Volumes (GWh)
Generation
Western Power(2) 654 626 1,325 1,307
Eastern Power(3) 907 770 2,050 1,848
Purchased
Sundance A, B and Sheerness
PPAs(4) 1,295 1,855 3,334 3,960
Other purchases 1 55 46 143
----------------------------------------
2,857 3,306 6,755 7,258
----------------------------------------
Contracted
Western Power(2) 1,741 1,919 4,036 4,074
Eastern Power(3) 907 770 2,050 1,848
Spot
Western Power 209 617 669 1,336
----------------------------------------
2,857 3,306 6,755 7,258
========================================
Plant Availability(5)
Western Power(2)(6) 97% 97% 98% 97%
Eastern Power(3)(7) 78% 92% 85% 95%
========================================
(1) Includes TransCanada's share of Equity Investments' volumes.
(2) Includes Coolidge effective May 2011.
(3) Includes Montagne-Seche and phase one of Gros-Morne at Cartier Wind
effective November 2011 and volumes related to TransCanada's 50 per
cent ownership interest in Portlands Energy.
(4) Includes TransCanada's 50 per cent ownership interest of Sundance B
volumes through the ASTC Power Partnership. No volumes were delivered
under the Sundance A PPA in 2012 or 2011.
(5) Plant availability represents the percentage of time in a period that
the plant is available to generate power regardless of whether it is
running.
(6) Excludes facilities that provide power under PPAs.
(7) Becancour has been excluded from the availability calculation as power
generation has been suspended since 2008.
Western Power's Comparable EBITDA of $27 million and $158 million for the three and six months ended June 30, 2012 decreased $45 million and $33 million compared to the same periods of 2011, respectively.
Throughout first quarter 2012, revenues and costs related to the Sundance A PPA had been recorded as though the outages of Units 1 and 2 were interruptions of supply. As a result of the Sundance A PPA arbitration decision received in July 2012, a $30 million charge equivalent to the amount of pre-tax income recorded in first quarter 2012, was recorded in second quarter 2012. In addition, no further revenues or costs related to the Sundance A PPA were recorded in second quarter 2012. Western Power's Comparable EBITDA for the three and six months ended June 30, 2011 included $12 million and $51 million, respectively, of accrued earnings related to the Sundance A PPA. Refer to the Recent Developments section in this MD&A for further discussion regarding the Sundance A PPA arbitration decision.
Western Power's Comparable EBITDA in second quarter 2012 decreased $45 million compared to 2011 due to the charge related to the Sundance A PPA arbitration decision and not recognizing earnings from the Sundance A PPA in second quarter 2012 as well as lower PPA volumes primarily as a result of higher planned outage days, partially offset by the impact of incremental earnings from Coolidge which was placed in service in May 2011 and lower fuel costs.
Western Power's Comparable EBITDA for the six months ended June 30, 2012 decreased $33 million compared to the same period in 2011. The decrease reflected no EBITDA from the Sundance A PPA in 2012 as well as the impact of lower Sheerness PPA volumes, partially offset by incremental earnings from Coolidge, higher realized power prices and lower fuel costs.
Western Power Revenue of $106 million and $330 million for the three and six months ended June 30, 2012, respectively, decreased $37 million and $34 million, respectively, compared to the same periods in 2011 primarily due to not recognizing revenues in second quarter 2012 from the Sundance A PPA as well as lower Sheerness PPA volumes, partially offset by incremental earnings from Coolidge and higher realized power prices. Average spot market power prices decreased 23 per cent to $40 per megawatt hour (MWh) and 26 per cent to $50 per MWh for the three and six months ended June 30, 2012, respectively, compared to the same periods in 2011. Despite the decrease in spot prices, Western Power earned a higher realized price for the three and six months ended June 30, 2012 as a result of contracting activities.
Western Power's Commodity Purchases Resold of $43 million and $137 million for the three and six months ended June 30, 2012, respectively, decreased $29 million and $39 million, respectively, compared to the same periods in 2011, primarily due to not recognizing costs in second quarter 2012 from the Sundance A PPA as well as lower volumes purchased as a result of planned outages at Sheerness in 2012.
Eastern Power's Comparable EBITDA of $73 million and $166 million for the three and six months ended June 30, 2012 increased $6 million and $23 million, respectively, compared to the same periods in 2011. Similarly, Eastern Power's Power Revenues of $98 million and $201 million for the three and six months ended June 30, 2012 increased $7 million and $14 million, respectively, compared to the same periods in 2011. The increases were primarily due to higher Becancour contractual earnings and incremental earnings from Montagne-Seche and phase one of Gros-Morne at Cartier Wind, which were both placed in service in November 2011.
Income from Equity Investments decreased $25 million and $29 million for the three and six months ended June 30, 2012, respectively, to a loss of $6 million and income of $17 million, compared to the same periods in 2011. The decreases were primarily due to lower earnings from the ASTC Power Partnership as a result of lower volumes and prices for the Sundance B PPA and lower earnings from Portlands Energy due to an unplanned outage in second quarter 2012.
Plant Operating Costs and Other, which includes fuel gas consumed in power generation, of $47 million and $102 million for the three and six months ended June 30, 2012, respectively, decreased $8 million and $16 million, compared to the same periods in 2011, primarily due to decreased natural gas fuel prices in 2012 compared to 2011.
Depreciation and amortization increased $4 million and $10 million in the three and six months ended June 30, 2012, respectively, compared to the same periods in 2011 primarily due to incremental depreciation from Coolidge, Montagne-Seche and phase one of Gros-Morne.
Plant availability for Eastern Power of 78 per cent in second quarter 2012 decreased compared to second quarter 2011 due to an unplanned outage at Portlands Energy.
Approximately 89 per cent of Western Power sales volumes were sold under contract in second quarter 2012, compared to 76 per cent in second quarter 2011. While overall hedging levels were similar in both periods, the increased proportion of contracted volumes is a result of lower overall volumes primarily due to higher planned outages in 2012. To reduce its exposure to spot market prices in Alberta, as at June 30, 2012, Western Power had entered into fixed-price power sales contracts to sell approximately 4,500 gigawatt hours (GWh) for the remainder of 2012 and 7,000 GWh for 2013.
Eastern Power's sales volumes were 100 per cent sold under contract and are expected to be fully contracted going forward.
Bruce Power Results
(TransCanada's share)
(unaudited) Three months ended Six months ended
(millions of dollars unless June 30 June 30
otherwise indicated) 2012 2011 2012 2011
============================================================================
(Loss)/Income from Equity Investments(1)
Bruce A (23) 14 (56) 32
Bruce B 54 7 74 32
------------------------------------
31 21 18 64
====================================
Comprised of:
Revenues 185 202 347 415
Operating expenses (125) (146) (260) (282)
Depreciation and other (29) (35) (69) (69)
------------------------------------
31 21 18 64
====================================
Bruce Power - Other Information
Plant availability(2)
Bruce A 57% 97% 53% 98%
Bruce B 95% 80% 91% 86%
Combined Bruce Power 84% 85% 72% 89%
Planned outage days
Bruce A 62 8 153 8
Bruce B - 49 46 70
Unplanned outage days
Bruce A - 5 - 9
Bruce B 19 19 23 27
Sales volumes (GWh)(1)
Bruce A 895 1,436 1,642 2,936
Bruce B 2,047 1,760 3,956 3,792
------------------------------------
2,942 3,196 5,598 6,728
====================================
Realized sales price per MWh
Bruce A $68 $66 $67 $66
Bruce B(3) $56 $55 $55 $54
Combined Bruce Power $58 $59 $58 $58
====================================
(1) Represents TransCanada's 48.9 per cent ownership interest in Bruce A and
31.6 per cent ownership interest in Bruce B.
(2) Plant availability represents the percentage of time in a year that the
plant is available to generate power regardless of whether it is
running.
(3) Includes revenue received under the floor price mechanism and from
contract settlements as well as volumes and revenues associated with
deemed generation.
TransCanada's Equity Income from Bruce A decreased $37 million and $88 million for the three and six months ended June 30, 2012, respectively, to losses of $23 million and $56 million compared to income of $14 million and $32 million for the same periods in 2011. The decreases were primarily due to lower volumes resulting from the West Shift Plus planned outage on Unit 3 which commenced in November 2011 and was completed in June 2012.
TransCanada's Equity Income from Bruce B for the three and six months ended June 30, 2012 of $54 million and $74 million, respectively, increased $47 million and $42 million, compared to the same periods in 2011. The increases were primarily due to higher volumes and lower operating costs resulting from fewer planned outage days, and lower lease expense. Provisions in the Bruce B lease agreement with Ontario Power Generation provide for a reduction in annual lease expense if the annual average Ontario spot price for electricity is less than $30 per MWh. The average spot price has been below $30 per MWh for the first six months of 2012, and this is expected to continue throughout 2012.
Under a contract with the Ontario Power Authority (OPA), all output from Bruce A in second quarter 2012 was sold at a fixed price of $68.23 per MWh (before recovery of fuel costs from the OPA) compared to $66.33 per MWh in second quarter 2011. Also under a contract with the OPA, all output from the Bruce B units was subject to a floor price of $51.62 per MWh in second quarter 2012 compared to $50.18 in second quarter 2011. Both the Bruce A and Bruce B contract prices are adjusted annually for inflation on April 1.
Amounts received under the Bruce B floor price mechanism, within a calendar year, are subject to repayment if the monthly average spot price exceeds the floor price. With respect to 2012, TransCanada currently expects spot prices to be less than the floor price for the year, therefore, no amounts recorded in revenues in 2012 are expected to be repaid.
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 increased by $1 per MWh to $56 per MWh and $55 per MWh in the three and six months ended June 30, 2012, respectively, and reflected revenues recognized from the floor price mechanism, contract sales and deemed generation.
The overall plant availability percentage in 2012 is expected to be in the low 60s for Bruce A Units 3 and 4. Planned maintenance on one of the units at Bruce A is scheduled during the second half of 2012. Bruce B's overall plant availability percentage is expected to be in the mid 90s for the four units in 2012.
U.S. Power
U.S. Power Comparable EBIT(1)
Three months ended Six months ended
(unaudited) June 30 June 30
(millions of U.S. dollars) 2012 2011 2012 2011
============================================================================
Revenues
Power(2) 192 224 353 479
Capacity 66 74 106 113
Other(3) 5 13 24 43
------------------------------------
263 311 483 635
------------------------------------
Commodity purchases resold (122) (84) (205) (215)
Plant operating costs and other(3) (92) (128) (183) (250)
General, administrative and support costs (11) (10) (21) (19)
------------------------------------
Comparable EBITDA(1) 38 89 74 151
Depreciation and amortization (30) (24) (60) (54)
------------------------------------
Comparable EBIT(1) 8 65 14 97
====================================
(1) Refer to the Non-GAAP Measures section in this MD&A for further
discussion of Comparable EBITDA and Comparable EBIT.
(2) 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.
(3) Includes revenues and costs related to a third-party service agreement
at Ravenswood, the activity level of which was decreased in 2011.
U.S. Power Operating Statistics
Three months ended Six months ended
June 30 June 30
(unaudited) 2012 2011 2012 2011
============================================================================
Physical Sales Volumes (GWh)
Supply
Generation 1,787 1,941 2,941 3,232
Purchased 1,687 1,181 3,641 3,120
----------------------------------------
3,474 3,122 6,582 6,352
========================================
Plant Availability(1) 82% 86% 81% 84%
========================================
(1) Plant availability represents the percentage of time in a period that
the plant is available to generate power regardless of whether it is
running.
U.S Power's Comparable EBITDA of US$38 million and US$74 million for the three and six months ended June 30, 2012, respectively, decreased US$51 million and US$77 million compared to the same periods in 2011. The reductions were primarily due to lower realized power prices, which were negatively impacted by lower natural gas prices and lower power demand, higher load serving costs, and reduced water flows at the U.S. hydro facilities.
Physical sales volumes in second quarter 2012 increased compared to the same period in 2011 primarily due to higher purchased volumes resulting from new sales activity in the PJM and New England markets, while generation volumes decreased primarily due to lower hydro volumes.
U.S Power's Power Revenue of US$192 million and US$353 million for the three and six months ended June 30, 2012, respectively, decreased US$32 million and US$126 million compared to the same periods in 2011. The reduction was primarily due to lower realized power prices and lower volumes from the U.S. hydro facilities, partially offset by increased volumes of power purchased for resale.
Capacity Revenue of US$66 million and US$106 million for the three and six months ended June 30, 2012, respectively, decreased US$8 million and US$7 million compared to the same periods in 2011 due to lower realized capacity prices in New York and New England.
Commodity Purchases Resold for the three months ended June 30, 2012 of US$122 million increased US$38 million compared to the same period in 2011 due to higher volumes of power purchased for resale under power sales commitments to wholesale, commercial and industrial customers and higher load serving costs, partially offset by lower realized power prices. Commodity purchases resold for the six months ended June 30, 2012 of US$205 million decreased US$10 million compared to the same period in 2011, primarily due to lower realized power prices.
Plant Operating Costs and Other, which includes fuel gas consumed in generation, of US$92 million and US$183 million for the three and six months ended June 30, 2012, respectively, decreased US$36 million and US$67 million compared to the same period in 2011, primarily due to lower natural gas fuel prices.
As at June 30, 2012, approximately 2,500 GWh or 46 per cent and 2,200 GWh or 26 per cent of U.S. Power's planned generation is contracted for the remainder 2012 and fiscal 2013, respectively. Planned generation fluctuates depending on hydrology, wind conditions, commodity prices and the resulting dispatch of the assets. Power sales fluctuate based on customer usage.
Natural Gas Storage
Natural Gas Storage's Comparable EBITDA for the three and six month periods ended June 30, 2012 was $17 million and $30 million, respectively, compared to $17 million and $45 million, respectively, for the same periods in 2011. The decrease in Comparable EBITDA in the six months ended June 30, 2012 compared to the same period in 2011 was primarily due to lower realized natural gas price spreads in first quarter 2012.
Other Income Statement Items
Comparable Interest Expense(1)
Three months ended Six months ended
(unaudited) June 30 June 30
(millions of dollars) 2012 2011 2012 2011
============================================================================
Interest on long-term debt(2)
Canadian dollar-denominated 127 122 255 244
U.S. dollar-denominated 183 180 369 362
Foreign exchange - (5) - (8)
----------------------------------------
310 297 624 598
Other interest and amortization 5 7 7 13
Capitalized interest (76) (68) (150) (165)
----------------------------------------
Comparable Interest Expense(1) 239 236 481 446
========================================
(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 of $239 million and $481 million for the three and six months ended June 30, 2012 increased $3 million and $35 million, respectively, compared to the same periods in 2011. The increase in interest expense for the six months ended June 30, 2012 was primarily due to incremental interest expense on debt issues of US$500 million in March 2012 and $750 million in November 2011 and a TC PipeLines, LP debt issue of US$350 million in June 2011, as well as the negative impact of a stronger U.S. dollar on U.S. dollar-denominated interest, and lower capitalized interest for Keystone, Coolidge and Guadalajara as a result of placing these assets in service, partially offset by higher realized gains in 2012 compared to 2011 from derivatives used to manage the Company's exposure to rising interest rates and the impact of Canadian and U.S. dollar-denominated debt maturities in 2012 and 2011.
Comparable Interest Income and Other of $19 million and $44 million for the three and six months ended June 30, 2012 decreased $9 million and $12 million, respectively, compared to the same periods in 2011. These decreases were primarily due to lower realized gains in 2012 compared to 2011 on derivatives used to manage the Company's net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income.
Comparable Income Taxes were $91 million and $231 million in the three and six months ended June 30, 2012, respectively, compared to $139 million and $326 million for the same periods in 2011. The decreases were primarily due to lower pre-tax earnings in 2012 compared to 2011 and changes in the proportion of income earned between Canadian and foreign jurisdictions.
Liquidity and Capital Resources
TransCanada believes that its financial position remains sound as does its ability to generate cash in the short and long term to provide liquidity, maintain financial capacity and flexibility, and provide for planned growth. TransCanada's liquidity is underpinned by predictable cash flow from operations, available cash balances and unutilized committed revolving bank lines of US$1.0 billion, US$1.0 billion, US$300 million and $2.0 billion, maturing in October 2012, November 2012, February 2013 and October 2016, respectively. These facilities also support the Company's three commercial paper programs. In addition, at June 30, 2012, TransCanada's proportionate share of unutilized capacity on committed bank facilities at the Company's operated affiliates was $89 million with maturity dates in 2016. As at June 30, 2012, TransCanada had remaining capacity of $2.0 billion, $1.25 billion and US$3.5 billion under its equity, Canadian debt and U.S. debt shelf prospectuses, respectively. TransCanada's liquidity, market and other risks are discussed further in the Risk Management and Financial Instruments section in this MD&A.
Operating Activities
Funds Generated from Operations(1)
Three months ended Six months ended
(unaudited) June 30 June 30
(millions of dollars) 2012 2011 2012 2011
============================================================================
Cash Flows
Funds generated from operations(1) 729 847 1,600 1,691
Decrease/(increase) in operating
working capital 14 46 (155) 65
----------------------------------------
Net cash provided by operations 743 893 1,445 1,756
========================================
(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 decreased $150 million and $311 million in the three and six months ended June 30, 2012, respectively, compared to the same periods in 2011, largely as a result of fluctuations in operating working capital.
As at June 30, 2012, TransCanada's current assets were $2.8 billion and current liabilities were $5.4 billion resulting in a working capital deficiency of $2.6 billion. The Company believes this shortfall can be managed through its ability to generate cash flow from operations as well as its ongoing access to capital markets.
Investing Activities
In the three and six months ended June 30, 2012, capital expenditures totalled $397 million and $861 million, respectively (2011- $487 million and $1,088 million, respectively) primarily related to the expansion of the Alberta System and expansion of the Keystone Pipeline System. Equity investments of $197 million and $413 million for the three and six months ended June 30, 2012, respectively (2011 - $121 million and $238 million, respectively) were primarily related to the Company's investment in the refurbishment and restart of Bruce Power Units 1 and 2.
Financing Activities
In March 2012, TransCanada PipeLines Limited (TCPL) issued US$500 million of senior notes maturing on March 2, 2015 and bearing interest at an annual rate of 0.875 per cent. These notes were issued under the US$4.0 billion debt shelf prospectus filed in November 2011. The net proceeds of this offering were used for general corporate purposes and to reduce short-term indebtedness.
In May 2012, TCPL retired US$200 million of 8.625 per cent senior notes. In January 2012, TransCanada PipeLine USA Ltd. repaid the remaining principal of US$500 million on its five-year term loan.
The Company believes it has the capacity to fund its existing capital program through internally-generated cash flow, continued access to capital markets and liquidity underpinned by in excess of $4 billion of committed credit facilities. TransCanada's financial flexibility is further bolstered by opportunities for portfolio management, including an ongoing role for TC PipeLines, LP.
Dividends
On July 26, 2012, TransCanada's Board of Directors declared a quarterly dividend of $0.44 per share for the quarter ending September 30, 2012 on the Company's outstanding common shares. The dividend is payable on October 31, 2012 to shareholders of record at the close of business on September 28, 2012. In addition, quarterly dividends of $0.2875 and $0.25 per Series 1 and Series 3 preferred share, respectively, were declared for the quarter ending September 30, 2012. The dividends are payable on September 28, 2012 to shareholders of record at the close of business on August 31, 2012. Furthermore, a quarterly dividend of $0.275 per Series 5 preferred share was declared for the period ending October 30, 2012, payable on October 30, 2012 to shareholders of record at the close of business on September 28, 2012.
Contractual Obligations
There have been no material changes, except for decreases to market-based commodity purchase commitments of approximately $1.1 billion, to TransCanada's contractual obligations from December 31, 2011 to June 30, 2012, including payments due for the next five years and thereafter. For further information on these contractual obligations, refer to the MD&A in TransCanada's 2011 Annual Report.
Significant Accounting Policies and Critical Accounting Estimates
The condensed consolidated financial statements of TransCanada have been prepared by management in accordance with U.S. GAAP. Comparative figures, which were previously presented in accordance with CGAAP, have been adjusted as necessary to be compliant with the Company's accounting policies under U.S. GAAP. The amounts adjusted for U.S. GAAP in these condensed consolidated financial statements for the three and six months ended June 30, 2011 are the same as those that have been previously reported in the Company's June 30, 2011 Reconciliation to U.S. GAAP. The amounts adjusted for U.S. GAAP at December 31, 2011 are the same as those reported in Note 25 of TransCanada's 2011 audited Consolidated Financial Statements included in TransCanada's 2011 Annual Report. The significant accounting policies and critical accounting estimates applied are consistent with those outlined in TransCanada's 2011 Annual Report, except as described below, which outlines the Company's significant accounting policies that have changed upon adoption of U.S. GAAP.
To prepare financial statements that conform with U.S. 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.
Changes in Accounting Policies
Changes to Significant Accounting Policies Upon Adoption of U.S. GAAP
Principles of Consolidation
The condensed consolidated financial statements include the accounts of TransCanada and its subsidiaries. The Company consolidates its interests in entities over which it is able to exercise control. To the extent there are interests owned by other parties, these interests are included in Non-Controlling Interests. TransCanada uses the equity method of accounting for corporate joint ventures in which the Company is able to exercise joint control and for investments in which the Company is able to exercise significant influence. TransCanada records its proportionate share of undivided interests in certain assets.
Inventories
Inventories primarily consist of materials and supplies, including spare parts and fuel, and natural gas inventory in storage, and are recorded at the lower of weighted average cost or market.
Income Taxes
The Company uses the liability method of accounting for income taxes. This method requires the recognition of deferred income tax assets and liabilities for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred income tax assets and liabilities are measured using enacted tax rates at the balance sheet date that are anticipated to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. Changes to these balances are recognized in income in the period during which they occur except for changes in balances related to the Canadian Mainline, Alberta System and Foothills, which are deferred until they are refunded or recovered in tolls, as permitted by the NEB.
Canadian income taxes are not provided on the unremitted earnings of foreign investments that the Company does not intend to repatriate in the foreseeable future.
Employee Benefit and Other Plans
The Company sponsors defined benefit pension plans (DB Plans), defined contribution plans (DC Plans), a Savings Plan and other post-retirement benefit plans. Contributions made by the Company to the DC Plans and Savings Plan are expensed in the period in which contributions are made. The cost of the DB Plans and other post-retirement benefits received by employees is actuarially determined using the projected benefit method pro-rated based on service and management's best estimate of expected plan investment performance, salary escalation, retirement age of employees and expected health care costs.
The DB Plans' assets are measured at fair value. The expected return on the DB Plans' assets is determined using market-related values based on a five-year moving average value for all of the DB Plans' assets. Past service costs are amortized over the expected average remaining service life of the employees. Adjustments arising from plan amendments are amortized on a straight-line basis over the average remaining service period of employees active at the date of amendment. The Company recognizes the overfunded or underfunded status of its DB Plans as an asset or liability on its Balance Sheet and recognizes changes in that funded status through Other Comprehensive (Loss)/Income (OCI) in the year in which the change occurs. The excess of net actuarial gains or losses over 10 per cent of the greater of the benefit obligation and the market-related value of the DB Plans' assets, if any, is amortized out of Accumulated Other Comprehensive (Loss)/Income (AOCI) over the average remaining service period of the active employees. For certain regulated operations, post-retirement benefit amounts are recoverable through tolls as benefits are funded. The Company records any unrecognized gains and losses or changes in actuarial assumptions related to these post-retirement benefit plans as either regulatory assets or liabilities. The regulatory assets or liabilities are amortized on a straight-line basis over the average remaining service life of active employees. When the restructuring of a benefit plan gives rise to both a curtailment and a settlement, the curtailment is accounted for prior to the settlement.
The Company has medium-term incentive plans, under which payments are made to eligible employees. The expense related to these incentive plans is accounted for on an accrual basis. Under these plans, benefits vest when certain conditions are met, including the employees' continued employment during a specified period and achievement of specified corporate performance targets.
Long-Term Debt Transaction Costs
The Company records long-term debt transaction costs as deferred assets and amortizes these costs using the effective interest method for all costs except those related to the Canadian natural gas regulated pipelines, which continue to be amortized on a straight-line basis in accordance with the provisions of tolling mechanisms.
Guarantees
Upon issuance, the Company records the fair value of certain guarantees. The fair value of these guarantees is estimated by discounting the cash flows that would be incurred by the Company if letters of credit were used in place of the guarantees. Guarantees are recorded as an increase to Equity Investments, Plant, Property and Equipment, or a charge to Net Income, and a corresponding liability is recorded in Deferred Amounts.
Changes in Accounting Policies for 2012
Fair Value Measurement
Effective January 1, 2012, the Company adopted the Accounting Standards Update (ASU) on fair value measurements as issued by the Financial Accounting Standards Board (FASB). Adoption of the ASU has resulted in an increase in the qualitative and quantitative disclosures regarding Level III measurements.
Intangibles - Goodwill and Other
Effective January 1, 2012, the Company adopted the ASU on testing goodwill for impairment as issued by the FASB. Adoption of the ASU has resulted in a change in the accounting policy related to testing goodwill for impairment, as the Company is now permitted under U.S. GAAP to first assess qualitative factors affecting the fair value of a reporting unit in comparison to the carrying amount as a basis for determining whether it is required to proceed to the two-step quantitative impairment test.
Future Accounting Changes
Balance Sheet Offsetting/Netting
In December 2011, the FASB issued amended guidance to enhance disclosures that will enable users of the financial statements to evaluate the effect, or potential effect, of netting arrangements on an entity's financial position. The amendments result in enhanced disclosures by requiring additional information regarding financial instruments and derivative instruments that are either offset in accordance with current U.S. GAAP or subject to an enforceable master netting arrangement. This guidance is effective for annual periods beginning on or after January 1, 2013. Adoption of these amendments is expected to result in an increase in disclosure regarding financial instruments which are subject to offsetting as described in this amendment.
Financial Instruments and Risk Management
TransCanada continues to manage and monitor its exposure to market risk, counterparty credit risk and liquidity risk.
Counterparty Credit and Liquidity Risk
TransCanada's maximum counterparty credit exposure with respect to financial instruments at the balance sheet date, without taking into account security held, consisted of accounts receivable, the fair value of derivative assets and notes receivable. The carrying amounts and fair values of these financial assets, except amounts for derivative assets, are included in Accounts Receivable and Other in the Non-Derivative Financial Instruments Summary table below. Letters of credit and cash are the primary types of security provided to support these amounts. The majority of counterparty credit exposure is with counterparties who are investment grade. At June 30, 2012, there were no significant amounts past due or impaired.
At June 30, 2012, the Company had a credit risk concentration of $288 million due from a counterparty. This amount is expected to be fully collectible and is secured by a guarantee from the counterparty's parent company.
The Company continues to manage its liquidity risk by ensuring sufficient cash and credit facilities are available to meet its operating and capital expenditure obligations when due, under both normal and stressed economic conditions.
Net Investment in Self-Sustaining Foreign Operations
The Company hedges its net investment in self-sustaining foreign operations on an after-tax basis with U.S. dollar-denominated debt, cross-currency interest rate swaps, forward foreign exchange contracts and foreign exchange options. At June 30, 2012, the Company had designated as a net investment hedge U.S. dollar-denominated debt with a carrying value of $10.4 billion (US$10.2 billion) and a fair value of $13.3 billion (US$13.1 billion). At June 30, 2012, $63 million (December 31, 2011 - $79 million) was included in Other Current Assets, $51 million (December 31, 2011 - $66 million) was included in Intangibles and Other Assets, $13 million (December 31, 2011 - $15 million) was included in Accounts Payable and $57 million (December 31, 2011 - $41 million) was included in Deferred Amounts for the fair value of forwards and swaps used to hedge the Company's net U.S. dollar investment in self-sustaining foreign operations.
Derivatives Hedging Net Investment in Self-Sustaining Foreign Operations
The fair values and notional principal amounts for the derivatives designated as a net investment hedge were as follows:
June 30, 2012 December 31, 2011
------------------------------------------
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 2012 to 2019)(2) 44 US 4,050 93 US 3,850
U.S. dollar forward foreign
exchange contracts
(maturing 2012) - US 700 (4) US 725
------------------------------------------
44 US 4,750 89 US 4,575
==========================================
(1) Fair values equal carrying values.
(2) Consolidated Net Income in the three and six months ended June 30, 2012
included net realized gains of $7 million and $14 million, respectively
(2011 - gains of $7 million and $12 million, respectively) related to
the interest component of cross- currency swap settlements.
Non-Derivative Financial Instruments Summary
The carrying and fair values of non-derivative financial instruments were as follows:
June 30, 2012 December 31, 2011
--------------------------------------------
(unaudited) Carrying Fair Carrying Fair
(millions of dollars) Amount(1) Value(2) Amount(1) Value(2)
============================================================================
Financial Assets
Cash and cash equivalents 490 490 654 654
Accounts receivable and other(3) 1,267 1,319 1,359 1,403
Available-for-sale assets(3) 35 35 23 23
--------------------------------------------
1,792 1,844 2,036 2,080
============================================
Financial Liabilities(4)
Notes payable 2,449 2,449 1,863 1,863
Accounts payable and deferred
amounts(5) 1,044 1,044 1,329 1,329
Accrued interest 363 363 365 365
Long-term debt 18,417 23,862 18,659 23,757
Junior subordinated notes 1,018 1,049 1,016 1,027
--------------------------------------------
23,291 28,767 23,232 28,341
============================================
(1) Recorded at amortized cost, except for US$350 million (December 31, 2011
- US$350 million) of Long-Term Debt that is recorded at fair value. This
debt which is recorded at fair value on a recurring basis is classified
in Level II of the fair value category using the income approach based
on interest rates from external data service providers.
(2) The fair value measurement of financial assets and liabilities recorded
at amortized cost for which the fair value is not equal to the carrying
value would be included in Level II of the fair value hierarchy using
the income approach based on interest rates from external data service
providers.
(3) At June 30, 2012, the Condensed Consolidated Balance Sheet included
financial assets of $1.0 billion (December 31, 2011 - $1.1 billion) in
Accounts Receivable, $40 million (December 31, 2011 - $41 million) in
Other Current Assets and $262 million (December 31, 2011 - $247 million)
in Intangibles and Other Assets.
(4) Consolidated Net Income in the three and six months ended June 30, 2012
included a gain of $3 million and a loss of $12 million, respectively
(2011 - losses of $2 million and $11 million, respectively) for fair
value adjustments related to interest rate swap agreements on US$350
million (2011 - US$350 million) of Long-Term Debt. There were no other
unrealized gains or losses from fair value adjustments to the
non-derivative financial instruments.
(5) At June 30, 2012, the Condensed Consolidated Balance Sheet included
financial liabilities of $919 million (December 31, 2011 - $1,192
million) in Accounts Payable and $125 million (December 31, 2011 -
$137 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, 2012
(unaudited)
(millions of Canadian
dollars unless otherwise Natural Foreign
indicated) Power Gas Exchange Interest
============================================================================
Derivative Financial
Instruments Held for
Trading(1)
Fair Values(2)
Assets $224 $150 $1 $18
Liabilities $(255) $(187) $(18) $(18)
Notional Values
Volumes(3)
Purchases 33,110 109 - -
Sales 33,374 85 - -
Canadian dollars - - - 620
U.S. dollars - - US 1,369 US 200
Cross-currency - - 47/US 37 -
Net unrealized
(losses)/gains in the
period(4)
Three months ended June
30, 2012 $(12) $4 $(14) -
Six months ended June 30,
2012 $(19) $(10) $(8) -
Net realized (losses)/gains
in the period(4)
Three months ended June
30, 2012 $(6) $(5) $6 -
Six months ended June 30,
2012 $9 $(15) $15 -
Maturity dates 2012-2016 2012-2016 2012-2013 2013-2016
Derivative Financial
Instruments in Hedging
Relationships(5)(6)
Fair Values(2)
Assets $38 - - $12
Liabilities $(242) $(15) $(36) -
Notional Values
Volumes(3)
Purchases 22,279 4 - -
Sales 9,310 - - -
U.S. dollars - - US 42 US 350
Cross-currency - 136/US 100 -
Net realized (losses)/gains
in the period(4)
Three months ended June
30, 2012 $(26) $(8) - $2
Six months ended June 30,
2012 $(58) $(14) - $3
Maturity dates 2012-2018 2012-2013 2012-2014 2013-2015
================================================
(1) All derivative financial instruments held for trading 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 derivative financial
instruments held for trading used to purchase and sell power and natural
gas are included net 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 $12 million and a notional amount of US$350
million. Net realized gains on fair value hedges for the three and six
months ended June 30, 2012 were $2 million and $4 million, respectively,
and were included in Interest Expense. In the three and six months ended
June 30, 2012, 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, 2012, there were no gains
or losses included in Net Income for discontinued cash flow hedges where
it was probable that the anticipated transaction would not occur. No
amounts have been excluded from the assessment of hedge effectiveness.
2011
(unaudited)
(millions of Canadian
dollars unless otherwise Natural Foreign
indicated) Power Gas Exchange Interest
============================================================================
Derivative Financial
Instruments Held for
Trading(1)
Fair Values(2)(3)
Assets $185 $176 $3 $22
Liabilities $(192) $(212) $(14) $(22)
Notional Values(3)
Volumes(4)
Purchases 21,905 103 - -
Sales 21,334 82 - -
Canadian dollars - - - 684
U.S. dollars - - US 1,269 US 250
Cross-currency - - 47/US 37 -
Net unrealized
gains/(losses) in the
period(5)
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(5)
Three months ended June
30, 2011 $6 $(15) $12 -
Six months ended June 30,
2011 $5 $(41) $33 $1
Maturity dates 2012-2016 2012-2016 2012 2012-2016
Derivative Financial
Instruments in Hedging
Relationships(6)(7)
Fair Values(2)(3)
Assets $16 $3 - $13
Liabilities $(277) $(22) $(38) $(1)
Notional Values(3)
Volumes(4)
Purchases 17,188 8 - -
Sales 8,061 - - -
U.S. dollars - - US 73 US 600
Cross-currency - 136/US 100 -
Net realized losses in the
period(5)
Three months ended June
30, 2011 $(13) $(5) - $(4)
Six months ended June 30,
2011 $(56) $(8) - $(9)
Maturity dates 2012-2017 2012-2013 2012-2014 2012-2015
================================================
(1) All derivative financial instruments held for trading 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) As at December 31, 2011.
(4) Volumes for power and natural gas derivatives are in GWh and Bcf,
respectively.
(5) Realized and unrealized gains and losses on derivative financial
instruments held for trading used to purchase and sell power and natural
gas are included net 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.
(6) 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 $13 million and a notional amount of US$350
million at December 31, 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.
(7) 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 where
it was probable that the anticipated transaction would not occur. 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 2012 December 31 2011
============================================================================
Current
Other current assets 343 361
Accounts payable (510) (485)
Long term
Intangibles and other assets 214 202
Deferred amounts (331) (349)
===================================
Derivatives in Cash Flow Hedging Relationships
The components of OCI related to derivatives in cash flow hedging relationships are as follows:
Cash Flow Hedges
-------------------------------------------------
Three months ended June 30
(unaudited) Foreign
(millions of dollars, Power Natural Gas Exchange Interest
pre-tax) 2012 2011 2012 2011 2012 2011 2012 2011
============================================================================
Changes in fair value of
derivative instruments
recognized in OCI
(effective portion) 44 (48) (4) (14) 4 (1) - (3)
Reclassification of gains
and (losses) on derivative
instruments from AOCI to
Net Income (effective
portion) 28 (2) 15 24 - - 4 8
Gains on derivative
instruments recognized in
earnings (ineffective
portion) 7 1 1 1 - - - -
=================================================
Cash Flow Hedges
------------------------------------------------
Six months ended June 30
(unaudited) Foreign
(millions of dollars, pre- Power Natural Gas Exchange Interest
tax) 2012 2011 2012 2011 2012 2011 2012 2011
============================================================================
Changes in fair value of
derivative instruments
recognized in OCI
(effective portion) (22) (104) (14) (25) 1 (7) - (3)
Reclassification of gains on
derivative instruments from
AOCI to Net Income
(effective portion) 75 32 28 52 - - 10 17
Gains and (losses) on
derivative instruments
recognized in earnings
(ineffective portion) 1 - (1) (1) - - - -
================================================
Derivative contracts entered into to manage market risk often contain financial assurance provisions that allow parties to the contracts to manage credit risk. These provisions may require collateral to be provided if a credit-risk-related contingent event occurs, such as a downgrade in the Company's credit rating to non-investment grade. Based on contracts in place and market prices at June 30, 2012, the aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a net liability position was $86 million (2011 - $96 million), for which the Company had provided collateral of $23 million (2011 - $5 million) in the normal course of business. If the credit-risk-related contingent features in these agreements were triggered on June 30, 2012, the Company would have been required to provide additional collateral of $63 million (2011 - $91 million) to its counterparties. Collateral may also need to be provided should the fair value of derivative instruments exceed pre-defined contractual exposure limit thresholds. The Company has sufficient liquidity in the form of cash and undrawn committed revolving bank lines to meet these contingent obligations should they arise.
Fair Value Hierarchy
The Company's assets and liabilities recorded at fair value have been classified into three categories based on the fair value hierarchy.
In Level I, the fair value of assets and liabilities is determined by reference to quoted prices in active markets for identical assets and liabilities that the Company has the ability to access at the measurement date.
In Level II, the fair value of interest rate and foreign exchange derivative assets and liabilities is determined using the income approach. The fair value of power and gas commodity assets and liabilities is determined using the market approach. Under both approaches, valuation is based on the extrapolation of inputs, other than quoted prices included within Level I, for which all significant inputs are observable directly or indirectly. Such inputs include published exchange rates, interest rates, interest rate swap curves, yield curves, and broker quotes from external data service providers. Transfers between Level I and Level II would occur when there is a change in market circumstances. There were no transfers between Level I and Level II in the six months ended June 30, 2012 and 2011.
In Level III, the fair value of assets and liabilities measured on a recurring basis is determined using a market approach based on inputs that are unobservable and significant to the overall fair value measurement. Assets and liabilities measured at fair value can fluctuate between Level II and Level III depending on the proportion of the value of the contract that extends beyond the time frame for which inputs are considered to be observable. As contracts near maturity and observable market data becomes available, they are transferred out of Level III and into Level II.
Long-dated commodity transactions in certain markets where liquidity is low are included in Level III of the fair value hierarchy, as the related commodity prices are not readily observable. Long-term electricity prices are estimated using a third-party modelling tool which takes into account physical operating characteristics of generation facilities in the markets in which the Company operates. Inputs into the model include market fundamentals such as fuel prices, power supply additions and retirements, power demand, seasonal hydro conditions and transmission constraints. Long-term North American natural gas prices are based on a view of future natural gas supply and demand, as well as exploration and development costs. Long-term prices are reviewed by management and the Board on a periodic basis. Significant decreases in fuel prices or demand for electricity or natural gas, or increases in the supply of electricity or natural gas would result in a lower fair value measurement of contracts included in Level III.
The fair value of the Company's assets and liabilities measured on a recurring basis, including both current and non-current portions, are categorized as follows:
Significant
Quoted Prices Other Significant
in Active Observable Unobservable
Markets Inputs Inputs
(Level I) (Level II) (Level III) Total
--------------------------------------------------------
(unaudited)
(millions of Jun 30 Dec 31 Jun 30 Dec 31 Jun 30 Dec 31 Jun 30 Dec 31
dollars, pre-tax) 2012 2011 2012 2011 2012 2011 2012 2011
============================================================================
Derivative Financial
Instrument Assets:
Interest rate
contracts - - 30 36 - - 30 36
Foreign exchange
contracts - - 114 141 - - 114 141
Power commodity
contracts - - 245 201 11 - 256 201
Gas commodity
contracts 114 124 32 55 - - 146 179
Derivative Financial
Instrument
Liabilities:
Interest rate
contracts - - (18) (23) - - (18) (23)
Foreign exchange
contracts - - (123) (102) - - (123) (102)
Power commodity
contracts - - (487) (454) (4) (15) (491) (469)
Gas commodity
contacts (176) (208) (22) (26) - - (198) (234)
Non-Derivative
Financial
Instruments:
Available-for-sale
assets 35 23 - - - - 35 23
--------------------------------------------------------
(27) (61) (229) (172) 7 (15) (249) (248)
========================================================
The following table presents the net change in the Level III fair value category:
Derivatives(1)(2)
-------------------------------------
Three months ended Six months ended
(unaudited) June 30 June 30
(millions of dollars, pre-tax) 2012 2011 2012 2011
============================================================================
Balance at beginning of period (11) (13) (15) (8)
New contracts - - - 1
Settlements (1) - (1) -
Transfers out of Level III(3) 1 - 1 -
Total gains/(losses) included in OCI 18 (17) 22 (23)
-------------------------------------
Balance at end of period 7 (30) 7 (30)
=====================================
(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, 2012, there were no
unrealized gains or losses included in Net Income attributable to
derivatives that were still held at the reporting date (2011 - nil).
(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 outstanding derivative financial instruments included in Level III as at June 30, 2012.
Other Risks
Additional risks faced by the Company are discussed in the MD&A in TransCanada's 2011 Annual Report. These risks remain substantially unchanged since December 31, 2011.
Controls and Procedures
As of June 30, 2012, an evaluation was carried out under the supervision of, and with the participation of management, including the President and Chief Executive Officer and the Chief Financial Officer, of the effectiveness of TransCanada's disclosure controls and procedures as defined under the rules adopted by the Canadian securities regulatory authorities and by the SEC. Based on this evaluation, the President and Chief Executive Officer and the Chief Financial Officer concluded that the design and operation of TransCanada's disclosure controls and procedures were effective at a reasonable assurance level as at June 30, 2012.
During the quarter ended June 30, 2012, there have been no changes in TransCanada's internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.
Outlook
Since the disclosure in TransCanada's 2011 Annual Report, the Company's overall earnings outlook for 2012 will be negatively impacted by the Sundance A PPA arbitration decision received in July 2012 which will result in the Company not recording earnings from the Sundance A PPA until the units are returned to service, which is not expected to occur in 2012. The delay in the return to service of Bruce Power's Unit 2 will also have a moderately adverse impact on the Company's earnings outlook. In addition, reduced demand for natural gas and electricity due to unseasonably warm winter weather, combined with continued strong U.S. natural gas production, has resulted in historically high natural gas storage levels and low natural gas prices, which are having a negative impact on revenues in U.S. Pipelines, and power prices in Canadian and U.S. Power. The Company's earnings outlook could also be affected by the uncertainty and ultimate resolution of the capacity pricing issues in New York and the force majeure claim at Bruce Power, as discussed in the Recent Developments section of this MD&A. For further information on outlook, refer to the MD&A in TransCanada's 2011 Annual Report.
Recent Developments
Natural Gas Pipelines
Canadian Mainline
2012-2013 Tolls Application
In 2011, TransCanada filed a comprehensive tolls application with the NEB to change the business structure and the terms and conditions of service for the Canadian Mainline. The hearing with respect to this application began on June 4, 2012 and is scheduled to conclude at the end of September, with a decision expected in late fourth quarter 2012 or early first quarter 2013.
As part of the Mainline hearing, TransCanada filed an updated throughput forecast for 2013 through 2020. Based on natural gas prices being lower by an average of $1.40 per gigajoule compared to the previous forecast, the Western Mainline Receipts are expected to be lower, on average, by approximately 1 billion cubic feet per day over the forecasted period.
Marcellus Facilities Expansion
In May 2012, TransCanada received NEB approval with respect to an application that was re-filed in November 2011 to construct new pipeline infrastructure to provide Southern Ontario with additional natural gas supply from the Marcellus shale basin. As a result of a number of compliance requirements associated with the approval, the current November 1, 2012 in-service date may be delayed.
Mainline New Capacity Open Season
In response to requests for capacity to bring additional Marcellus shale gas volumes into Canada, TransCanada held a new capacity open season for firm transportation service on the integrated Canadian Mainline from Niagara and Chippawa as well as from other receipt points to all delivery points, including points east of Parkway. The open season that closed in May 2012 received strong interest from shippers. TransCanada is currently in the process of executing Precedent Agreements (PAs) with the interested parties and anticipates those being completed this summer. The executed PAs will ultimately define the level of new long-term (10-year) firm transportation contracts including the specific receipt and delivery points, which in turn will determine if any additional facilities, such as between Parkway and Maple, will be required.
Alberta System
Expansion Projects
During the first half of 2012, TransCanada placed in service 10 separate pipeline projects for the Alberta System with a total cost of approximately $600 million. This included the construction of the Horn River project that expanded the Alberta System into the Horn River shale play and was placed in service in May 2012 at a cost of approximately $250 million.
The NEB has approved additional Alberta System expansions of approximately $630 million, including the Leismer-Kettle River Crossover project, a 30 inch, 77 km pipeline which was approved in June 2012. This project has an estimated construction cost of $162 million and is intended to provide increased capacity to meet demand in Northeast Alberta. A further approximately $340 million of projects are still awaiting NEB approval, including the Komie North project which would extend the Alberta System further into the Horn River area.
ATCO Pipelines Commercial Integration
Commercial integration of the Alberta System and ATCO Pipelines (ATCO) commenced in October 2011. TransCanada continues to work with ATCO to gather information for the final stage of the integration which is to swap assets of equal value and will require approval by both the Alberta Utilities Commission and the NEB.
NGL Extraction Convention
The Alberta System has applied for and obtained approval from the NEB to suspend the NGL Extraction Convention (NEXT) model Application. This application resulted from low natural gas prices and the potential implications of implementing NEXT on lean gas production, as well as some newly identified opportunities to increase the quantity of NGL available for extraction. Possible changes to the NEXT model will be discussed with the industry and, as part of the suspension approval, an update to the NEB is required by mid-October 2012.
Coastal GasLink Project
TransCanada has been selected by Shell Canada Limited (Shell) and its partners to design, build, own and operate the proposed Coastal GasLink project, an estimated $4 billion pipeline that will transport natural gas from the Montney gas-producing region near Dawson Creek, British Columbia (B.C.) to the recently announced LNG Canada liquefied natural gas export facility near Kitimat, B.C. The LNG Canada project is a joint venture led by Shell, with partners Korea Gas Corporation, Mitsubishi Corporation and PetroChina Company Limited. The approximately 700 km pipeline is expected to have an initial capacity of more than 1.7 billion cubic feet per day and be placed into service toward the end of the decade. A proposed contractual extension of the Alberta System using capacity on the Coastal GasLink pipeline, to a point near Vanderhoof, B.C., will allow TransCanada to offer gas transmission service to interconnecting natural gas pipelines serving the West Coast. TransCanada expects to elicit interest in and commitments for such service through an open season process in late 2012.
Alaska Pipeline Project
The Alaska North Slope producers (ExxonMobil, ConocoPhillips and BP), along with TransCanada through its participation in the Alaska Pipeline Project, have agreed on a work plan aimed at commercializing North Slope natural gas resources via an LNG option. In May 2012, TransCanada received approval from the State of Alaska to curtail its activities on the Alaska/Alberta route and focus on the LNG alternative. The approval allows TransCanada to defer its obligation to file for a Federal Energy Regulatory Commission (FERC) certificate for the Alberta route beyond the original fall 2012 deadline.
Mackenzie Gas Project
Project activities have been curtailed largely due to natural gas market conditions. TransCanada's future funding obligations for the Aboriginal Pipeline Group during such curtailment are expected to be nominal.
Oil Pipelines
Keystone Pipeline System
In May 2012, TransCanada filed revised fixed tolls for the Cushing Extension section of the Keystone Pipeline System with both the NEB and the FERC. The revised tolls, which reflect the final project costs of the Keystone Pipeline System, became effective July 1, 2012.
Gulf Coast Project
The Company announced in February 2012 that what had previously been the Cushing to U.S. Gulf Coast portion of the Keystone XL Project has its own independent value to the marketplace and will be constructed as the stand-alone Gulf Coast Project, which is not part of the Presidential Permit process. The 36-inch pipeline, which will extend from Cushing, Oklahoma to the U.S. Gulf Coast, is expected to have an initial capacity of up to 700,000 barrels per day (bbl/d) with an ultimate capacity of 830,000 bbl/d. TransCanada expects to start construction this summer and place the Gulf Coast Project in service in mid to late 2013. As of June 30, 2012, US$0.9 billion has been invested in the project. Included in the US$2.3 billion cost is US$300 million for the 76 km (47-mile) Houston Lateral pipeline that will transport crude oil to Houston refineries.
Keystone XL Pipeline
In May 2012, TransCanada filed for a Presidential Permit application (cross border permit) to the U.S. Department of State (DOS) for the Keystone XL Pipeline from the U.S./Canada border in Montana to Steele City, Nebraska. TransCanada will supplement that application with an alternative route in Nebraska as soon as that route is selected.
The Company continues to work collaboratively with the Nebraska Department of Environmental Quality (NDEQ) to finalize an alternative route for the Keystone XL Pipeline that avoids the Nebraska Sandhills and has submitted its plans for alternative routing corridors and a preferred corridor to the NDEQ. The NDEQ has conducted public open houses on the proposed routes and the state of Nebraska has indicated it expects to complete its review in the coming months.
The over three year environmental review for the Keystone XL Project completed last summer was one of the most comprehensive processes for a cross border pipeline. Based on that work, TransCanada expects its cross border permit should be processed expeditiously and a decision made once a new route in Nebraska is determined. The DOS has indicated it expects to make a decision on the project by first quarter 2013.
The approximate cost of the 36-inch line is US$5.3 billion and, subject to regulatory approvals, TransCanada expects the Keystone XL Pipeline to be in service in late 2014 or early 2015. As of June 30, 2012, US$1.5 billion has been invested in the project.
Keystone Hardisty Terminal
In May 2012, TransCanada announced that it had secured binding long-term commitments exceeding 500,000 bbl/d for the Keystone Hardisty Terminal. As a result of strong commercial support for the project, the Company will expand the proposed two million barrel project to a 2.6 million barrel terminal located at Hardisty, Alberta. The Keystone Hardisty Terminal Project will provide new crude oil batch accumulation tankage and pipeline infrastructure for Western Canadian producers and access to the Keystone Pipeline System. Subject to regulatory approvals, the Keystone Hardisty Terminal is expected to be operational in late 2014 and cost approximately $275 million.
Energy
Bruce Power
In March 2012, Bruce Power received authorization from the Canadian Nuclear Safety Commission (CNSC) to restart Unit 2. In May 2012, an incident occurred within the Unit 2 electrical generator on the non-nuclear side of the plant that delayed the synchronization of Unit 2 to the Ontario electrical grid. As a result, Bruce Power has submitted a force majeure claim to the OPA and, if accepted, the price received for power generated from the operating units of Bruce A would not be impacted. Work is currently underway to repair the Unit 2 electrical generator and Bruce Power expects commercial operations for Unit 2 to commence in fourth quarter 2012.
Bruce Power has received approval from the CNSC to remove the reactor shutdown guarantees and is proceeding with restarting the Unit 1 reactor. Synchronization of Unit 1 to the Ontario electrical grid is expected to occur during third quarter 2012.
TransCanada's share of the total net capital cost of the refurbishment project is expected to be approximately $2.4 billion.
In June 2012, Bruce Power returned Unit 3 to service after completing the West Shift Plus outage at a cost of approximately $300 million which commenced in November 2011. This investment is a key part of Bruce Power's strategy to maximize the lives of its reactors and is now expected to allow Unit 3 to produce low-cost electricity until at least 2021.
Sundance A
In December 2010, Sundance Units 1 and 2 were withdrawn from service and were subject to a force majeure claim by TransAlta Corporation (TransAlta) in January 2011. In February 2011, TransAlta notified TransCanada that it had determined it was uneconomic to repair Units 1 and 2 and that the Sundance A PPA should therefore be terminated.
TransCanada disputed both the force majeure and economic destruction claims under the binding dispute resolution process provided in the PPA. The binding arbitration proceedings concluded during the second quarter and a decision was received on July 20, 2012. The arbitration panel determined that the PPA should not be terminated and ordered TransAlta to rebuild Units 1 and 2. The panel also limited TransAlta's force majeure claim from November 20, 2011 until such time that the units can reasonably be returned to service. According to the terms of the arbitration decision, TransAlta has an obligation under the PPA to exercise all reasonable efforts to mitigate or limit the effects of the force majeure. TransAlta announced that it expects the units to be returned to service in the fall of 2013.
The impact of this decision has been reflected in the results for the period ended June 30, 2012. TransCanada had accrued $188 million of EBITDA from the commencement of the outages in December 2010 to the end of March 2012 as it considered the outages to be an interruption of supply. As a result of the decision, the Company expects to realize approximately $138 million of this amount. The difference of $50 million has been recorded as a charge to second quarter 2012 earnings. The net book value of the Sundance A PPA recorded in Intangibles and Other Assets remains fully recoverable under the terms of the PPA.
Ravenswood
Spot market capacity prices in the New York Zone J market have been higher on average for the first half of 2012 compared to the same period in 2011 due to the combination of higher demand curve rates which were reset in late third quarter 2011 and rule changes implemented by the New York Independent System Operator (NYISO) which affected the way certain capacity is measured in the market. In addition, capacity prices have been positively impacted by a series of generator retirements which has reduced the amount of capacity in the market.
In 2011, TransCanada and other parties jointly filed two formal complaints with the FERC regarding application of pricing rules by the NYISO. The FERC has addressed the first of two complaints filed and has indicated it will take steps to increase transparency and accountability with regard to future Mitigation Exemption Test decisions. The second and potentially more significant complaint is still pending.
Becancour
In June 2012, Hydro-Quebec notified TransCanada it would exercise its option to extend the agreement to suspend all electricity generation from the Becancour power plant throughout 2013. Under the terms of the suspension agreement, 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 capacity payments under the agreement similar to those that would have been received under the normal course of operation while energy production and payments are suspended.
Canadian Solar
In late 2011, TransCanada agreed to purchase nine Ontario solar projects from Canadian Solar Solutions Inc., with a combined capacity of 86 megawatts, for approximately $470 million. Under the terms of the agreement, each of the nine solar projects will be developed and constructed by Canadian Solar Solutions Inc. using photovoltaic panels. TransCanada will purchase each project once construction and acceptance testing have been completed and operations have begun under 20-year PPAs with the OPA under the Feed-In Tariff program in Ontario. Construction on the first two solar projects has commenced and both projects are expected to be placed in service in late 2012. TransCanada anticipates the remaining projects will be placed in service in 2013 or early 2014, subject to regulatory approvals.
Share Information
At July 24, 2012, TransCanada had 704 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 five million were exercisable as at July 24, 2012.
Selected Quarterly Consolidated Financial Data(1)
(unaudited)
(millions of
dollars, except 2012 2011 2010
per share ------------- ---------------------------- -------------
amounts) Second First Fourth Third Second First Fourth Third
============================================================================
Revenues 1,806 1,911 1,967 1,987 1,797 1,868 1,675 1,776
Net income
attributable to
controlling
interests 286 366 390 399 367 425 277 393
Share Statistics
Net Income per
common share
Basic $0.39 $0.50 $0.53 $0.55 $0.50 $0.59 $0.38 $0.55
Diluted $0.39 $0.50 $0.53 $0.55 $0.50 $0.59 $0.37 $0.55
Dividend declared
per common share $0.44 $0.44 $0.42 $0.42 $0.42 $0.42 $0.40 $0.40
===========================================================
(1) The selected quarterly consolidated financial data has been prepared in
accordance with U.S. 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 Pipeline System, earnings are primarily generated by contractual arrangements for committed capacity that are not dependent on actual throughput. 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, hydrology, capacity prices, planned and unplanned plant outages, acquisitions and divestitures, certain fair value adjustments and developments outside of the normal course of operations.
Significant developments that affected the last eight quarters' EBIT and Net Income are as follows:
-- Second Quarter 2012, EBIT included a $50 million pre-tax ($37 million
after tax) charge from the Sundance A PPA arbitration decision and net
realized losses of $14 million pre-tax ($13 million after tax) from
certain risk management activities.
-- First Quarter 2012, EBIT included net realized losses of $22 million
pre-tax ($11 million after tax) from certain risk management activities.
-- Fourth Quarter 2011, EBIT excluded net unrealized gains of $11 million
pre-tax ($9 million after tax) resulting from certain risk management
activities.
-- Third Quarter 2011, Energy's EBIT included the positive impact of higher
prices for Western Power. EBIT included net unrealized losses of $43
million pre-tax ($30 million after tax) resulting from certain risk
management activities.
-- Second Quarter 2011, Natural Gas Pipelines' EBIT included incremental
earnings from Guadalajara, which was placed in service in June 2011.
Energy's EBIT included incremental earnings from Coolidge, which was
placed in service in May 2011. EBIT included net unrealized losses of $3
million pre-tax ($2 million after tax) resulting from 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 the Keystone Pipeline System in February 2011.
EBIT included net unrealized losses of $19 million pre-tax ($12 million
after tax) resulting from 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 Aboriginal Pipeline Group for the
Mackenzie Gas Project. 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 $46 million pre-tax ($29 million after tax)
resulting from 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 loss of $1 million pre-tax ($1 million after tax)
resulting from certain risk management activities.
Condensed Consolidated Statement of Income
(unaudited) Three months ended Six months ended
(millions of Canadian dollars except June 30 June 30
per share amounts) 2012 2011 2012 2011
============================================================================
Revenues
Natural Gas Pipelines 1,034 1,009 2,119 2,071
Oil Pipelines 251 211 510 346
Energy 521 577 1,088 1,248
----------------------------------------
1,806 1,797 3,717 3,665
Income from Equity Investments 65 80 125 201
Operating and Other Expenses
Plant operating costs and other 727 647 1,434 1,256
Commodity purchases resold 167 157 346 395
Depreciation and amortization 346 330 690 650
----------------------------------------
1,240 1,134 2,470 2,301
----------------------------------------
Financial Charges/(Income)
Interest expense 239 235 481 446
Interest income and other (5) (25) (36) (55)
----------------------------------------
234 210 445 391
----------------------------------------
Income before Income Taxes 397 533 927 1,174
----------------------------------------
Income Taxes Expense
Current 39 42 95 148
Deferred 46 96 119 170
----------------------------------------
85 138 214 318
----------------------------------------
Net Income 312 395 713 856
Net Income Attributable to Non-
Controlling Interests 26 28 61 64
----------------------------------------
Net Income Attributable to
Controlling Interests 286 367 652 792
Preferred Share Dividends 14 14 28 28
----------------------------------------
Net Income Attributable to Common
Shares 272 353 624 764
========================================
Net Income per Common Share
Basic and Diluted $0.39 $0.50 $0.89 $1.09
========================================
Dividends Declared per Common Share $0.44 $0.42 $0.88 $0.84
========================================
Weighted Average Number of Common
Shares (millions)
Basic 704 702 704 700
Diluted 705 703 705 701
========================================
See accompanying notes to the condensed consolidated financial statements.
Condensed Consolidated Statement of Comprehensive Income
Three months ended Six months ended
(unaudited) June 30 June 30
(millions of Canadian dollars) 2012 2011 2012 2011
============================================================================
Net Income 312 395 713 856
-------------------------------------
Other Comprehensive Income/(Loss), Net
of Income Taxes
Change in foreign currency translation
gains and losses on investments in
foreign operations(1) 114 (38) 7 (154)
Change in fair value of derivative
instruments to hedge the net
investments in foreign operations(2) (61) 23 (23) 72
Change in fair value of derivative
instruments designated as cash flow
hedges(3) 28 (42) (17) (95)
Reclassification to Net Income of
losses on derivative instruments
designated as cash flow hedges(4) 27 22 72 70
Reclassification to Net Income of
actuarial losses and prior service
costs on pension and other post-
retirement benefit plans(5) 4 3 14 5
Other Comprehensive (Loss)/Income of
Equity Investments(6) (3) (2) 2 -
-------------------------------------
Other Comprehensive Income/(Loss) 109 (34) 55 (102)
-------------------------------------
Comprehensive Income 421 361 768 754
Comprehensive Income Attributable to
Non-Controlling Interests 46 25 64 46
-------------------------------------
Comprehensive Income Attributable to
Controlling Interests 375 336 704 708
Preferred Share Dividends 14 14 28 28
-------------------------------------
Comprehensive Income Attributable to
Common Shares 361 322 676 680
=====================================
(1) Net of income tax recovery of $30 million and $8 million for the three
and six months ended June 30, 2012, respectively (2011 - expense of $11
million and $40 million, respectively).
(2) Net of income tax recovery of $19 million and $8 million for the three
and six months ended June 30, 2012, respectively (2011 - expense of $8
million and $27 million, respectively).
(3) Net of income tax expense of $15 million and recovery of $19 million for
the three and six months ended June 30, 2012, respectively (2011 -
recovery of $21 million and $40 million, respectively).
(4) Net of income tax expense of $20 million and $41 million for the three
and six months ended June 30, 2012, respectively (2011 - expense of $12
million and $37 million, respectively).
(5) Net of income tax expense of $1 million and recovery of $3 million for
the three and six months ended June 30, 2012, respectively (2011 -
expense of $1 million and $2 million, respectively).
(6) Primarily related to reclassification to Net Income of actuarial losses
on pension and other post-retirement benefit plans, gains and losses on
derivative instruments designated as cash flow hedges, offset by change
in gains and losses on derivative instruments designated as cash flow
hedges, net of income tax expense of nil and $1 million for the three
and six months ended June 30, 2012, respectively (2011 - nil and expense
of $1 million, respectively).
See accompanying notes to the condensed consolidated financial statements.
Condensed Consolidated Statement of Cash Flows
Three months ended Six months ended
(unaudited) June 30 June 30
(millions of Canadian dollars) 2012 2011 2012 2011
============================================================================
Cash Generated from Operations
Net income 312 395 713 856
Depreciation and amortization 346 330 690 650
Deferred income taxes 46 96 119 170
Income from equity investments (65) (80) (125) (201)
Distributions received from equity
investments 74 91 157 185
Employee future benefits expense in
excess of/ (less than) funding 5 1 12 (2)
Other 11 14 34 33
Decrease/(increase) in operating
working capital 14 46 (155) 65
-------------------------------------
Net cash provided by operations 743 893 1,445 1,756
-------------------------------------
Investing Activities
Capital expenditures (397) (487) (861) (1,088)
Equity investments (197) (121) (413) (238)
Deferred amounts and other 79 (1) 42 35
-------------------------------------
Net cash used in investing activities (515) (609) (1,232) (1,291)
-------------------------------------
Financing Activities
Dividends on common and preferred
shares (324) (198) (634) (398)
Distributions paid to non-controlling
interests (35) (27) (68) (54)
Notes payable issued/(repaid), net 635 (545) 589 (411)
Long-term debt issued, net of issue
costs 1 519 493 519
Reduction of long-term debt (222) (419) (770) (740)
Common shares issued 4 4 18 25
Partnership units of subsidiary issued,
net of costs - 321 - 321
-------------------------------------
Net cash provided by/(used in)
financing activities 59 (345) (372) (738)
-------------------------------------
Effect of Foreign Exchange Rate Changes
on Cash and Cash Equivalents 7 (3) (5) (15)
-------------------------------------
Increase/(Decrease) in Cash and Cash
Equivalents 294 (64) (164) (288)
-------------------------------------
Cash and Cash Equivalents
Beginning of period 196 436 654 660
-------------------------------------
Cash and Cash Equivalents
End of period 490 372 490 372
=====================================
See accompanying notes to the condensed consolidated financial statements.
Condensed Consolidated Balance Sheet
(unaudited) June 30 December 31
(millions of Canadian dollars) 2012 2011
============================================================================
ASSETS
Current Assets
Cash and cash equivalents 490 654
Accounts receivable 1,000 1,094
Inventories 235 248
Other 1,068 1,114
----------------------
2,793 3,110
Plant, Property and Equipment, net of accumulated
depreciation of $16,030 and $15,406, respectively 32,585 32,467
Equity Investments 5,463 5,077
Goodwill 3,542 3,534
Regulatory Assets 1,652 1,684
Intangibles and Other Assets 1,496 1,466
----------------------
47,531 47,338
======================
LIABILITIES
Current Liabilities
Notes payable 2,449 1,863
Accounts payable 1,995 2,359
Accrued interest 363 365
Current portion of long-term debt 589 935
----------------------
5,396 5,522
Regulatory Liabilities 298 297
Deferred Amounts 893 929
Deferred Income Tax Liabilities 3,768 3,591
Long-Term Debt 17,828 17,724
Junior Subordinated Notes 1,018 1,016
----------------------
29,201 29,079
EQUITY
Common shares, no par value 12,030 12,011
Issued and outstanding:
June 30, 2012 - 704 million shares
December 31, 2011 - 704 million shares
Preferred shares 1,224 1,224
Additional paid-in capital 380 380
Retained earnings 4,632 4,628
Accumulated other comprehensive loss (1,397) (1,449)
----------------------
Controlling Interests 16,869 16,794
Non-controlling interests 1,461 1,465
----------------------
Equity 18,330 18,259
----------------------
47,531 47,338
======================
Contingencies and Guarantees (Note 8)
Subsequent Event (Note 9)
See accompanying notes to the condensed consolidated financial statements.
Condensed Consolidated Statement of Accumulated Other Comprehensive
(Loss)/Income
Pension and
Other Post-
Currency Cash Flow retirement
(unaudited) Translation Hedges Plan
(millions of Canadian dollars) Adjustments and Other Adjustments Total
============================================================================
Balance at December 31, 2011 (643) (281) (525) (1,449)
Change in foreign currency
translation gains and losses
on investments in foreign
operations(1) 4 - - 4
Change in fair value of
derivative instruments to
hedge net investments in
foreign operations(2) (23) - - (23)
Change in fair value of
derivative instruments
designated as cash flow
hedges(3) - (17) - (17)
Reclassification to Net Income
of losses on derivative
instruments designated as
cash flow hedges pertaining
to prior periods(4)(5) - 72 - 72
Reclassification of actuarial
losses and prior service
costs on pension and other
post-retirement benefit
plans(6) - - 14 14
Other Comprehensive
(Loss)/Income of Equity
Investments (7) - (6) 8 2
----------------------------------------------
Balance at June 30, 2012 (662) (232) (503) (1,397)
==============================================
Pension and
Other Post-
Currency Cash Flow retirement
(unaudited) Translation Hedges Plan
(millions of Canadian dollars) Adjustments and Other Adjustments Total
============================================================================
Balance at December 31, 2010 (683) (194) (366) (1,243)
Change in foreign currency
translation gains and losses
on investments in foreign
operations(1) (128) - - (128)
Change in fair value of
derivative instruments to
hedge net investments in
foreign operations(2) 72 - - 72
Change in fair value of
derivative instruments
designated as cash flow
hedges(3) - (98) - (98)
Reclassification to Net Income
of losses on derivative
instruments designated as
cash flow hedges(4)(5) - 65 - 65
Reclassification of actuarial
losses and prior service
costs on pension and other
post-retirement benefit
plans(6) - - 5 5
Other Comprehensive
(Loss)/Income of Equity
Investments (7) - (5) 5 -
----------------------------------------------
Balance at June 30, 2011 (739) (232) (356) (1,327)
==============================================
(1) Net of income tax recovery of $8 million and non-controlling interest
gains of $3 million for the six months ended June 30, 2012 (2011 -
expense of $40 million; loss of $26 million).
(2) Net of income tax recovery of $8 million for the six months ended June
30, 2012 (2011 - expense of $27 million).
(3) Net of income tax recovery of $19 million and non-controlling interest
losses of nil for the six months ended June 30, 2012 (2011 - recovery of
$40 million; gain of $3 million).
(4) Net of income tax expense of $41 million and non-controlling interest
losses of nil for the six months ended June 30, 2012 (2011 - expense
of $37 million; gain of $5 million).
(5) Losses related to cash flow hedges reported in AOCI and expected to be
reclassified to Net Income in the next 12 months are estimated to be
$166 million ($105 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.
(6) Net of income tax recovery of $3 million for the six months ended June
30, 2012 (2011 - expense of $2 million).
(7) Primarily related to reclassification to Net Income of actuarial losses
on pension and other post-retirement benefit plans, reclassification to
Net Income of gains and losses on derivative instruments designated as
cash flow hedges, partially offset by changes in gains and losses on
derivative instruments designated as cash flow hedges, net of income
tax expense of $1 million for the six months ended June 30, 2012
(2011 - expense of $1 million).
See accompanying notes to the condensed consolidated financial statements.
Condensed Consolidated Statement of Equity
Six months ended
(unaudited) June 30
(millions of Canadian dollars) 2012 2011
============================================================================
Common Shares
Balance at beginning of period 12,011 11,745
Shares issued under dividend reinvestment plan - 202
Shares issued on exercise of stock options 19 26
------------------
Balance at end of period 12,030 11,973
------------------
Preferred Shares
------------------
Balance at beginning and end of period 1,224 1,224
------------------
Additional Paid-In Capital
Balance at beginning of period 380 349
Issuance of stock options, net of exercises - 1
Dilution gain from TC PipeLines, LP units issued - 30
------------------
Balance at end of period 380 380
------------------
Retained Earnings
Balance at beginning of period 4,628 4,273
Net income attributable to controlling interests 652 792
Common share dividends (620) (589)
Preferred share dividends (28) (28)
------------------
Balance at end of period 4,632 4,448
------------------
Accumulated Other Comprehensive Loss
Balance at beginning of period (1,449) (1,243)
Other comprehensive income/(loss) 52 (84)
------------------
Balance at end of period (1,397) (1,327)
------------------
------------------
Equity Attributable to Controlling Interests 16,869 16,698
------------------
Equity Attributable to Non-Controlling Interests
Balance at beginning of period 1,465 1,157
Net income attributable to non-controlling interest 61 64
Other comprehensive income/(loss) attributable to non-
controlling interest 3 (18)
Sale of TC PipeLines, LP units
Proceeds, net of issue costs - 321
Decrease in TCPL's ownership - (50)
Distributions to non-controlling interests (68) (54)
Other - (4)
------------------
Balance at end of period 1,461 1,416
------------------
Total Equity 18,330 18,114
==================
See accompanying notes to the condensed consolidated financial statements.
Notes to Condensed Consolidated Financial Statements
(Unaudited)
1. Basis of Presentation
These condensed consolidated financial statements of TransCanada Corporation (TransCanada or the Company) have been prepared by management in accordance with United States generally accepted accounting principles (U.S. GAAP). Comparative figures, which were previously presented in accordance with Canadian generally accepted accounting principles as defined in Part V of the Canadian Institute of Chartered Accountants Handbook (CGAAP), have been adjusted as necessary to be compliant with the Company's policies under U.S. GAAP. The amounts adjusted for U.S. GAAP presented in these condensed consolidated financial statements for the three and six months ended June 30, 2011 are the same as those that have been previously reported in the Company's June 30, 2011 Reconciliation to U.S. GAAP. The amounts adjusted at December 31, 2011 are the same as those reported in Note 25 of TransCanada's 2011 audited Consolidated Financial Statements included in TransCanada's 2011 Annual Report. The accounting policies applied are consistent with those outlined in TransCanada's 2011 Annual Report, except as described in Note 2, which outlines the Company's significant accounting policies that have changed upon adoption of U.S. GAAP. Capitalized and abbreviated terms that are used but not otherwise defined herein are identified in the Glossary of Terms contained in TransCanada's 2011 Annual Report.
These condensed consolidated financial statements reflect adjustments, all of which are normal recurring adjustments that are, in the opinion of management, necessary to reflect the financial position and results of operations for the respective periods. These condensed consolidated financial statements do not include all disclosures required in the annual financial statements and should be read in conjunction with the 2011 audited Consolidated Financial Statements included in TransCanada's 2011 Annual Report.
Earnings for interim periods may not be indicative of results for the fiscal year in the Company's Natural Gas Pipeline segment due to seasonal fluctuations in short-term throughput volumes on U.S. pipelines. Earnings for interim periods may also not be indicative of results for the fiscal year in the Company's Energy segment due to the impact of seasonal weather conditions on customer demand and market pricing in certain of the Company's investments in electrical power generation plants and non-regulated gas storage facilities.
Use of Estimates and Judgements
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 condensed 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 to Significant Accounting Policies Upon Adoption of U.S. GAAP
Principles of Consolidation
The condensed consolidated financial statements include the accounts of TransCanada and its subsidiaries. The Company consolidates its interests in entities over which it is able to exercise control. To the extent there are interests owned by other parties, these interests are included in Non-Controlling Interests. TransCanada uses the equity method of accounting for corporate joint ventures in which the Company is able to exercise joint control and for investments in which the Company is able to exercise significant influence. TransCanada records its proportionate share of undivided interests in certain assets.
Inventories
Inventories primarily consist of materials and supplies, including spare parts and fuel, and natural gas inventory in storage, and are recorded at the lower of weighted average cost or market.
Income Taxes
The Company uses the liability method of accounting for income taxes. This method requires the recognition of deferred income tax assets and liabilities for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred income tax assets and liabilities are measured using enacted tax rates at the balance sheet date that are anticipated to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. Changes to these balances are recognized in income in the period during which they occur except for changes in balances related to the Canadian Mainline, Alberta System and Foothills, which are deferred until they are refunded or recovered in tolls, as permitted by the NEB.
Canadian income taxes are not provided on the unremitted earnings of foreign investments that the Company does not intend to repatriate in the foreseeable future.
Employee Benefit and Other Plans
The Company sponsors defined benefit pension plans (DB Plans), defined contribution plans (DC Plans), a Savings Plan and other post-retirement benefit plans. Contributions made by the Company to the DC Plans and Savings Plan are expensed in the period in which contributions are made. The cost of the DB Plans and other post-retirement benefits received by employees is actuarially determined using the projected benefit method pro-rated based on service and management's best estimate of expected plan investment performance, salary escalation, retirement age of employees and expected health care costs.
The DB Plans' assets are measured at fair value. The expected return on the DB Plans' assets is determined using market-related values based on a five-year moving average value for all of the DB Plans' assets. Past service costs are amortized over the expected average remaining service life of the employees. Adjustments arising from plan amendments are amortized on a straight-line basis over the average remaining service period of employees active at the date of amendment. The Company recognizes the overfunded or underfunded status of its DB Plans as an asset or liability on its Balance Sheet and recognizes changes in that funded status through Other Comprehensive (Loss)/Income (OCI) in the year in which the change occurs. The excess of net actuarial gains or losses over 10 per cent of the greater of the benefit obligation and the market-related value of the DB Plans' assets, if any, is amortized out of Accumulated Other Comprehensive (Loss)/Income (AOCI) over the average remaining service period of the active employees. For certain regulated operations, post-retirement benefit amounts are recoverable through tolls as benefits are funded. The Company records any unrecognized gains and losses or changes in actuarial assumptions related to these post-retirement benefit plans as either regulatory assets or liabilities. The regulatory assets or liabilities are amortized on a straight-line basis over the average remaining service life of active employees. When the restructuring of a benefit plan gives rise to both a curtailment and a settlement, the curtailment is accounted for prior to the settlement.
The Company has medium-term incentive plans, under which payments are made to eligible employees. The expense related to these incentive plans is accounted for on an accrual basis. Under these plans, benefits vest when certain conditions are met, including the employees' continued employment during a specified period and achievement of specified corporate performance targets.
Long-Term Debt Transaction Costs
The Company records long-term debt transaction costs as deferred assets and amortizes these costs using the effective interest method for all costs except those related to the Canadian natural gas regulated pipelines, which continue to be amortized on a straight-line basis in accordance with the provisions of tolling mechanisms.
Guarantees
Upon issuance, the Company records the fair value of certain guarantees. The fair value of these guarantees is estimated by discounting the cash flows that would be incurred by the Company if letters of credit were used in place of the guarantees. Guarantees are recorded as an increase to Equity Investments, Plant, Property and Equipment, or a charge to Net Income, and a corresponding liability is recorded in Deferred Amounts.
Changes in Accounting Policies for 2012
Fair Value Measurement
Effective January 1, 2012, the Company adopted the Accounting Standards Update (ASU) on fair value measurements as issued by the Financial Accounting Standards Board (FASB). Adoption of the ASU has resulted in an increase in the qualitative and quantitative disclosures regarding Level III measurements.
Intangibles - Goodwill and Other
Effective January 1, 2012, the Company adopted the ASU on testing goodwill for impairment as issued by the FASB. Adoption of the ASU has resulted in a change in the accounting policy related to testing goodwill for impairment, as the Company is now permitted under U.S. GAAP to first assess qualitative factors affecting the fair value of a reporting unit in comparison to the carrying amount as a basis for determining whether it is required to proceed to the two-step quantitative impairment test.
Future Accounting Changes
Balance Sheet Offsetting/Netting
In December 2011, the FASB issued amended guidance to enhance disclosures that will enable users of the financial statements to evaluate the effect, or potential effect, of netting arrangements on an entity's financial position. The amendments result in enhanced disclosures by requiring additional information regarding financial instruments and derivative instruments that are either offset in accordance with current U.S. GAAP or subject to an enforceable master netting arrangement. This guidance is effective for annual periods beginning on or after January 1, 2013. Adoption of these amendments is expected to result in an increase in disclosure regarding financial instruments which are subject to offsetting as described in this amendment.
3. Segmented Information
Three months
ended June 30
(unaudited)
(millions of Natural Gas Oil
Canadian Pipelines Pipelines Energy Corporate Total
dollars) 2012 2011 2012 2011 2012 2011 2012 2011 2012 2011
============================================================================
Revenues 1,034 1,009 251 211 521 577 - - 1,806 1,797
Income from
equity
investments 37 35 - - 28 45 - - 65 80
Plant
operating
costs and
other (405) (356) (75) (58) (232) (218) (15) (15) (727) (647)
Commodity
purchases
resold - - - - (167) (157) - - (167) (157)
Depreciation
and
amortization (234) (229) (36) (34) (72) (63) (4) (4) (346) (330)
-------------------------------------------------------------
432 459 140 119 78 184 (19) (19) 631 743
===============================================
Interest expense (239) (235)
Interest income and other 5 25
--------------
Income before Income Taxes 397 533
Income taxes expense (85) (138)
--------------
Net Income 312 395
Net Income Attributable to Non-Controlling Interests (26) (28)
--------------
Net Income Attributable to Controlling Interests 286 367
Preferred Share Dividends (14) (14)
--------------
Net Income Attributable to Common Shares 272 353
==============
Six months
ended June 30
(unaudited)
(millions of Natural Gas Oil
Canadian Pipelines Pipelines(1) Energy Corporate Total
dollars) 2012 2011 2012 2011 2012 2011 2012 2011 2012 2011
============================================================================
Revenues 2,119 2,071 510 346 1,088 1,248 - - 3,717 3,665
Income from
equity
investments 83 78 - - 42 123 - - 125 201
Plant
operating
costs and
other (811) (688) (161) (94) (418) (435) (44) (39)(1,434)(1,256)
Commodity
purchases
resold - - - - (346) (395) - - (346) (395)
Depreciation
and
amortization (466) (457) (72) (57) (145) (129) (7) (7) (690) (650)
-------------------------------------------------------------
925 1,004 277 195 221 412 (51) (46) 1,372 1,565
===============================================
Interest expense (481) (446)
Interest income and other 36 55
--------------
Income before Income Taxes 927 1,174
Income taxes expense (214) (318)
--------------
Net Income 713 856
Net Income Attributable to Non-Controlling Interests (61) (64)
--------------
Net Income Attributable to Controlling Interests 652 792
Preferred Share Dividends (28) (28)
--------------
Net Income Attributable to Common Shares 624 764
==============
(1) Commencing in February 2011, TransCanada began recording earnings related
to the Wood River/Patoka and Cushing Extension sections of Keystone.
Total Assets
(unaudited)
(millions of Canadian dollars) June 30, 2012 December 31, 2011
============================================================================
Natural Gas Pipelines 23,025 23,161
Oil Pipelines 9,691 9,440
Energy 13,600 13,269
Corporate 1,215 1,468
-----------------------------------
47,531 47,338
===================================
4. Income Taxes
At June 30, 2012, the total unrecognized tax benefit of uncertain tax positions was approximately $54 million (December 31, 2011 - $52 million). TransCanada recognizes interest and penalties related to income tax uncertainties in income tax expense. Included in net tax expense for the three and six months ended June 30, 2012 is nil and $1 million, respectively, of interest expense and nil for penalties (2011 - reversal of interest expense of $3 million and $2 million, respectively, and nil for penalties). At June 30, 2012, the Company had $8 million accrued for interest expense and nil accrued for penalties (December 31, 2011 - $7 million accrued for interest expense and nil accrued for penalties).
The effective tax rates for the six-month periods ended June 30, 2012 and 2011 were 23.1 per cent and 27.0 per cent, respectively. The lower effective tax rate in 2012 was a result of a reduction in the Canadian statutory tax rate, and changes in the proportion of income earned between Canadian and foreign jurisdictions.
TransCanada expects the enactment of certain Canadian Federal tax legislation in the next twelve months which is expected to result in a favourable income tax adjustment of approximately $25 million. Otherwise, subject to the results of audit examinations by taxation authorities and other legislative amendments, TransCanada does not anticipate further adjustments to the unrecognized tax benefits during the next twelve months that would have a material impact on its financial statements.
5. Long-Term Debt
In the three and six months ended June 30, 2012, the Company capitalized interest related to capital projects of $76 million and $150 million, respectively (2011 - $68 million and $165 million, respectively).
In January 2012, TransCanada PipeLine USA Ltd. repaid the remaining principal of US$500 million on its five-year term loan.
In March 2012, TransCanada PipeLines Limited (TCPL) issued US$500 million of 0.875 per cent senior notes due in 2015.
In May 2012, TCPL retired US$200 million of 8.625 per cent senior notes.
6. Employee Post-Retirement Benefits
The net benefit plan expense for the Company's defined benefit pension plans and other post-retirement benefit plans is as follows:
Three months ended June 30 Six months ended June 30
--------------------------- ---------------------------
Other Post- Other Post-
(unaudited) Pension retirement Pension retirement
(millions of Benefit Plans Benefit Plans Benefit Plans Benefit Plans
Canadian dollars) 2012 2011 2012 2011 2012 2011 2012 2011
============================================================================
Service cost 17 13 - 1 33 27 1 1
Interest cost 24 22 2 2 47 45 4 4
Expected return on
plan assets (29) (28) (1) (1) (57) (56) (1) (1)
Amortization of
actuarial loss 4 2 1 1 9 5 1 1
Amortization of past
service cost 1 1 - - 1 1 - -
Amortization of
regulatory asset 5 3 - - 10 7 - -
Amortization of
transitional
obligation related
to regulated
business - - 1 1 - - 1 1
--------------------------------------------------------
Net Benefit Cost
Recognized 22 13 3 4 43 29 6 6
========================================================
7. Financial Instruments and Risk Management
Counterparty Credit Risk
TransCanada's maximum counterparty credit exposure with respect to financial instruments at the balance sheet date, without taking into account security held, consisted of accounts receivable, the fair value of derivative assets and notes receivable. The carrying amounts and fair values of these financial assets, except amounts for derivative assets, are included in Accounts Receivable and Other in the Non-Derivative Financial Instruments Summary table below. Letters of credit and cash are the primary types of security provided to support these amounts. The majority of counterparty credit exposure is with counterparties who are investment grade. At June 30, 2012, there were no significant amounts past due or impaired.
At June 30, 2012, the Company had a credit risk concentration of $288 million due from a counterparty. This amount is expected to be fully collectible and is secured by a guarantee from the counterparty's parent company.
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, 2012, the Company had designated as a net investment hedge U.S. dollar-denominated debt with a carrying value of $10.4 billion (US$10.2 billion) and a fair value of $13.3 billion (US$13.1 billion). At June 30, 2012, $63 million (December 31, 2011 - $79 million) was included in Other Current Assets, $51 million (December 31, 2011 - $66 million) was included in Intangibles and Other Assets, $13 million (December 31, 2011 - $15 million) was included in Accounts Payable and $57 million (December 31, 2011 - $41 million) was included in Deferred Amounts for the fair value of forwards and swaps used to hedge the Company's net U.S. dollar investment in self-sustaining foreign operations.
Derivatives Hedging Net Investment in Self-Sustaining Foreign Operations
The fair values and notional principal amounts for the derivatives designated as a net investment hedge were as follows:
June 30, 2012 December 31, 2011
------------------------------------------------
Asset/(Liability) Notional or Notional or
(unaudited) (millions of Fair Principal Fair Principal
dollars) Value(1) Amount Value(1) Amount
============================================================================
U.S. dollar cross-currency
swaps
(maturing 2012 to 2019)(2) 44 US 4,050 93 US 3,850
U.S. dollar forward foreign
exchange contracts
(maturing 2012) - US 700 (4) US 725
------------------------------------------------
44 US 4,750 89 US 4,575
================================================
(1) Fair values equal carrying values.
(2) Consolidated Net Income in the three and six months ended June 30, 2012
included net realized gains of $7 million and $14 million, respectively
(2011 - gains of $7 million and $12 million, respectively) related to
the interest component of cross-currency swap settlements.
Non-Derivative Financial Instruments Summary
The carrying and fair values of non-derivative financial instruments were as follows:
June 30, 2012 December 31, 2011
----------------------------------------
(unaudited) Carrying Fair Carrying Fair
(millions of dollars) Amount(1) Value(2) Amount(1) Value(2)
============================================================================
Financial Assets
Cash and cash equivalents 490 490 654 654
Accounts receivable and other(3) 1,267 1,319 1,359 1,403
Available-for-sale assets(3) 35 35 23 23
----------------------------------------
1,792 1,844 2,036 2,080
========================================
Financial Liabilities(4)
Notes payable 2,449 2,449 1,863 1,863
Accounts payable and deferred
amounts(5) 1,044 1,044 1,329 1,329
Accrued interest 363 363 365 365
Long-term debt 18,417 23,862 18,659 23,757
Junior subordinated notes 1,018 1,049 1,016 1,027
----------------------------------------
23,291 28,767 23,232 28,341
========================================
(1) Recorded at amortized cost, except for US$350 million (December 31, 2011
- US$350 million) of Long-Term Debt that is recorded at fair value. This
debt which is recorded at fair value on a recurring basis is classified
in Level II of the fair value category using the income approach based
on interest rates from external data service providers.
(2) The fair value measurement of financial assets and liabilities recorded
at amortized cost for which the fair value is not equal to the carrying
value would be included in Level II of the fair value hierarchy using
the income approach based on interest rates from external data service
providers.
(3) At June 30, 2012, the Condensed Consolidated Balance Sheet included
financial assets of $1.0 billion (December 31, 2011 - $1.1 billion) in
Accounts Receivable, $40 million (December 31, 2011 - $41 million) in
Other Current Assets and $262 million (December 31, 2011 - $247 million)
in Intangibles and Other Assets.
(4) Consolidated Net Income in the three and six months ended June 30, 2012
included a gain of $3 million and a loss of $12 million, respectively
(2011 - losses of $2 million and $11 million, respectively) for fair
value adjustments related to interest rate swap agreements on US$350
million (2011 - US$350 million) of Long-Term Debt. There were no other
unrealized gains or losses from fair value adjustments to the
non-derivative financial instruments.
(5) At June 30, 2012, the Condensed Consolidated Balance Sheet included
financial liabilities of $919 million (December 31, 2011 - $1,192
million) in Accounts Payable and $125 million (December 31, 2011 -
$137 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, 2012
(unaudited)
(millions of Canadian
dollars unless otherwise Natural Foreign
indicated) Power Gas Exchange Interest
============================================================================
Derivative Financial
Instruments Held for
Trading(1)
Fair Values(2)
Assets $224 $150 $1 $18
Liabilities $(255) $(187) $(18) $(18)
Notional Values
Volumes(3)
Purchases 33,110 109 - -
Sales 33,374 85 - -
Canadian dollars - - - 620
U.S. dollars - - US 1,369 US 200
Cross-currency - - 47/US 37 -
Net unrealized
(losses)/gains in the
period(4)
Three months ended June
30, 2012 $(12) $4 $(14) -
Six months ended June 30,
2012 $(19) $(10) $(8) -
Net realized (losses)/gains
in the period(4)
Three months ended June
30, 2012 $(6) $(5) $6 -
Six months ended June 30,
2012 $9 $(15) $15 -
Maturity dates 2012-2016 2012-2016 2012-2013 2013-2016
Derivative Financial
Instruments in Hedging
Relationships(5)(6)
Fair Values(2)
Assets $38 - - $12
Liabilities $(242) $(15) $(36) -
Notional Values
Volumes(3)
Purchases 22,279 4 - -
Sales 9,310 - - -
U.S. dollars - - US 42 US 350
Cross-currency - - 136/US 100 -
Net realized (losses)/gains
in the period(4)
Three months ended June
30, 2012 $(26) $(8) - $2
Six months ended June 30,
2012 $(58) $(14) - $3
Maturity dates 2012-2018 2012-2013 2012-2014 2013-2015
================================================
(1) All derivative financial instruments held for trading 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 derivative financial
instruments held for trading used to purchase and sell power and natural
gas are included net 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 $12 million and a notional amount of US$350
million. Net realized gains on fair value hedges for the three and six
months ended June 30, 2012 were $2 million and $4 million, respectively,
and were included in Interest Expense. In the three and six months ended
June 30, 2012, 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, 2012, there were no gains or
losses included in Net Income for discontinued cash flow hedges where it
was probable that the anticipated transaction would not occur. No
amounts have been excluded from the assessment of hedge effectiveness.
2011
(unaudited)
(millions of Canadian
dollars unless otherwise Natural Foreign
indicated) Power Gas Exchange Interest
============================================================================
Derivative Financial
Instruments Held for
Trading(1)
Fair Values(2)(3)
Assets $185 $176 $3 $22
Liabilities $(192) $(212) $(14) $(22)
Notional Values(3)
Volumes(4)
Purchases 21,905 103 - -
Sales 21,334 82 - -
Canadian dollars - - - 684
U.S. dollars - - US 1,269 US 250
Cross-currency - - 47/US 37 -
Net unrealized
gains/(losses) in the
period(5)
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(5)
Three months ended June
30, 2011 $6 $(15) $12 -
Six months ended June 30,
2011 $5 $(41) $33 $1
Maturity dates 2012-2016 2012-2016 2012 2012-2016
Derivative Financial
Instruments in Hedging
Relationships(6)(7)
Fair Values(2)(3)
Assets $16 $3 - $13
Liabilities $(277) $(22) $(38) $(1)
Notional Values(3)
Volumes(4)
Purchases 17,188 8 - -
Sales 8,061 - - -
U.S. dollars - - US 73 US 600
Cross-currency - - 136/US 100 -
Net realized losses in the
period(5)
Three months ended June
30, 2011 $(13) $(5) - $(4)
Six months ended June 30,
2011 $(56) $(8) - $(9)
Maturity dates 2012-2017 2012-2013 2012-2014 2012-2015
================================================
(1) All derivative financial instruments held for trading 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) As at December 31, 2011.
(4) Volumes for power and natural gas derivatives are in GWh and Bcf,
respectively.
(5) Realized and unrealized gains and losses on derivative financial
instruments held for trading used to purchase and sell power and natural
gas are included net 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.
(6) 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 $13 million and a notional amount of US$350
million at December 31, 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.
(7) 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 where it
was probable that the anticipated transaction would not occur. 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) 2012 2011
============================================================================
Current
Other current assets 343 361
Accounts payable (510) (485)
Long term
Intangibles and other assets 214 202
Deferred amounts (331) (349)
==================================
Derivatives in Cash Flow Hedging Relationships
The components of OCI related to derivatives in cash flow hedging relationships are as follows:
Cash Flow Hedges
--------------------------------------------------------
Three months ended
June 30
(unaudited) Foreign
(millions of Power Natural Gas Exchange Interest
dollars, pre-tax) 2012 2011 2012 2011 2012 2011 2012 2011
============================================================================
Changes in fair
value of derivative
instruments
recognized in OCI
(effective portion) 44 (48) (4) (14) 4 (1) - (3)
Reclassification of
gains and (losses)
on derivative
instruments from
AOCI to Net Income
(effective portion) 28 (2) 15 24 - - 4 8
Gains on derivative
instruments
recognized in
earnings
(ineffective
portion) 7 1 1 1 - - - -
========================================================
Cash Flow Hedges
--------------------------------------------------------
Six months ended
June 30
(unaudited) Foreign
(millions of Power Natural Gas Exchange Interest
dollars, pre-tax) 2012 2011 2012 2011 2012 2011 2012 2011
============================================================================
Changes in fair
value of derivative
instruments
recognized in OCI
(effective portion) (22) (104) (14) (25) 1 (7) - (3)
Reclassification of
gains on derivative
instruments from
AOCI to Net Income
(effective portion) 75 32 28 52 - - 10 17
Gains and (losses)
on derivative
instruments
recognized in
earnings
(ineffective
portion) 1 - (1) (1) - - - -
========================================================
Derivative contracts entered into to manage market risk often contain financial assurance provisions that allow parties to the contracts to manage credit risk. These provisions may require collateral to be provided if a credit-risk-related contingent event occurs, such as a downgrade in the Company's credit rating to non-investment grade. Based on contracts in place and market prices at June 30, 2012, the aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a net liability position was $86 million (2011 - $96 million), for which the Company had provided collateral of $23 million (2011 - $5 million) in the normal course of business. If the credit-risk-related contingent features in these agreements were triggered on June 30, 2012, the Company would have been required to provide additional collateral of $63 million (2011 - $91 million) to its counterparties. Collateral may also need to be provided should the fair value of derivative instruments exceed pre-defined contractual exposure limit thresholds. The Company has sufficient liquidity in the form of cash and undrawn committed revolving bank lines to meet these contingent obligations should they arise.
Fair Value Hierarchy
The Company's assets and liabilities recorded at fair value have been classified into three categories based on the fair value hierarchy.
In Level I, the fair value of assets and liabilities is determined by reference to quoted prices in active markets for identical assets and liabilities that the Company has the ability to access at the measurement date.
In Level II, the fair value of interest rate and foreign exchange derivative assets and liabilities is determined using the income approach. The fair value of power and gas commodity assets and liabilities is determined using the market approach. Under both approaches, valuation is based on the extrapolation of inputs, other than quoted prices included within Level I, for which all significant inputs are observable directly or indirectly. Such inputs include published exchange rates, interest rates, interest rate swap curves, yield curves, and broker quotes from external data service providers. Transfers between Level I and Level II would occur when there is a change in market circumstances. There were no transfers between Level I and Level II in the six months ended June 30, 2012 and 2011.
In Level III, the fair value of assets and liabilities measured on a recurring basis is determined using a market approach based on inputs that are unobservable and significant to the overall fair value measurement. Assets and liabilities measured at fair value can fluctuate between Level II and Level III depending on the proportion of the value of the contract that extends beyond the time frame for which inputs are considered to be observable. As contracts near maturity and observable market data becomes available, they are transferred out of Level III and into Level II.
Long-dated commodity transactions in certain markets where liquidity is low are included in Level III of the fair value hierarchy, as the related commodity prices are not readily observable. Long-term electricity prices are estimated using a third-party modelling tool which takes into account physical operating characteristics of generation facilities in the markets in which the Company operates. Inputs into the model include market fundamentals such as fuel prices, power supply additions and retirements, power demand, seasonal hydro conditions and transmission constraints. Long-term North American natural gas prices are based on a view of future natural gas supply and demand, as well as exploration and development costs. Long-term prices are reviewed by management and the Board on a periodic basis. Significant decreases in fuel prices or demand for electricity or natural gas, or increases in the supply of electricity or natural gas would result in a lower fair value measurement of contracts included in Level III.
The fair value of the Company's assets and liabilities measured on a recurring basis, including both current and non-current portions, are categorized as follows:
Significant
Quoted Prices Other Significant
in Active Observable Unobservable
Markets Inputs Inputs
(Level I) (Level II) (Level III) Total
--------------------------------------------------------
(unaudited)(millions
of dollars, pre- Jun 30 Dec 31 Jun 30 Dec 31 Jun 30 Dec 31 Jun 30 Dec 31
tax) 2012 2011 2012 2011 2012 2011 2012 2011
============================================================================
Derivative Financial
Instrument Assets:
Interest rate
contracts - - 30 36 - - 30 36
Foreign exchange
contracts - - 114 141 - - 114 141
Power commodity
contracts - - 245 201 11 - 256 201
Gas commodity
contracts 114 124 32 55 - - 146 179
Derivative Financial
Instrument
Liabilities:
Interest rate
contracts - - (18) (23) - - (18) (23)
Foreign exchange
contracts - - (123) (102) - - (123) (102)
Power commodity
contracts - - (487) (454) (4) (15) (491) (469)
Gas commodity
contacts (176) (208) (22) (26) - - (198) (234)
Non-Derivative
Financial
Instruments:
Available-for-sale
assets 35 23 - - - - 35 23
--------------------------------------------------------
(27) (61) (229) (172) 7 (15) (249) (248)
========================================================
The following table presents the net change in the Level III fair value category:
Derivatives(1)(2)
--------------------------------------------
Three months ended Six months ended
(unaudited) June 30 June 30
(millions of dollars, pre-tax) 2012 2011 2012 2011
============================================================================
Balance at beginning of period (11) (13) (15) (8)
New contracts - - - 1
Settlements (1) - (1) -
Transfers out of Level III(3) 1 - 1 -
Total gains/(losses) included in
OCI 18 (17) 22 (23)
--------------------------------------------
Balance at end of period 7 (30) 7 (30)
============================================
(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, 2012, there were no
unrealized gains or losses included in Net Income attributable to
derivatives that were still held at the reporting date (2011 - nil).
(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 outstanding derivative financial instruments included in Level III as at June 30, 2012.
8. Contingencies and Guarantees
TransCanada and its subsidiaries are subject to various legal proceedings, arbitrations and actions arising in the normal course of business. While the final outcome of such legal proceedings and actions cannot be predicted with certainty, it is the opinion of management that the resolution of such proceedings and actions will not have a material impact on the Company's consolidated financial position or results of operations.
Amounts received under the Bruce B floor price mechanism within a calendar year are subject to repayment if the monthly average spot price exceeds the floor price. With respect to 2012, TransCanada currently expects spot prices to be less than the floor price for the year, therefore no amounts recorded in revenues in first six months of 2012 are expected to be repaid.
Guarantees
TransCanada and its joint venture partners on Bruce Power, Cameco Corporation and BPC Generation Infrastructure Trust (BPC), have severally guaranteed one-third of certain contingent financial obligations of Bruce B related to power sales agreements, a lease agreement and contractor services. The guarantees have terms ranging from 2018 to perpetuity. In addition, TransCanada and BPC have each severally guaranteed one-half of certain contingent financial obligations related to an agreement with the Ontario Power Authority to refurbish and restart Bruce A power generation units. The guarantees have terms ending in 2018 and 2019. TransCanada's share of the potential exposure under these Bruce A and Bruce B guarantees was estimated to be $804 million at June 30, 2012. The fair value of these Bruce Power guarantees at June 30, 2012 is estimated to be $36 million. The Company's exposure under certain of these guarantees is unlimited.
In addition to the guarantees for Bruce Power, the Company and its partners in certain other jointly owned entities have either (i) jointly and severally, (ii) jointly or (iii) severally guaranteed the financial performance of these entities related primarily to redelivery of natural gas, power purchase arrangement (PPA) payments and the payment of liabilities. TransCanada's share of the potential maximum exposure under these assurances was estimated at June 30, 2012 to range from $155 million to $426 million. The fair value of these guarantees at June 30, 2012 is estimated to be $69 million, which has been included in Deferred Amounts. For certain of these entities, any payments made by TransCanada under these guarantees in excess of its ownership interest are to be reimbursed by its partners.
9. Subsequent Event
On July 20, 2012, TransCanada received the binding arbitration decision regarding the Sundance A PPA force majeure and economic destruction claims. The arbitration panel determined that the PPA should not be terminated and ordered TransAlta Corporation (TransAlta) to return Units 1 and 2 to service. The panel also limited TransAlta's force majeure claim from November 20, 2011 until such time that the units can reasonably be returned to service.
The Company recorded revenues and costs under the PPA from the commencement of the outages in December 2010 to the end of March 2012. As of March 31, 2012, the Company had recorded $188 million of pre-tax earnings relating to the PPA. As a result of the arbitration decision, the Company expects to realize $138 million of this amount. Accordingly, the Company has recognized a pre-tax charge of $50 million to Plant Operating Costs and Other in second quarter 2012.
Contact Information:
Shawn Howard/Grady Semmens
403.920.7859 or 800.608.7859
TransCanada Investor & Analyst Enquiries:
David Moneta/Terry Hook/Lee Evans
403.920.7911 or 800.361.6522
www.transcanada.com