RNS Number:0977S
TransCanada Pipelines Ld
01 March 2007
PART 3
TRANSCANADA PIPELINES LIMITED 1
TABLE OF CONTENTS
CONSOLIDATED FINANCIAL REVIEW
Selected Three Year Consolidated Financial Data 3
Highlights 4
Segment Results-at-a-Glance 5
Results of Operations 6
SUBSEQUENT EVENTS 7
FORWARD-LOOKING INFORMATION 8
NON-GAAP MEASURES 8
TCPL OVERVIEW 8
TCPL'S STRATEGY
Pipelines 9
Energy 11
Operational Excellence 12
Competitive Strength and Enduring Value 13
OUTLOOK 14
PIPELINES
Highlights 18
Results-at-a-Glance 19
Financial Analysis 20
Opportunities and Developments 22
Business Risks 27
Other 29
Outlook 29
Natural Gas Throughput Volumes 31
ENERGY
Highlights 34
Results-at-a-Glance 35
Power Plants - Nominal Generating Capacity and Fuel Type 36
Financial Analysis 36
Opportunities and Developments 46
Business Risks 46
Outlook 47
CORPORATE
Results-at-a-Glance 48
DISCONTINUED OPERATIONS 49
LIQUIDITY AND CAPITAL RESOURCES
Summarized Cash Flow 49
Highlights 50
CONTRACTUAL OBLIGATIONS
Contractual Obligations 52
Principal Repayments 52
Interest Payments 53
Purchase Obligations 53
FINANCIAL AND OTHER INSTRUMENTS 55
RISKS AND RISK MANAGEMENT 60
CONTROLS AND PROCEDURES 62
SIGNIFICANT ACCOUNTING POLICIES AND CRITICAL ACCOUNTING ESTIMATES 62
ACCOUNTING CHANGES 64
SELECTED QUARTERLY CONSOLIDATED FINANCIAL DATA 65
FOURTH QUARTER 2006 HIGHLIGHTS 67
SHARE INFORMATION 68
OTHER INFORMATION 68
GLOSSARY OF TERMS 69
2 MANAGEMENT'S DISCUSSION AND ANALYSIS
The Management's Discussion and Analysis (MD&A) dated February 22, 2007 should
be read in conjunction with the audited Consolidated Financial Statements of
TransCanada PipeLines Limited (TCPL or the Company) and the notes thereto for
the year ended December 31, 2006. This MD&A covers TCPL's financial position and
operations as at and for the year ended December 31, 2006. TCPL's February 22,
2007 acquisition of American Natural Resources Company, and ANR Storage Company
(collectively ANR), additional interests in Great Lakes Gas Transmission
Partnership (Great Lakes) and related events, are summarized in the "Subsequent
Events" section of this MD&A. Amounts are stated in Canadian dollars unless
otherwise indicated. Abbreviations and acronyms used in this MD&A are identified
in the Glossary of Terms of the Company's 2006 Annual Report.
CONSOLIDATED FINANCIAL REVIEW
SELECTED THREE YEAR CONSOLIDATED FINANCIAL DATA(1)
(millions of dollars except per share amounts)
2006 2005 2004
Balance Sheet
Total assets 25,908 24,113 22,421
Total long-term liabilities 14,464 13,012 12,403
Income Statement
Revenues 7,520 6,124 5,497
Net income applicable to common shares
Continuing operations 1,049 1,208 978
Discontinued operations 28 - 52
Total net income 1,077 1,208 1,030
Per Common Share Data
Net income - Basic and Diluted
Continuing operations $2.17 $2.50 $2.03
Discontinued operations 0.06 - 0.11
$2.23 $2.50 $2.14
(1)
The selected three-year consolidated financial data is based on the
Company's financial statements which are prepared in accordance with
Canadian generally accepted accounting principles (GAAP). Certain
comparative figures have been reclassified to conform with the current
year's presentation.
MANAGEMENT'S DISCUSSION AND ANALYSIS 3
HIGHLIGHTS
Balance Sheet
*
In 2006, TCPL's shareholders' equity increased by $0.5 billion to $8
billion.
Net Income
*
In 2006, net income applicable to common shares was $1,077 million
compared to $1,208 million in 2005.
Net Earnings
*
In 2006, TCPL's net income applicable to common shares from continuing
operations (net earnings) was $1,049 million compared to $1,208 million
in 2005.
*
Excluding gains on sales of assets, TCPL's net earnings increased $185
million in 2006 to $1,036 million compared to $851 million in 2005.
Investing Activities
*
In 2006, TCPL invested approximately $2.0 billion in its Pipelines and
Energy businesses.
*
In February 2007, the Company closed the acquisition of ANR and an
additional 3.55 per cent interest in Great Lakes for approximately
US$3.4 billion, subject to certain post-closing adjustments, including
approximately US$488 million of assumed long-term debt.
*
In February 2007, TC PipeLines, LP (PipeLines LP) closed its acquisition
of a 46.45 per cent interest in Great Lakes for approximately US$962
million, subject to certain post-closing adjustments, including
approximately US$212 million of assumed long-term debt.
Financing Activities
*
In 2006, TCPL issued $2.1 billion of long-term debt.
*
In February 2007, TCPL issued $1.3 billion of common shares to
TransCanada Corporation (TransCanada) to partially finance the
acquisition of ANR.
*
In February 2007, TCPL entered into an agreement for a new US$1.0
billion credit facility. The Company utilized US$1.0 billion from this
facility and additional funds from an existing demand loan to partially
finance the ANR acquisition.
*
In February 2007, PipeLines LP increased the size of its syndicated
revolving credit and term loan agreement to US$950 million. Draws of
US$126 million under this agreement were used to partially finance
PipeLines LP's Great Lakes Acquisition.
*
In February 2007, PipeLines LP completed a private placement offering of
17,356,086 common units at a price of US$34.57 per unit. TCPL acquired
50 per cent of the units for US$300 million, and invested an additional
approximately US$12 million to maintain its general partner interest,
increasing its total ownership to 32.1 per cent. The total private
placement resulted in gross proceeds of approximately US$612 million
which were used to partially finance PipeLines LP's Great Lakes
Acquisition.
Dividends
*
In January 2007, the Board of Directors of TransCanada authorized the
issue of common shares from treasury at a two per cent discount under
TransCanada's Dividend Reinvestment and Share Purchase Plan (DRP),
beginning with the dividend payable April 30, 2007 to sharholders of
record at March 30, 2007. TCPL preferred shareholders may reinvest their
dividends to obtain additional TransCanada common shares.
4 MANAGEMENT'S DISCUSSION AND ANALYSIS
SEGMENT RESULTS-AT-A-GLANCE
Year ended December 31 (millions of dollars)
2006 2005 2004
Pipelines Net Earnings
Excluding gains 547 630 577
Gain on sale of Northern Border Partners, L.P. interest 13 - -
Gain on sale of PipeLines LP units - 49 -
Gain on sale of Millennium - - 7
560 679 584
Energy Net Earnings
Excluding gains 452 258 211
Gain on sale of Paiton Energy - 115 -
Gains related to Power LP - 193 187
452 566 398
Corporate 37 (37 ) (4 )
Net Income Applicable to Common Shares
Continuing Operations1 1,049 1,208 978
Discontinued Operations 28 - 52
1,077 1,208 1,030
Net Income Per Common Share Data
Continuing Operations2 $2.17 $2.50 $2.03
Discontinued Operations 0.06 - 0.11
Basic $2.23 $2.50 $2.14
(1)Net Income Applicable to Common Shares from Continuing
Operations:
Excluding gains 1,036 851 784
Gains as noted above 13 357 194
1,049 1,208 978
(2)Net Income Applicable to Common Share Data from Continuing
Operations:
Excluding gains $2.17 $1.76 $1.63
Gains as noted above 0.03 0.74 0.40
$2.17 $2.50 $2.03
MANAGEMENT'S DISCUSSION AND ANALYSIS 5
RESULTS OF OPERATIONS
Effective June 1, 2006, TCPL revised the composition and names of its reportable
business segments to Pipelines and Energy. The financial reporting of these
segments was aligned to reflect the internal organizational structure of the
Company. Pipelines principally comprises the Company's pipelines in Canada, the
U.S. and Mexico. Energy includes the Company's power operations, natural gas
storage business and liquefied natural gas (LNG) projects in Canada and the U.S.
The segmented information has been retroactively reclassified to reflect the
changes in reportable segments. These changes had no impact on consolidated net
income.
Net income applicable to common shares for the year ended December 31, 2006 was
$1,077 million compared to $1,208 million for 2005 and $1,030 million for 2004.
This includes net income from discontinued operations of $28 million in 2006,
reflecting bankruptcy settlements with Mirant Corporation and certain of its
subsidiaries (Mirant) related to TCPL's Gas Marketing business divested in 2001.
Income from discontinued operations of $52 million in 2004 reflects income
recognized on initially deferred gains relating to Mirant.
Net earnings for the year ended December 31, 2006 were $1,049 million compared
to $1,208 million in 2005 and $978 million in 2004. Net earnings for 2006
included after-tax gains of $13 million from the sale of TCPL's general partner
interest in Northern Border Partners, L.P. Net earnings for 2005 included
after-tax gains of $193 million on the sale of the Company's interest in
TransCanada Power, L.P. (Power LP), $115 million on the sale of the Company's
interest in P.T. Paiton Energy Company (Paiton Energy) and $49 million on the
sale of PipeLines LP units.
Excluding gains of $13 million in 2006 and $357 million in 2005, net earnings in
2006 were $1,036 million, an increase of $185 million compared to 2005. This
increase was mainly due to higher net earnings in Energy and Corporate,
partially offset by decreased net earnings in Pipelines.
Excluding the gains on sale of the Northern Border Partners, L.P. interest in
2006 and the PipeLines LP units in 2005, net earnings in the Pipelines business
decreased $83 million in 2006 compared to 2005. The decrease was primarily due
to lower net earnings from the Canadian Mainline and the Alberta System as a
result of lower approved rates of return on common equity (ROE) and lower
average investment bases in 2006 compared to 2005. In addition, the Company's
Other Pipelines businesses and the Gas Transmission Northwest System and the
North Baja system (collectively GTN) experienced lower earnings in 2006.
Excluding the gain on the sale of Paiton Energy and gains related to the
Company's investment in Power LP in 2005, Energy's net earnings for 2006
increased $194 million compared to 2005 as a result of higher operating income
from each of its existing businesses as well as a $23-million favourable impact
on future income taxes arising from reductions in Canadian federal and
provincial income tax rates in 2006. These increases were partially offset by a
loss of operating income associated with the sale of Power LP in 2005.
The increase in Corporate's net earnings in 2006 of $74 million compared to 2005
was primarily due to $72 million of positive income tax adjustments in 2006.
Net earnings increased $230 million in 2005 compared to 2004. The increase was
primarily due to the inclusion of gains of $357 million in 2005 compared to
gains of $194 million in 2004. Excluding gains, Pipeline's net earnings
increased due to the inclusion of a full year of earnings from GTN in 2005 and
the positive impact on earnings of a National Energy Board (NEB) decision to
increase the Canadian Mainline's common equity component in its deemed capital
structure. This was partially offset by the Canadian Mainline's lower average
investment base, lower earnings related to operating cost savings, a decrease in
the approved ROE and lower net earnings from the Company's Other Pipelines'
businesses in 2005. Energy's net earnings, excluding gains, increased in 2005,
compared to 2004, primarily due to higher operating income from Bruce Power A
L.P. (Bruce A) and Bruce Power L.P. (Bruce B) (collectively Bruce Power), and
Eastern Power Operations. A lower contribution from Western Power Operations and
higher general administrative, support costs and other also reduced Energy's net
earnings in 2005 compared to 2004. Corporate's net expenses increased in 2005
compared to 2004, primarily due to increased net interest expense on higher
average long-term debt and commercial paper balances in 2005.
6 MANAGEMENT'S DISCUSSION AND ANALYSIS
SUBSEQUENT EVENTS
ANR Acquisition
On February 22, 2007, TCPL closed the acquisition of ANR and an additional 3.55
per cent interest in Great Lakes from El Paso Corporation for approximately
US$3.4 billion, subject to certain post-closing adjustments, including
approximately US$488 million of assumed long-term debt. The acquisition of ANR
added approximately 17,000 kilometres (km) of natural gas transmission pipeline
with a peak-day capacity of 6.8 Bcf/d. ANR also owns and operates natural gas
storage facilities with a total capacity of approximately 230 Bcf. The
acquisition was financed with a combination of proceeds from the Company's
recent issuance of $1.3 billion of common shares, cash on hand and funds drawn
on existing and newly established loan facilities, discussed below.
In February 2007, the Company, through a wholly owned subsidiary, executed an
agreement with a syndicate of banks to establish a new US$1.0 billion credit
facility, consisting of a US$700 million five-year term loan and a US$300
million five-year extendible revolving facility. This facility is committed and
unsecured. The Company utilized US$1.0 billion from this facility and an
additional US$100 million from an existing demand line to partially finance the
ANR acquisition as well as additional investments in PipeLines LP, described
below.
Great Lakes Acquisition
On February 22, 2007, PipeLines LP closed its acquisition of a 46.45 per cent
interest in Great Lakes from El Paso Corporation for approximately US$962
million, which included approximately US$212 million of assumed long-term debt,
subject to certain post-closing adjustments. At December 31, 2006, TransCanada
had a 13.4 per cent interest in PipeLines LP.
In February 2007, PipeLines LP increased the size of its syndicated revolving
credit and term loan agreement from US$410 million to US$950 million.
Incremental draws of US$126 million received under this agreement were used to
partially finance PipeLines LP's Great Lakes acquisition.
On February 22, 2007, PipeLines LP completed a private placement offering of
17,356,086 common units at a price of US$34.57 per unit, of which 50 per cent of
the units were acquired by TCPL, for US$300 million. TCPL also invested an
additional approximately US$12 million to maintain its general partnership
ownership interest in PipeLines LP. As a result of TCPL's additional investments
in Pipelines LP, its ownership in PipeLines LP increased to 32.1 per cent. The
total private placement resulted in gross proceeds to PipeLines LP of US$612
million, which were used to partially finance its Great Lakes acquisition. As a
result of TCPL's increased ownership in PipeLines LP, TCPL's effective ownership
in Tuscarora Gas Transmission Company (Tuscarora), Northern Border Pipeline
Company (Northern Border) and Great Lakes increased to 32.5 per cent (including
one per cent held directly), 16.1 per cent and 68.5 per cent (including 53.55
per cent held directly), respectively.
MANAGEMENT'S DISCUSSION AND ANALYSIS 7
FORWARD-LOOKING INFORMATION
Certain information in this MD&A includes forward-looking statements. All
forward-looking statements are based on TCPL's beliefs and assumptions based on
information available at the time such statements were made. Factors which could
cause actual results or events to differ materially from current expectations
include, among other things, the ability of TCPL to successfully implement its
strategic initiatives and whether such strategic initiatives will yield the
expected benefits, the availability and price of energy commodities, regulatory
decisions, changes in environmental and other laws and regulations, competitive
factors in the pipeline and energy industry sectors, construction and completion
of capital projects, access to capital markets, interest and currency exchange
rates, technological developments and the current economic condition in North
America. By its nature, such forward-looking information is subject to various
risks and uncertainties, which could cause TCPL's actual results and experience
to differ materially from the anticipated results or other expectations
expressed. Readers are cautioned not to place undue reliance on this
forward-looking information, which is given as of the date of this MD&A or as
otherwise stated. TCPL undertakes no obligation to update publicly or revise any
forward-looking information, whether as a result of new information, future
events or otherwise, except as required by law.
NON-GAAP MEASURES
The Company uses the measures "funds generated from operations" and "operating
income" in this MD&A. These measures do not have any standardized meaning in
GAAP and are therefore considered to be non-GAAP measures. These measures may
not be comparable to similar measures presented by other entities. These
measures have been used to provide readers with additional information on the
Company's liquidity and its ability to generate funds to finance its operations.
Funds generated from operations is comprised of net cash provided by operations
before changes in operating working capital. A reconciliation of funds generated
from operations to net cash provided by operations is presented in the
Summarized Cash Flow table in this MD&A. Operating income is used in the Energy
segment and is comprised of revenues plus income from equity investments less
operating expenses as shown on the consolidated income statement. Refer to the
Energy section in this MD&A for a reconciliation of operating income to net
earnings.
TCPL OVERVIEW
TCPL is a leading North American energy infrastructure company with a strong
focus on natural gas transmission and power generation opportunities located in
regions in which it has significant competitive advantages. Natural gas
transmission and power are complementary businesses for TCPL. They are driven by
similar supply and demand fundamentals, they are both capital-intensive
businesses, and they use similar technology and operating practices. They are
also businesses with significant long-term growth prospects.
North American natural gas demand is expected to increase primarily due to a
growing demand for electricity. Experts predict that demand for electricity will
increase at an average annual rate of approximately two per cent over the next
ten years, primarily due to a growing population and an increase in gross
domestic product. A large part of that demand growth is expected to be met by
higher utilization of existing natural gas-fired generating plants.
Nuclear facilities have played, and will continue to play, a significant role in
supplying North American power. Coal-fired plants remain the largest source of
electric power in North America and coal reserves are significant. However, the
long lead times required to complete new coal and nuclear projects may impede
the development and completion of new coal or nuclear generation over the next
five to ten years. As a result, North America is expected to continue to rely on
natural gas-fired generation to satisfy its growing electricity needs in the
near term. This is expected to lead to a significant increase in natural gas
consumption. Natural gas demand in North America, including Mexico, is expected
to
8 MANAGEMENT'S DISCUSSION AND ANALYSIS
grow to approximately 89 billion cubic feet per day (Bcf/d) by 2016, an increase
of 14 Bcf/d when compared to 2006. New natural gas-fired power generation is
expected to account for approximately 9 Bcf/d of that growth.
While growing demand will provide a number of opportunities, the natural gas
industry also faces a number of challenges. North America has entered a period
when it will no longer be able to rely solely on traditional sources of natural
gas supply to meet its growing needs. Natural gas supply is limited and this is
likely to continue until major investments are made in the infrastructure
required to bring new supply to market. Looking forward, production from North
America's traditional basins is expected to essentially remain flat over the
next decade. An increase in production in the U.S. Rockies is expected to offset
declines in other basins, including the Gulf of Mexico. This outlook for
traditional basins means that northern gas and offshore LNG will be required to
fill the shortfall between supply and demand. TCPL is well positioned in North
America to serve growing power generation demand in the near term and to bring
these new natural gas supplies to market in the medium to long term.
TCPL'S STRATEGY
TCPL's strong position in North America is the direct result of successfully
executing its corporate strategy which was first adopted in 2000. While the plan
has evolved over time in response to actual and anticipated changes in the
business environment, it fundamentally remains the same. Today, TCPL's corporate
strategy consists of the following six components:
*
maximize the profitability and long-term value of existing pipelines;
*
grow the North American pipeline business, internally and through
acquisitions;
*
maximize the profitability and long-term value of existing power and
other energy assets;
*
grow the North American energy business, internally and through
acquisitions;
*
drive for operational excellence in all aspects of the business; and
*
maximize TCPL's competitive strength and enduring value.
Pipelines
Strategy
The Company's strategy in Pipelines is focused on both growing its North
American natural gas transmission network and maximizing the profitability and
long-term value of its existing pipeline assets. In order to grow the Pipelines
segment, TCPL is focusing on expanding and extending its existing systems to
connect new supply to growing markets, increasing its ownership in partially
owned entities, acquiring or constructing pipelines that provide TCPL with a
significant regional presence, expanding into the oil transmission business and,
in the long term, connecting new sources of supply in the form of northern gas
and LNG.
Over the past 50 years, TCPL has developed significant expertise in
large-diameter, cold-weather natural gas pipeline design, construction,
operation and maintenance. It has also developed significant expertise in the
design, optimization and operation of large gas turbine compressor stations.
Today, TCPL operates one of the largest, most sophisticated, remote-controlled
pipeline networks in the world with a solid reputation for safety and
reliability.
In addition to growing the North American Pipelines business, the Company
continues to place a priority on maximizing the profitability and long-term
value of its wholly owned pipelines. Efforts in this area are focused on
achieving a fair return on invested capital and streamlining and harmonizing
processes and tariff provisions for and among TCPL's regulated pipelines.
Further, the Company works collaboratively with its customers to develop and
implement new services. TCPL also provides services to many of its partially
owned pipeline systems.
MANAGEMENT'S DISCUSSION AND ANALYSIS 9
Existing Pipelines
TCPL's natural gas transmission assets link the Western Canada Sedimentary Basin
(WCSB) with premium North American markets. With approximately 42,000 km of
pipeline (at December 31, 2006), the Company's network of wholly owned pipeline
assets is one of the largest in North America.
In 2006, the wholly owned Alberta System gathered 67 per cent of the natural gas
produced in western Canada or 17 per cent of total North American production.
TCPL exports natural gas from the WCSB to Eastern Canada and the U.S. West,
Midwest and Northeast through four wholly owned pipeline systems:
*
Canadian Mainline;
*
Gas Transmission Northwest System;
*
Foothills; and
*
BC System.
In addition, the Company transports natural gas in Alberta through the TCPL
Pipeline Ventures Limited Partnership (Ventures LP) System.
In December 2006, TCPL began transporting natural gas in Mexico through its
Tamazunchale pipeline.
TCPL also exports gas from the WCSB to eastern Canada as well as the U.S. West,
Midwest and Northeast through six partially owned pipeline systems:
*
Great Lakes;
*
Trans Quebec & Maritimes System (TQM);
*
Iroquois Gas Transmission System (Iroquois);
*
Portland Natural Gas Transmission System (Portland);
*
Northern Border; and
*
Tuscarora.
Northern Development
In 2006, TCPL continued to pursue the Mackenzie Delta and Alaska North Slope
projects. When the Mackenzie Gas Pipeline (MGP) project and the Alaska Highway
Pipeline project are constructed and connected to TCPL's existing
infrastructure, they would represent additional growth opportunities for TCPL
and enhance the long-term viability and value of the Company's existing
Pipelines business, especially the wholly owned pipelines currently transporting
WCSB natural gas.
Mexico
In addition to the Tamazunchale pipeline, TCPL continues to explore other
pipeline and energy infrastructure opportunities in Mexico.
ANR and Great Lakes
On February 22, 2007, TCPL closed its acquisition of ANR and an additional 3.55
per cent interest in Great Lakes. In addition, PipeLines LP closed its
acquisition of a 46.45 per cent interest in Great Lakes.
10 MANAGEMENT'S DISCUSSION AND ANALYSIS
Regulatory
In 2006, TCPL's principal regulatory activities included a negotiated settlement
with respect to 2006 Canadian Mainline tolls; filing a rate case with the
Federal Energy Regulatory Commission (FERC) for new Gas Transmission Northwest
System rates; filing an application with the NEB to integrate the BC System into
the Foothills Zone 8 facilities and (received NEB approval in February 2007);
filing an application with the NEB seeking approval to transfer approximately
860 km of the Canadian Mainline's existing natural gas pipeline to oil service;
filing an application with the NEB to construct and operate approximately 370 km
of new oil pipeline, terminal facilities and pump stations; and filing
applications that sought approval to transfer a portion of the Canadian
Mainline's assets to Keystone and to reduce the Canadian Mainline's rate base by
the net book value (NBV) of the transferred assets (received NEB approval in
February 2007).
Energy
Strategy
TCPL's strategy for growth and value creation in the Energy business has five
key elements:
*
focusing on markets where TCPL has a competitive advantage;
*
developing low-risk, greenfield generation projects, underpinned by
long-term input and sales contracts with quality counterparties;
*
acquiring low-cost, base-load power generation. The Company believes
that being a low-cost provider and/or having long-term sales contracts
is critical to being successful in volatile power markets;
*
exploiting TCPL's proven strong project management skills; and
*
optimizing the profitability and reliability of the existing asset
portfolio by operating the facilities as efficiently and
cost-effectively as possible.
TCPL's ability to successfully execute its strategy is related to a broad
understanding of North American energy markets and a deep understanding of its
core markets in Alberta, Ontario, Quebec, and the northeastern U.S. In addition,
the Company actively participates in deregulated and deregulating markets and
has the ability to structure transactions and manage risk, which is critical to
mitigating volatility in natural gas and power markets.
Existing Assets
TCPL has built a substantial energy business over the past decade and has
achieved a significant presence in power generation across Canada and the U.S.
More recently, TCPL has developed its natural gas storage business through
investments in Alberta.
,G465925.JPG The power plants and power supply that TCPL owns, operates and/or controls, including
projects under construction, represent approximately 7,700 megawatts (MW) of power
generation capacity in Canada and the U.S. TCPL's portfolio of power supply is diversified:
33 per cent natural gas; 32 per cent nuclear; 22 per cent coal; seven per cent hydro and
six per cent wind. TCPL's power assets are primarily low-cost, base load generation and/or
backed by secure, long-term power sales agreements. The Company's power assets are
concentrated in two main regions: Western Power Operations in Alberta and Eastern Power
Operations in the eastern Canada and New England markets.
Energy's natural gas storage assets are all located in Alberta. TCPL owns or controls more
than 130 billion cubic feet (Bcf) or approximately one third of the natural gas storage
capacity in the province. TCPL believes the market fundamentals for natural gas storage will remain strong into the
future.
MANAGEMENT'S DISCUSSION AND ANALYSIS 11
In 2006, TCPL continued to add to its diverse portfolio of existing quality
energy assets as follows:
Becancour
Construction of the Becancour cogeneration plant was completed and placed
commercially in service in September 2006. The project was completed on time and
under budget and is the largest greenfield power plant built by TCPL to date.
Portlands Energy
In September 2006, Portlands Energy Centre L.P. (Portlands Energy) announced
that it had signed a 20-year Accelerated Clean Energy Supply (ACES) contract
with the Ontario Power Authority (OPA) to construct a natural gas generation
plant to be located in downtown Toronto, Ontario.
Cartier Wind
In November 2006, the Baie-des-Sables wind farm went into commercial operation
and is currently one of the largest wind farms in Canada, providing 110 MW of
power to the Hydro-Quebec grid.
Halton Hills
In November 2006, TCPL announced that it had been awarded a contract to build,
own and operate a natural gas-fired power plant near the town of Halton Hills,
Ontario.
Bruce Power
Throughout 2006, work continued on the Bruce A capital project, consisting of
the restart and refurbishment of the currently idle Units 1 and 2, extension of
the operating life of Unit 3 by replacing its steam generators and fuel channels
when required, and replacement of the steam generators on Unit 4.
Edson Gas Storage
Construction of the Edson natural gas storage facility was substantially
completed and placed into service on December 31, 2006.
Broadwater and Cacouna LNG Facilities
TCPL continues to pursue these two LNG proposals.
Operational Excellence
TCPL maintains a high level of pipeline operating performance, as measured by
the minimal disruptions for the Canadian Mainline, the Alberta System and GTN.
In 2006, TCPL developed a technology program involving techniques to reduce the
cost and environmental impact of constructing new pipeline. The program, which
negates the need for large volumes of water, was applied to a segment of TCPL's
pipeline construction. The technology was accepted by the NEB which is expected
to encourage further development by TCPL and to promote wide-scale use.
Through its annual Customer Satisfaction Survey, TCPL received feedback from
customers served by its Canadian pipelines. The survey, conducted by Ipsos Reid
in the fall of 2006, found that TCPL maintained high levels of overall customer
satisfaction. TCPL's call centre, transactional systems and staff obtained the
highest satisfaction levels. This reflects TCPL's commitment to operational
excellence in the provision of reliable and high-quality service to customers.
The Company was very productive in 2006 with respect to collaborative efforts
with customers. The Mainline Tolls Task Force, the Alberta System Tolls, Tariff,
Facilities and Procedures Committee, and the BC System and Foothills Shippers
group produced a number of resolutions in 2006. These resolutions included new
services, service enhancements,
12 MANAGEMENT'S DISCUSSION AND ANALYSIS
process improvements, a Canadian Mainline tolls settlement and the proposed
integration of the BC System into the Foothills system, which was approved by
the NEB in February 2007. Productive collaborative processes can result in
significant costs savings for both TCPL and the industry by avoiding costs
associated with regulatory proceedings.
In Energy, TCPL continued its commitment in 2006 to provide safe, low-cost
operations and maintenance of all assets to ensure the highest possible
reliability and availability. For power plants directly operated by TCPL, the
weighted average plant availability in 2006 was 93 per cent compared to 87 per
cent in 2005.
In 2007, TCPL will continue to focus efforts on efficiencies, operational
reliability, the environment and safety. Greenhouse gas emissions management
programs will continue to receive attention and further efforts will be
undertaken to improve contractor safety.
Competitive Strength and Enduring Value
TCPL's strategy includes:
*
developing excellence in value-creating strategy, analysis and
investment execution;
*
appropriate financial capacity and flexibility, allowing TCPL to build
large scale infrastructure projects and act quickly on quality
opportunities when they arise;
*
using project development and project management skills, combined with
strong facility construction and operational abilities;
*
maintaining high standards in corporate governance practices;
*
developing and sustaining its relationships and reputation with key
stakeholders; and
*
creating sustainable organizational strengths.
At December 31, 2006, TCPL had approximately 2,350 employees who have expertise
in gas transmission and power operations, project management, depth of market
and industry knowledge, and financial acumen.
MANAGEMENT'S DISCUSSION AND ANALYSIS 13
OUTLOOK
Since 2000, TCPL has followed a long-term approach of growing its Pipelines and
Energy businesses in a diligent and disciplined manner. In 2007 and beyond, the
Company's net earnings and cash flow, combined with a strong balance sheet, are
expected to continue to provide the financial flexibility for TCPL to pursue
opportunities and create additional long-term value for its shareholders.
In 2007, the Company will continue to implement its Pipelines strategy,
including:
*
integrating ANR into TCPL's existing Pipelines business;
*
becoming the operator of Great Lakes in conjunction with the acquisition
of an additional 3.55 per cent interest in Great Lakes, bringing its
direct total ownership to 53.55 per cent, with PipeLines LP owning the
remaining interest;
*
engaging in discussions with Alberta System stakeholders following the
conclusion of the current three-year settlement that expires at the end
of 2007;
*
proceeding with the Gas Transmission Northwest System rate case, which
is scheduled to be in negotiations and answering discovery until the
hearing phase begins on October 31, 2007;
*
advancing development of the Keystone Pipeline;
*
working with the MGP owners and the Aboriginal Pipeline Group (APG),
including participating in regulatory proceedings as may be required, to
advance the MGP project;
*
working with project stakeholders and the State of Alaska to further
advance the proposed Alaska Highway Pipeline project;
*
developing transportation solutions for new market and supply growth
opportunities that lead to potential expansions of the Alberta System;
*
becoming the operator of Northern Border; and
*
working with joint venture partners of partially owned pipeline systems
to develop additional supply and market options for system customers.
TCPL will continue to grow its Energy business in 2007. As in prior years, this
growth is expected to come from a mix of greenfield developments, new
acquisitions and organic growth within its existing assets and markets. In
particular, in 2007, TCPL expects to:
*
work with Bruce A and its partners on the restart and refurbishment of
the Bruce A units;
*
complete construction of the second of six Cartier Wind projects in
third quarter 2007 and begin construction of the third Cartier Wind
facility;
*
continue construction of the Portlands Energy project;
*
initiate construction of the Halton Hills project;
*
advance development of the Cacouna Energy project (Cacouna) and
Broadwater Energy project (Broadwater) LNG facilities; and
*
pursue additional greenfield projects and acquisition opportunities in
TCPL's key markets.
Although the following discussion reflects management's expectations for 2007,
as discussed throughout this MD&A, a number of risk factors and developments may
positively or negatively affect the actual results for 2007, as discussed
throughout this MD&A, including the section entitled "Forward-Looking
Information".
14 MANAGEMENT'S DISCUSSION AND ANALYSIS
With the closing of the acquisition of ANR and Great Lakes, and the Company's
increased ownership in PipeLines LP, TCPL expects higher net earnings from
Pipelines in 2007 compared to 2006. The combined effect of an expected decline
in the average investment base of each of the Canadian Mainline and the Alberta
System, and a decline in each of their formula-based regulated ROEs is expected
to decrease net earnings on these systems compared to 2006. Excluding any
potential positive impact from a decision or settlement on the current rate case
filing for the Gas Transmission Northwest System, reduced firm contract volumes
on this system are expected to have a slightly negative impact on the results
compared to 2006. In addition, Pipelines' 2006 net earnings included a $13
million gain on the sale of Northern Border Partners, L.P. interest, which will
not occur in 2007. In 2007, TCPL is expecting a positive impact from a full year
of earnings from the Tamazunchale pipeline.
In Energy, net earnings in 2007 are expected to approximate or be slightly lower
than 2006 net earnings due to the non-recurring $23-million future tax benefit
in 2006 arising from reductions in federal and provincial income tax rates.
Operating income is expected to be relatively consistent with 2006, although
this is very dependent on commodity prices in each region as well as other
factors such as hydrology and storage spreads. TCPL's operating income from its
investment in Bruce B can be significantly impacted by the effect, on
uncontracted output, of changes in spot market prices for power. Excluding any
changes in spot market prices for 2007 compared to 2006, Bruce Power's operating
income is expected to decline in 2007 compared to 2006, reflecting lower
projected generation volumes and higher operating costs resulting from an
increase in planned outages in 2007. Western Power Operations' operating income
in 2007 is expected to approximate 2006. Although TCPL has sold forward
significant output from its Alberta power purchase agreements (PPA) and power
plants, Western Power Operations' operating income in 2007 can be significantly
impacted by changes in the spot market price of power and market heat rates in
Alberta. Eastern Power Operations' operating income is expected to increase in
2007 primarily due to a full year of operations for both the Becancour natural
gas-fired cogeneration facility and the first of six wind farms of the Cartier
Wind project as well as the positive impact of the New England Power Pool
(NEPOOL) forward capacity payments received by Ocean State Power (OSP) and TC
Hydro commencing December 1, 2006. Gas Storage's operating income is expected to
increase in 2007 over 2006 primarily due to the placing into service of the
Edson facility at the end of 2006, partially offset by expected lower storage
spreads.
Corporate's net expenses are expected to be higher in 2007 compared to 2006
primarily due to the income tax refunds and positive income tax adjustments
realized in 2006 that are not expected to recur in 2007. Financing costs
associated with the purchase of ANR are expected to increase net expenses in
Corporate in 2007.
MANAGEMENT'S DISCUSSION AND ANALYSIS 15
,G531525.JPG
CANADIAN MAINLINE TCPL's 100 per cent owned 14,957 km natural gas transmission
system in Canada extends from the Alberta/Saskatchewan border east to the Quebec
/Vermont border and connects with other natural gas pipelines in Canada and the
U.S.
ALBERTA SYSTEM TCPL's 100 per cent owned natural gas transmission system in
Alberta gathers natural gas for use within the province and delivers it to
provincial boundary points for connection with the Canadian Mainline, BC System,
Foothills and other pipelines. The 23,498 km system is one of the largest
carriers of natural gas in North America.
GAS TRANSMISSION NORTHWEST SYSTEM TCPL's 100 per cent owned natural gas
transmission system extends 2,174 km and links the BC System and Foothills with
Pacific Gas and Electric Company's California Gas Transmission System, with
Williams' Northwest Pipeline in Washington and Oregon, and with Tuscarora.
FOOTHILLS TCPL's 100 per cent owned, 1,040 km natural gas transmission system
in western Canada carries natural gas for export from central Alberta to the
U.S. border to serve markets in the U.S. Midwest, Pacific Northwest, California
and Nevada.
16 MANAGEMENT'S DISCUSSION AND ANALYSIS
BC SYSTEM TCPL's 100 per cent owned natural gas transmission system extends
201 km from Alberta's western border through British Columbia (B.C.) to connect
with the Gas Transmission Northwest System at the U.S. border, serving markets
in B.C. as well as the Pacific Northwest, California and Nevada.
NORTH BAJA TCPL's 100 per cent owned natural gas transmission system extends
129 km from southwestern Arizona at Ehrenberg to a point near Ogilby, California
on the California/Mexico border and connects with the Gasoducto Bajanorte
pipeline system in Mexico.
VENTURES LP Ventures LP, which is 100 per cent owned by TCPL, owns a 121 km
pipeline and related facilities which supply natural gas to the oil sands region
of northern Alberta, and a 27 km pipeline which supplies natural gas to a
petrochemical complex at Joffre, Alberta.
TAMAZUNCHALE TCPL's 100 per cent owned 130 km natural gas pipeline in east
central Mexico extends from the facilities of Pemex Gas near Naranjos, Veracruz
to an electricity generation station near Tamazunchale, San Luis Potosi. This
pipeline went into service on December 1, 2006.
ANR On February 22, 2007, TCPL acquired 100 per cent of the ANR natural gas
transmission system which extends approximately 17,000 km from producing fields
in Louisiana, Oklahoma, Texas and the Gulf of Mexico to markets in Wisconsin,
Michigan, Illinois, Ohio and Indiana. This pipeline also connects with other
pipelines to give access to supply from western Canada, the Rocky Mountain
region and a variety of markets in the midwestern and northeastern U.S. ANR also
owns and operates underground natural gas storage facilities in Michigan with a
total capacity of approximately 230 Bcf.
TUSCARORA Tuscarora is owned or controlled 99 per cent by PipeLines LP and is
a 491 km pipeline system transporting natural gas from the Gas Transmission
Northwest System at Malin, Oregon to Wadsworth, Nevada with delivery points in
northeastern California and northwestern Nevada. TCPL operates Tuscarora and, at
February 22, 2007, effectively owns or controls an aggregate 32.8 per cent
interest in Tuscarora, of which 31.8 per cent is held indirectly through TCPL's
32.1 per cent ownership interest in PipeLines LP and the remaining one percent
is owned directly.
NORTHERN BORDER Northern Border is 50 per cent owned by PipeLines LP and is a
2,250 km natural gas pipeline system which serves the U.S. Midwest from a
connection with Foothills near Monchy, Saskatchewan. In April 2007, TCPL expects
to become the operator of Northern Border. At February 22, 2007, the Company
effectively owns approximately 16.1 per cent of Northern Border through its 32.1
per cent ownership interest in PipeLines LP.
GREAT LAKES Great Lakes is a 3,404 km pipeline system that connects with the
Canadian Mainline at Emerson, Manitoba and serves markets in central Canada and
the midwestern U.S. Effective February 22, 2007, TCPL owns 53.55 per cent of
Great Lakes and PipeLines LP owns the remaining 46.45 per cent. TCPL's effective
ownership of Great Lakes is 68.5 per cent of which 14.9 per cent is held
indirectly through its 32.1 per cent ownership in PipeLines LP. TCPL is the
operator of Great Lakes.
IROQUOIS Iroquois connects with the Canadian Mainline near Waddington, New
York and delivers natural gas to customers in the northeastern U.S. TCPL has a
44.5 per cent ownership interest in this 666 km pipeline system.
TQM TQM is a 572 km natural gas pipeline system which connects with the
Canadian Mainline and transports natural gas from Montreal to Quebec City and to
the Portland system. TCPL holds a 50 per cent ownership interest in TQM and is
the operator.
PORTLAND Portland is a 474 km pipeline that connects with TQM near East
Hereford, Quebec and delivers natural gas to customers in the northeastern U.S.
TCPL has a 61.7 per cent ownership interest in Portland and operates this
pipeline.
TRANSGAS TransGas is a 344 km natural gas pipeline system which runs from
Mariquita in the central region of Colombia to Cali in the southwest of
Colombia. TCPL holds a 46.5 per cent ownership interest in this pipeline.
GAS PACIFICO Gas Pacifico is a 540 km natural gas pipeline extending from Loma
de la Lata, Argentina to Concepcion, Chile. TCPL holds a 30 per cent ownership
interest in Gas Pacifico.
INNERGY INNERGY is an industrial natural gas marketing company based in
Concepcion, Chile that markets natural gas transported on Gas Pacifico. TCPL
holds a 30 per cent ownership interest in INNERGY.
MANAGEMENT'S DISCUSSION AND ANALYSIS 17
HIGHLIGHTS
Net Earnings
*
Net earnings from Pipelines decreased $119 million to $560 million in
2006 compared to $679 million in 2005, primarily due to a $49-million
gain on the sale of PipeLines LP units in 2005 ($13-million gain on the
sale of the interest in Northern Border Partners, L.P. in 2006), lower
net earnings from the Canadian Mainline and the Alberta System as a
result of a lower ROE and lower average investment bases in 2006,
compared to 2005, and a $13-million Mainline adjustment in 2005 related
to a 2004 regulatory decision.
ANR and Great Lakes Acquisition
*
On February 22, 2007, TCPL acquired ANR and an additional 3.55 per cent
interest in Great Lakes.
Canadian Mainline
*
The NEB approved a negotiated settlement of 2006 Mainline tolls which
included a deemed common equity ratio of 36 per cent and incentives for
managing costs through fixing certain components of the revenue
requirement.
Alberta System
*
The Alberta System continues to operate under the terms of the 2005-2007
Revenue Requirement Settlement approved by the Alberta Energy and
Utilities Board (EUB) in 2005. The settlement includes a deemed common
equity ratio of 35 per cent.
Gas Transmission Northwest System
*
In June 2006, Gas Transmission Northwest System filed a rate case with
the FERC. The comprehensive filing requests a number of tariff changes,
including increased rates for transportation services.
Keystone
*
TCPL filed two applications with the NEB in 2006. In the first
application, TCPL applied to transfer a portion of its Canadian Mainline
assets to Keystone and to reduce the Canadian Mainline's rate base by
the NBV of the transferred assets. Approval was received from the NEB on
this application in February 2007. In the second application, TCPL
applied to construct and operate new oil pipeline facilities.
Foothills and BC System
*
In February 2007, TCPL received approval from the NEB to integrate the
BC System into Foothills in southern B.C.
North Baja
*
In February 2006, TCPL filed an application with the FERC to expand
North Baja to accommodate bi-directional natural gas flow and to
construct new pipeline and metering facilities. In October 2006, the
FERC issued a preliminary approval of the application except for
environmental issues, which will be the subject of a future order.
PipeLines LP
*
In April 2006, PipeLines LP acquired an additional 20 per cent
partnership interest in Northern Border.
*
In December 2006, PipeLines LP acquired an additional 49 per cent
controlling general partner interest in Tuscarora, with the option to
purchase Sierra Pacific Resources remaining one per cent interest in
Tuscarora in approximately one year.
*
On February 22, 2007, PipeLines LP acquired a 46.45 per cent interest in
Great Lakes.
*
TCPL became the operator of Tuscarora in December 2006 and Great Lakes
in February 2007 and expects to begin operating Northern Border in April
2007.
*
In February 2007, PipeLines completed a private placement offering of
17,356,086 units at a price of US$34.57 per unit. TCPL acquired 50 per
cent of the units for US$300 million, increasing its total ownership to
32.1 per cent. TCPL also invested an additional approximately US$12
million to maintain its general partnership interest in PipeLines LP.
The total private placement resulted in gross proceeds of approximately
US$612 million which were used to partially finance the acquisition of
the 46.45 per cent interest in Great Lakes.
Other Pipelines
*
TCPL sold its 17.5 per cent general partner interest in Northern Border
Partners, L.P. for an after-tax gain of approximately $13 million.
*
TCPL continued its efforts to progress the proposed Alaska Highway
Pipeline.
*
TCPL continued to fund the APG participation in the MGP project.
*
In December 2006, TCPL commenced commercial operations of the
Tamazunchale pipeline in east-central Mexico.
18 MANAGEMENT'S DISCUSSION AND ANALYSIS
PIPELINES RESULTS-AT-A-GLANCE
Year ended December 31 (millions of dollars)
2006 2005 2004
Wholly Owned Pipelines
Canadian Mainline 239 283 272
Alberta System 136 150 150
GTN(1) 64 71 14
Foothills 21 21 22
BC System 6 6 7
466 531 465
Other Pipelines
Great Lakes 44 46 55
Iroquois 15 17 17
PipeLines LP(2) 4 9 16
Portland 13 11 10
Ventures LP 12 12 15
TQM 7 7 8
Tamazunchale(3) 2 - -
TransGas 11 11 11
Gas Pacifico/INNERGY(4) 8 6 4
Northern Development (5 ) (4 ) (6 )
General, administrative, support costs and other (30 ) (16 ) (18 )
81 99 112
Gain on sale of Northern Border Partners, L.P. interest 13 - -
Gain on sale of PipeLines LP units - 49 -
Gain on sale of Millennium - - 7
94 148 119
Net earnings 560 679 584
(1)
TCPL acquired GTN in November 2004. Amounts in this table reflect TCPL's 100
per cent ownership interest in GTN's net earnings from the acquisition
date.
(2)
During 2005, TCPL decreased its ownership interest in PipeLines LP to 13.4
per cent from 33.4 per cent.
(3)
The Tamazunchale pipeline went into service December 1, 2006.
(4)
Gasoducto del Pacifico S.A./INNERGY Holdings S.A.
In 2006, net earnings from the Pipelines business were $560 million compared to
$679 million and $584 million in 2005 and 2004, respectively. Excluding the
$49-million after-tax gain on the sale of PipeLines LP units in 2005 and the
$13-million after-tax gain on the sale of TCPL's general partner interest in
Northern Border Partners, L.P. in 2006, Pipelines' net earnings for the year
ended December 31, 2006 decreased $83 million compared to the same period in
2005. This decrease was primarily due to lower net earnings from the Canadian
Mainline, the Alberta System, GTN and Other Pipelines.
The overall increase of $95 million in 2005 Pipelines net earnings compared to
2004 was mainly due to a full year of GTN net earnings, the $49-million gain
related to PipeLines LP and higher Canadian Mainline net earnings in 2005 as a
result of an April 2005 NEB decision that resulted in a positive $13-million
adjustment related to 2004, partially offset
MANAGEMENT'S DISCUSSION AND ANALYSIS 19
by lower net earnings from Other Pipelines. Lower 2005 net earnings from Other
Pipelines were primarily due to decreased earnings from Great Lakes, PipeLines
LP and Ventures LP.
PIPELINES - FINANCIAL ANALYSIS
Canadian Mainline
The Canadian Mainline is regulated by the NEB. The NEB sets tolls which provide
TCPL with the opportunity to recover its projected costs of transporting natural
gas, including a return on the Canadian Mainline's average investment base. In
addition, new facilities are approved by the NEB before construction begins. Net
earnings of the Canadian Mainline are affected by changes in the investment
base, the ROE, the level of deemed common equity and potential incentive
earnings.
In April 2006, the NEB approved TCPL's application for a negotiated settlement
of the 2006 Canadian Mainline tolls as filed. The settlement resulted in a
revenue requirement of approximately $1.8 billion for 2006. The settlement also
established the Canadian Mainline's fixed OM&A costs for 2006 at $174 million
with variances between actual OM&A costs in 2006 and those agreed to in the
settlement accruing to TCPL. The majority of the other cost elements of the 2006
revenue requirement were to be treated on a flow-through basis. The settlement
also provided TCPL with an opportunity to realize modest additional net earnings
through performance-based incentive arrangements. These incentive arrangements
were focused on certain cost management activities and the management of fuel,
and provided mutual benefits to both TCPL and its customers. Further, the
settlement included an ROE of 8.88 per cent as determined for 2006 under the
NEB's return adjustment formula, on a deemed common equity ratio of 36 per cent.
Net earnings of $239 million in 2006 were $44 million lower than 2005 net
earnings of $283 million. The decrease was primarily due to a combination of a
lower ROE and a lower average investment base in 2006 compared to 2005. In
addition, 2005 net earnings included a positive adjustment of $13 million
related to 2004 as a result of the NEB's decision in April 2005 on the Canadian
Mainline's 2004 Tolls and Tariff Application (Phase II) which included an
increase in the deemed common equity ratio to 36 per cent from 33 per cent for
2005 that was also effective for 2004. The 2006 NEB-approved Canadian Mainline
tolls settlement that TCPL reached with its customers and other interested
parties included an ROE of 8.88 per cent, which was determined for 2006 under
the NEB's return adjustment formula on a deemed common equity ratio of 36 per
cent. The NEB-approved ROE for 2005 was 9.46 per cent.
The Canadian Mainline generated net earnings of $283 million in 2005, an
increase of $11 million over 2004 earnings. The increase in net earnings was
primarily due to the NEB's decision on the 2004 Tolls and Tariff Application
(Phase II). The Phase II decision resulted in a $35-million ($22 million related
to 2005 and $13 million related to 2004) increase to the Canadian Mainline's
2005 net earnings compared to 2004. However, this earnings increase was
partially offset by the combination of a lower average investment base, lower
cost savings and a lower approved ROE in 2005. The NEB-approved ROE decreased to
9.46 per cent in 2005 from 9.56 per cent in 2004.
,G1013369.JPG
20 MANAGEMENT'S DISCUSSION AND ANALYSIS
Alberta System
The Alberta System is regulated by the EUB primarily under the provisions of the
Gas Utilities Act (Alberta) (GUA) and the Pipeline Act (Alberta). Under the GUA,
the Alberta System's rates, tolls and other charges, and terms and conditions of
service are subject to approval by the EUB.
The Alberta System is currently operating under the 2005-2007 Revenue
Requirement Settlement. The settlement was reached in 2005 with shippers and
other interested parties regarding the annual revenue requirements of its
Alberta System for the years 2005, 2006 and 2007. The settlement was approved by
the EUB in June 2005 and encompassed all elements of the Alberta System revenue
requirement, including operating, maintenance and administration (OM&A) costs,
ROE, depreciation and income and municipal taxes.
The Alberta System settlement fixed OM&A costs at $193 million for 2005, $201
million for 2006, and $207 million for 2007. In each year, any variance between
actual OM&A and other fixed costs, and those agreed to in the settlement accrues
to TCPL. The majority of other cost elements of the 2005, 2006 and 2007 revenue
requirements are treated on a flow-through basis.
The ROE will be calculated annually during the term of the settlement using the
EUB formula for the purpose of establishing the annual generic rate of return
for Alberta utilities on deemed common equity of 35 per cent. In addition,
depreciation costs are determined using the depreciation rates and methodology
that the Company proposed to the EUB in its 2004 General Rate Application (GRA).
Net earnings of $136 million in 2006 were $14 million lower compared to 2005.
The decrease was primarily due to a lower investment base and a lower approved
rate of return in 2006. Net earnings in 2005 and 2006 reflect an ROE of 9.50 and
8.93 per cent, respectively, as prescribed by the EUB, on deemed common equity
of 35 per cent.
Net earnings of $150 million in 2005 were unchanged from 2004 due to the
negative impacts of a lower investment base and a lower approved rate of return
in 2005 being offset by the positive impact of higher allowed operating costs in
2005 compared to 2004 as a result of cost disallowances in the EUB's decision on
Phase 1 of the 2004 GRA. Net earnings in 2004 reflect an ROE of 9.60 as
prescribed by the EUB, on deemed common equity of 35 per cent.
,G98620.JPG
GTN
GTN is regulated by the FERC, which has authority to regulate rates for natural
gas transportation in interstate commerce. Both of GTN's systems, the Gas
Transmission Northwest System and North Baja, operate under fixed rate rates,
under which maximum and minimum rates for various service types have been
ordered by the FERC. GTN is permitted to discount or negotiate these models on a
non-discriminatory basis. In 2006, the Gas Transmission Northwest System
operated under a rate case that was filed in 1994 and was settled and approved
by the FERC in 1996. In June 2006, the Gas Transmission Northwest System filed a
new rate case with the FERC. North Baja's rates were established in the FERC's
initial order in 2002 certifying construction and operation of the system. The
net earnings of GTN are impacted by variations in contracted levels, volumes
delivered and prices charged under the various service types that are provided,
as well as by variations in the costs of providing services.
MANAGEMENT'S DISCUSSION AND ANALYSIS 21
Net earnings for the year ended December 31, 2006 were $64 million, a $7-million
decrease from the same period in 2005. This decrease was primarily due to lower
transportation revenues, higher operating costs, the impact of a weaker U.S.
dollar and a provision for non-payment of contract transportation revenue from a
subsidiary of Calpine Corporation that filed for bankruptcy protection. These
negative factors were partially offset by an $18-million bankruptcy settlement
($29 million pre-tax) in first quarter 2006 with Mirant, a former shipper on the
Gas Transmission Northwest System. Net earnings for November and December 2004
were $14 million.
Other Pipelines
TCPL's direct and indirect investments in various natural gas pipelines are
included in Other Pipelines. It also includes TCPL's project development
activities related to its pursuit of new pipelines and gas and oil transmission
related opportunities throughout North America.
TCPL's net earnings from Other Pipelines in 2006 were $94 million compared to
$148 million and $119 million in 2005 and 2004, respectively. Excluding the
gains on sale of Northern Border Partners, L.P. in 2006 and PipeLines LP units
in 2005, net earnings for 2006 were $18 million lower compared to 2005. The
decrease was primarily due to higher project development and support costs
associated with growing the Pipelines business, reduced ownership in PipeLines
LP, a weaker U.S. dollar and bankruptcy settlements received by Iroquois in
2005, partially offset by increased net earnings from Portland due to a
bankruptcy settlement received in 2006.
Excluding the gains on sale of PipeLines LP units in 2005 and the Millennium
Pipeline project (Millennium) in 2004, net earnings in 2005 were $13 million
lower than 2004. The decrease was primarily due to lower net earnings from Great
Lakes as a result of lower short-term revenues and higher operating and
maintenance costs, and lower earnings from PipeLines LP as a result of the
reduced ownership. Results were also negatively impacted by a weaker U.S. dollar
in 2005.
PIPELINES - OPPORTUNITIES AND DEVELOPMENTS
ANR and Great Lakes Acquisition
On February 22, 2007, TCPL closed its acquisition of ANR and an additional 3.55
per cent interest in Great Lakes from El Paso Corporation for approximately
US$3.4 billion, subject to certain post-closing adjustments, including
approximately US$488 million of assumed long-term debt. This transaction will
significantly expand the Company's continental natural gas pipeline and storage
operations.
ANR operates one of the largest interstate natural gas pipeline systems in the
U.S., providing transportation, storage, and various capacity-related services
to a variety of customers in both the U.S. and Canada. The system consists of
approximately 17,000 km of pipeline with a peak-day capacity of 6.8 Bcf/d. It
transports natural gas from producing fields in Louisiana, Oklahoma, Texas and
the Gulf of Mexico to markets in Wisconsin, Michigan, Illinois, Ohio and
Indiana. The pipeline system also connects with numerous other pipelines
providing customers with access to diverse sources of supply from western Canada
and the Rocky Mountain region and access to a variety of end-user markets in the
midwestern and northeastern U.S.
ANR also owns and operates numerous underground natural gas storage facilities
in Michigan with a total capacity of approximately 230 Bcf. Its facilities offer
customers a high level of service flexibility allowing them to meet peak-day
delivery requirements and to capture the value resulting from changing supply
and demand dynamics. As part of the acquisition, TCPL will also obtain certain
natural gas supplies contained within production and storage reservoirs in
Michigan.
Great Lakes
On February 22, 2007, PipeLines LP closed its acquisition of a 46.45 per cent
interest in Great Lakes from El Paso Corporation for approximately US$962
million subject to post-closing adjustments including approximately US$212
million of assumed long-term debt. Great Lakes owns and operates a 3,402 km
interstate natural gas pipeline
22 MANAGEMENT'S DISCUSSION AND ANALYSIS
system with a design capacity of 2.5 Bcf/d. TCPL is the general partner of and
holds a 32.1 per cent interest in PipeLines LP.
Canadian Mainline
In May 2006, TCPL filed for approval of two Canadian Mainline services designed
to meet the growing needs of natural gas-fired power generators in Ontario.
These services are designed to ensure that shippers can access transportation on
as little as 15 minutes notice so they can better match the timing of their
natural gas transportation needs with the timing of their power generation
requirements. The application was the subject of an oral public hearing in
September 2006 and, in December 2006, the NEB approved implementation of the
services with minor modifications.
In December 2006, TCPL applied to the NEB for approval of a new receipt point at
Gros Cacouna on the Canadian Mainline. The Company is also seeking affirmation
of the tolling methodology that will apply to service from that point. The new
receipt point would accommodate receipts of regassified LNG at Gros Cacouna,
bringing a new source of supply to the Canadian Mainline to serve markets in
eastern Canada and the U.S. Northeast. The NEB has established a procedure to
deal with the Gros Cacouna, Quebec receipt point application which includes an
oral hearing expected to begin in April 2007.
Alberta System
On February 21, 2006, the EUB issued its decision on the 2005 GRA Phase II. The
EUB approved the 2005 rate design as applied for. With this decision, TCPL was
able to finalize the 2005 and 2006 Alberta System tolls on March 14, 2006. The
2006 final tolls were effective April 1, 2006. TCPL had been charging interim
tolls since January 1, 2006 with the EUB's approval.
TCPL filed for a Review and Variance on the Ventures LP's Transportation by
Others (TBO) costs following the EUB decision on the 2004 GRA Phase I. At the
time, the EUB denied certain costs associated with the Ventures LP's new TBO
contract that was replacing the old TBO contract. In its decision on November
28, 2006, (Decision 2006-069), the EUB allowed for the recovery of approximately
$1 million of costs due to the timing of the termination and commencement of the
TBO contracts.
On November 30, 2006, the EUB finalized the 2007 generic ROE formula results.
For 2007, the Alberta System's ROE will be 8.51 per cent; down from 8.93 per
cent in 2006.
On December 20, 2006, the EUB approved TCPL's application to charge interim
tolls for transportation service, effective January 1, 2007. Final tolls for
2007 will be determined in first quarter 2007 upon updating of the flow-through
cost components of the revenue requirement to reflect actual costs and revenues
from the prior year.
GTN
In June 2006, TCPL filed a rate case with the FERC for its Gas Transmission
Northwest System. The rate case filing was primarily driven by decreased
revenues due to contract non-renewals and shipper defaults. The comprehensive
filing requested a number of tariff changes including an increase in rates for
transportation services that became effective January 1, 2007, subject to
refund. The proposed rates include an ROE of 14.5 per cent, a common equity
ratio of 62.99 per cent and a depreciation rate for the transmission plant of
2.76 per cent. The rates in effect prior to the January 2007 rate increase were
based on the last rate case filed in 1994.
In January 2007, TCPL received a procedural order from the FERC establishing a
timeline for the system's rate case proceeding. The hearing into this rate case
is scheduled to commence on October 31, 2007.
BC System and Foothills
TCPL filed applications with the NEB in early December 2005 for approval of 2006
tolls for Foothills and the BC System, reflecting an agreement with the Canadian
Association of Petroleum Producers (CAPP) and other stakeholders to increase the
deemed equity component of the capital structure of each system to 36 per cent
from 30 per cent. On December 21, 2005, the NEB approved Foothills' application
as filed. On February 22, 2006, the NEB finalized the BC System's 2006 tolls as
filed.
MANAGEMENT'S DISCUSSION AND ANALYSIS 23
In March 2006, TCPL initiated discussions with shippers on the BC System to
integrate the BC System with Foothills. The discussions culminated in a
settlement agreement (Integration Settlement) between Foothills and CAPP. The
Integration Settlement amended an existing settlement for Foothills and includes
a sharing mechanism for anticipated cost savings through increased
administrative efficiencies arising out of the integration of the two systems.
TCPL filed Foothills and BC System's integration application and related
approvals with the NEB on December 21, 2006. In February 2007, the NEB approved
the application as filed.
Tamazunchale
In December 2006, TCPL commenced commercial operations of the Tamazunchale
pipeline. The 36 inch, 130 km pipeline in central Mexico extends from the
facilities of Pemex Gas near Naranjos, Veracruz and transports natural gas under
a 26-year contract with the Comision Federal de Electricdad to an electricity
generation station near Tamazunchale, San Luis Potosi.
The pipeline is designed to transport initial volumes of 170 million cubic feet
per day (mmcf/d). Under the contract, the capacity of the Tamazunchale pipeline
is expected to be expanded, beginning in 2009, to approximately 430 mmcf/d to
meet the needs of two additional proposed power plants near Tamazunchale.
North Baja
On February 7, 2006, North Baja Pipelines LLC (North Baja) filed an application
with the FERC to expand and modify its existing system to facilitate the
importation of up to 2.7 Bcf/d of regassified LNG from Mexico into the
California and Arizona markets. Specifically, North Baja proposes to modify its
existing system to accommodate bi-directional natural gas flow, to construct a
new meter station and a 36 inch pipeline to interconnect with Southern
California Gas Company, to construct approximately 74 km of lateral facilities
to serve electric generation facilities, and to loop its entire approximately
129 km existing system with a combination of 42 inch and 48 inch diameter
pipeline. In addition to its FERC certificate of public convenience and
necessity, which includes a determination on environmental issues, the project
will need various permits and leases from the U.S. Bureau of Land Management,
the California State Lands Commission and other agencies. On October 6, 2006,
the FERC issued a preliminary determination approving all aspects of North
Baja's proposal other than those related to environmental issues, which will be
the subject of a future order.
Keystone Pipeline
In November 2005, TCPL, ConocoPhillips Company and ConocoPhillips Pipe Line
Company (CPPL) signed a Memorandum of Understanding which commits ConocoPhillips
Company to ship crude oil on the proposed Keystone Pipeline, and gives CPPL the
right to acquire up to a 50 per cent ownership interest in the pipeline. On
January 31, 2006, TCPL announced it has secured firm, long-term contracts
totalling 340,000 barrels per day with durations averaging 18 years. The
commitments were obtained through the successful completion of a binding Open
Season held during fourth quarter 2005. With these commitments from shippers,
TCPL proceeded with regulatory filings for approval of the project.
At an estimated cost of approximately US$2.1 billion, the Keystone Pipeline is
intended to transport approximately 435,000 barrels per day of crude oil from
Hardisty, Alberta, to Patoka, Illinois through a 2,960 km pipeline system. The
pipeline can be expanded to 590,000 barrels per day with additional pump
stations. In addition to approximately 1,730 km of new pipeline construction in
the U.S., the Canadian portion of the proposed project includes the construction
of approximately 370 km of new pipeline and the conversion of approximately 860
km of TCPL's existing pipeline facilities from natural gas to crude oil
transmission. At December 31, 2006, the Company had capitalized $39 million
related to Keystone.
In 2006, TCPL and TCPL's wholly owned subsidiary, TransCanada Keystone Pipeline
GP Ltd. (Keystone), filed two regulatory applications with the NEB for the
Canadian leg of the Keystone Pipeline. In June 2006, TCPL filed the first
application with the NEB seeking approval to transfer a portion of its Canadian
Mainline natural gas transmission facilities to Keystone for use as part of the
Keystone Pipeline. As part of the transfer application, TCPL sought approval to
reduce the Canadian Mainline's rate base by the NBV of the transferred
facilities and to add the NBV of these facilities to the Keystone Pipeline rate
base. Public hearings on the transfer application were completed in mid-November
2006. Approval was received from the NEB in February 2007.
24 MANAGEMENT'S DISCUSSION AND ANALYSIS
In the second application, TCPL sought approval to construct and operate new
facilities in Canada including approximately 370 km of new oil pipeline,
terminal facilities at Hardisty, Alberta and required pump stations. TCPL is
also seeking approval of the tolls and tariff for the pipeline. A decision on
this application is anticipated from the NEB in fourth quarter 2007.
In April 2006, TCPL filed an application with the U.S. Department of State for a
Presidential Permit authorizing the construction, operation and maintenance of
the U.S. portion of the Keystone Pipeline. In September 2006, the Department of
State issued a formal notice of the application as well as a Notice of Intent to
prepare an Environmental Impact Statement for the project.
In June 2006, TCPL filed a petition with the Illinois Commerce Commission for a
certificate authorizing the pipeline and granting authority to exercise eminent
domain. The matter is expected to go to hearing in March 2007.
Shippers have also expressed interest in a proposed extension of the Keystone
Pipeline to Cushing, Oklahoma. Through an Open Season, which will close at the
end of first quarter 2007, binding commitments are being solicited to support
the Cushing Extension, which would expand the Keystone Pipeline from a capacity
of approximately 435,000 barrels per day to 590,000 barrels per day, and see the
construction of a 468 km, 36 inch extension of the U.S. portion of the pipeline
to Cushing. The expansion and extension would enable Keystone to provide access
for increasing western Canadian crude supply to two key markets and
transportation hubs at Patoka and Cushing. The expected capital cost is US$700
million and the targeted in-service date is fourth quarter 2010.
The Heartland extension is a proposed 190 km pipeline from Hardisty which would
connect Keystone to the Fort Saskatchewan area. This extension would increase
the Keystone Pipeline's market supply reach and provide incremental
transportation service between Alberta's two major crude oil centres. The
expected capital cost is approximately US$300 million. Discussions are under way
with shippers to gauge the level of interest with an anticipation of moving
forward with commercial arrangements later in 2007. The targeted in-service date
of the Heartland extension is 2010/2011.
TCPL is in the business of connecting energy supplies to markets and it views
the Keystone opportunity as another way of providing a valuable service to its
customers. Converting one of the Company's natural gas pipeline assets for oil
transportation is an innovative, cost-competitive way to meet the need for
pipeline expansions to accommodate anticipated growth in Canadian crude oil
production during the next decade.
Mackenzie Gas Pipeline Project
The MGP is a 1,200 km natural gas pipeline proposed to be constructed from near
Inuvik, Northwest Territories to the northern border of Alberta, where it would
then connect to the Alberta System. In June 2006, TCPL submitted an application
to the EUB for approval of the Dickins-Vardie facilities, a $212-million capital
project required to provide the Alberta System interconnection facilities for
Mackenzie gas volumes.
Throughout 2006, the MGP proponents participated in public hearings convened by
the NEB and by a Joint Review Panel (JRP) constituted to assess socio-economic
and environmental aspects of the project. These latter hearings are expected to
conclude in second quarter 2007, with the JRP's report ultimately being
submitted into the NEB review process. Concurrently, the project proponents have
been reassessing the capital cost estimate and construction schedule for the
MGP, in light of overall industry cost escalations and labour shortages. A
revised capital estimate for the project is expected to be filed with the NEB in
first quarter 2007.
Apart from the Alberta System interconnection facilities, TCPL's involvement
with the MGP is derived from a 2003 agreement with the APG and the MGP by which
TCPL agreed to finance the APG's one-third share of the pipeline's
pre-development costs associated with the project. These costs are currently
forecasted to be approximately $145 million by the end of 2007. Cumulative
advances made by TCPL in this respect totalled $118 million at December 31, 2006
and are included in Other Assets. These amounts constitute a loan to the APG,
which becomes repayable only after the date upon which the pipeline commences
commercial operations. The total amount of the loan is expected to ultimately
form part of the rate base of the pipeline, and the loan will subsequently be
repaid from the
MANAGEMENT'S DISCUSSION AND ANALYSIS 25
APG's share of available future pipeline revenues or from alternate financing.
If the project does not proceed, TCPL has no recourse against the APG for
recovery of advances made. Accordingly, the recovery of the advances is
dependent upon a successful outcome of the project.
Under the terms of certain MGP agreements, TCPL holds an option to acquire up to
five per cent equity ownership in the pipeline at the time of the decision to
construct. In addition, TCPL gains certain rights of first refusal to acquire 50
per cent of any divestitures by existing partners and an entitlement to obtain
a one-third interest in all expansion opportunities once the APG reaches a
one-third ownership share, with the other pipeline owners and the APG sharing
the balance.
Alaska Highway Pipeline Project
In 2006, TCPL continued its discussions with Alaska North Slope producers and
the State of Alaska regarding the Alaskan portion of the proposed Alaska Highway
Pipeline Project. In early 2006, Alaska's State administration reached a
preliminary agreement with ConocoPhillips Alaska Inc., BP Exploration (Alaska)
Inc. and ExxonMobil Alaska Production Inc. for the pipeline project. However,
the State Legislature did not ratify that agreement. Alaska's new Governor,
elected in November 2006, has indicated the new administration intends to
introduce a different process for the pipeline project in 2007.
Foothills Pipe Lines Ltd. (Foothills) holds the priority right to build, own and
operate the first pipeline through Canada for the transportation of Alaskan gas.
This right was granted under the Northern Pipeline Act of Canada (NPA),
following a lengthy competitive hearing before the NEB in the late 1970s, which
resulted in a decision in favour of Foothills. The NPA creates a single window
regulatory regime that is uniquely available to Foothills. It has been used by
Foothills to construct facilities in Alberta, B.C. and Saskatchewan, which
constitute a prebuild for the Alaska Highway Pipeline Project, and to expand
those facilities five times, the latest of which was in 1998. Continued
development under the NPA should ensure the earliest in-service date for the
project.
Western Supply and Markets
The primary driver for infrastructure projects for the Alberta System is the
development of natural gas supply and market demand in the various regions
served by the Alberta System. In 2006, natural gas prices were lower than in
2005 which resulted in some slowdown in natural gas drilling activity levels.
Nevertheless, activity remains strong which has resulted in supply growth in
some regions of western Canada and an increased requirement for new transmission
infrastructure. The primary source of supply growth has been deeper conventional
drilling in western Alberta, northeastern B.C. and coalbed methane development
in central Alberta.
TCPL will continue to focus on the cost effective and timely connection of new
gas production volumes so that customers can promptly access markets. As well,
service flexibility will continue to be a focus to ensure TCPL remains
competitive.
TCPL received approval from the EUB in April 2006 to construct new natural gas
transmission facilities to serve the firm intra-Alberta delivery contract
requirements of oil sand developers in the Fort McKay area. These facilities
include 127 km of pipeline and three metering facilities at an estimated capital
cost of $125 million. In addition to the proposed Fort McKay facilities, TCPL
constructed additional metering facilities to serve approximately 200 mmcf/d of
firm intra-Alberta delivery contracts.
Eastern Supply and Markets
Historically, TCPL's eastern pipeline system has been supplied by long-haul
flows from western Canada and by volumes received from storage fields and
interconnecting pipelines in southwestern Ontario. In the future, the eastern
pipeline system may also be supplied by LNG deliveries from proposed
regassification facilities in Quebec and the northeastern U.S.
Power generation continues to be the primary driver for incremental gas demand
in eastern Canada and the northeastern U.S. Power projects that require
significant volumes of natural gas continue to be developed, supporting
utilization of the eastern pipeline system. Aligned with these power project
developments, TCPL received NEB approval
26 MANAGEMENT'S DISCUSSION AND ANALYSIS
in 2006 for two new services targeted at attracting incremental demand for
natural gas transportation on the Canadian Mainline system.
In addition, TCPL completed construction of three NEB-approved facilities on its
Canadian Mainline system in 2006. This included the Stittsville and Deux
Rivieres loops of approximately 38 km of 42 inch pipe with a capital cost of
approximately $113 million, and the Les Cedres loop of approximately 21 km of 36
inch pipe with a capital cost of $56 million.
PIPELINES - BUSINESS RISKS
Competition
TCPL faces competition at both the supply end and the market end of its systems.
The competition is a result of other pipelines accessing the increasingly mature
WCSB as well as markets served by TCPL's pipelines. In addition, the continued
expiration of long-term firm transportation (FT) contracts has resulted in
significant reductions in long-term firm contracted capacity on the Canadian
Mainline, the Alberta System, the BC System and the Gas Transmission Northwest
System, and shifts to short-term firm contracts.
TCPL's primary source of natural gas supply is the WCSB. As of December 2005,
the WCSB had remaining discovered natural gas reserves of approximately 57
trillion cubic feet and a reserves-to-production ratio of approximately nine
years at current levels of production. Historically, additional reserves have
continually been discovered to maintain the reserves-to-production ratio at
close to nine years. Natural gas prices in the future are expected to be higher
than long-term historical averages due to a tighter supply/demand balance, which
should stimulate exploration and production in the WCSB. However, the WCSB's
natural gas supply is expected to remain essentially flat. With the expansion of
capacity on TCPL's wholly and partially owned pipelines over the past decade and
the competition provided by other pipelines combined with significant growth in
natural gas demand in Alberta, TCPL anticipates there will be excess pipeline
capacity out of the WCSB for the foreseeable future.
TCPL's Alberta System is the major natural gas gathering and transportation
system for the WCSB, connecting most of the natural gas processing plants in
Alberta to domestic and export markets. The Alberta System has faced, and will
continue to face, increasing competition from other pipelines. An emerging
competitive issue for the Alberta System is the existence and access to natural
gas liquids (NGLs) contained in the gas that is transported by the pipeline. The
current extraction convention in Alberta allocates a heat content value to the
receipt point shippers at the overall Alberta System average gas composition.
This averaging is becoming a significant issue for northern gas producers whose
gas is generally rich in NGL content as they seek to extract the full value of
the NGLs. Alberta's petrochemical industry is also very interested in the issue
as it relies on NGLs as their feedstock. The EUB is aware of the current
extraction convention inequities and has indicated that they will commission a
process to address these concerns.
The Canadian Mainline is TCPL's cross-continental natural gas pipeline serving
midwestern and eastern markets in Canada and the U.S. The demand for natural gas
in TCPL's key eastern markets is expected to continue to increase, particularly
to meet the expected growth in natural gas-fired power generation. Although
there are opportunities to increase market share in Canadian and U.S. export
markets, TCPL faces significant competition in these regions. Consumers in the
northeastern U.S. generally have access to an array of pipeline and supply
options. Eastern Canadian markets that historically received Canadian supplies
only from TCPL are now capable of receiving supplies from new pipelines into the
region that can source western and Atlantic Canadian, and U.S. supplies.
Over the last few years, the Canadian Mainline has experienced reductions in
long-haul FT contracts. This has been partially offset by increases in
short-haul contracts. While decreases in throughput do not directly impact the
Canadian Mainline earnings, such decreases will impact the competitiveness of
its tolls. Over the course of 2005 and into early 2006, strong prices in eastern
Canada and the northeastern U.S. resulted in higher than anticipated flows on
the Canadian Mainline. Moderating prices in these markets in the latter part of
2006 have reduced flows toward expected
MANAGEMENT'S DISCUSSION AND ANALYSIS 27
levels. Looking forward, in the short to medium term, there is limited
opportunity to further reduce per unit tolls by increasing long-haul volumes on
the Canadian Mainline.
The Gas Transmission Northwest System must compete with other pipelines to
access natural gas supplies as well as to access markets. Transportation service
capacity on the Gas Transmission Northwest System provides customers with access
to supplies of natural gas primarily from the WCSB and serves markets in the
Pacific Northwest, California and Nevada. These three markets may also access
supplies from other competing basins in addition to supplies from the WCSB.
Historically, natural gas supplies from the WCSB have been competitively priced
in relation to natural gas supplies from the other supply regions serving these
markets. The Gas Transmission Northwest System experienced significant contract
non-renewals in 2005 and 2006 as natural gas transported from the WCSB on the
Gas Transmission Northwest System competes for the California and Nevada markets
against supplies from the Rocky Mountain and southwestern U.S. supply basins. In
the Pacific Northwest market, natural gas transported on the Gas Transmission
Northwest System competes against the Rocky Mountain natural gas supply as well
as additional western Canadian supply transported by other pipelines.
In October 2006, the Gas Transmission Northwest System's largest customer,
Pacific Gas & Electric Company (PG&E), extended its contract to October 31,
2008. In 2006, PG&E accounted for approximately 22 per cent of the Gas
Transmission Northwest System's revenue. By October 31, 2007, PG&E will inform
TCPL whether it elects to either extend the contract beyond November 2008,
utilize the contract's right of first refusal process or terminate the contract.
Transportation service on North Baja provides access to natural gas supplies
primarily from both the Permian Basin, located in western Texas and southeastern
New Mexico, and the San Juan Basin, primarily located in northwestern New Mexico
and Colorado. North Baja delivers gas to the Gasoducto Bajanorte Pipeline at the
California/Mexico border, which transports the gas to markets in northern Baja
California, Mexico. While there are currently no direct competitors to deliver
natural gas to North Baja's downstream markets, the pipeline may compete with
fuel oil, which is an alternative to natural gas in the operation of some
electric generation plants in the North Baja region.
Counterparty Risk
The risk of counterparty default is always present. In December 2005, Calpine
Corporation and certain of its subsidiaries (Calpine) filed for bankruptcy
protection in both Canada and the U.S. Calpine repudiated its transportation
contracts on certain of TCPL's Canadian pipelines effective January 1, 2007 as
allowed under a Companies' Creditors Arrangement Act Order. Given that TCPL
considers itself prudent in having obtained the maximum financial assurances
allowable under the respective Canadian tariffs, TCPL will make an application
to the regulator for recovery under the current regulatory model for any lost
revenue, net of assurances and any revenues from the defaulted capacity. Should
Calpine be successful in rejecting its contracts on certain of TCPL's U.S.
pipelines, the unmitigated annual after-tax exposure of the contract obligations
is estimated at $10 million for the Gas Transmission Northwest System.
Mitigating factors exist which may reduce this exposure including recontracting
the capacity where possible and recovery from bankruptcy proceedings. The
potential impact of such mitigating factors and the resulting net exposure are
unknown at this time.
Regulatory Financial Risk
Regulatory decisions continue to have a significant impact on the financial
returns for existing and future investments in TCPL's Canadian wholly owned
pipelines. TCPL remains concerned that the approved financial returns fail to be
competitive with returns from assets of similar risk and will discourage
additional investment in existing Canadian natural gas transmission systems. In
recent years, TCPL applied for an ROE of 11 per cent on 40 per cent deemed
common equity for both the Canadian Mainline and the Alberta System to the NEB
and the EUB, respectively. The outcome of these proceedings resulted in the
Canadian Mainline's current 36 per cent deemed equity thickness and the Alberta
System's 35 per cent deemed equity thickness. Additionally, the NEB reaffirmed
its ROE formula, while the EUB set a generic ROE which largely aligns with the
NEB's formula. In 2006, the NEB's ROE formula declined to 8.88 per cent from the
2005 ROE of 9.46 per cent and the EUB's generic ROE declined to 8.93 per cent
from 9.50 per cent in 2005. In 2007, the Canadian Mainline and the Alberta
System's ROEs continued to decline, dropping to 8.46 percent and 8.51 per cent,
respectively.
28 MANAGEMENT'S DISCUSSION AND ANALYSIS
Throughput Risk
As transportation contracts expire on TCPL's U.S. pipeline investments, these
pipelines will be more exposed to throughput risk and their revenues are more
likely to experience increased variability. Throughput risk is created by supply
and market competition, gas basin pricing, economic activity, weather
variability, pipeline competition and pricing of alternative fuels.
PIPELINES - OTHER
Safety
TCPL worked closely with regulators, customers and communities during 2006 to
ensure the continued safety of employees and the public. In 2006, TCPL
experienced two small diameter pipeline line-breaks located in remote areas of
northern Alberta. The breaks released sweet natural gas and resulted in minimal
impact with no injuries or property damage. Under the approved regulatory models
in Canada, expenditures for pipeline integrity on the NEB and the EUB regulated
pipelines are treated on a flow-through basis and, as a result, have no impact
on TCPL's earnings. The Company expects to spend approximately $100 million in
2007 for pipeline integrity on its wholly owned pipelines, which approximates
the amount spent in 2006. TCPL continues to use a rigorous risk management
system that focuses spending on issues and areas that have the largest impact on
maintaining or improving the reliability and safety of the pipeline system. TCPL
utilizes a comprehensive management system of policies, programs and procedures
to ensure the occupational safety of employees and contractors.
Environment
In 2006, TCPL continued to address environmental issues associated with its
historical operations through proactive environmental monitoring, sampling and
site remediation programs. Environmental site assessments were completed on the
assets of the BC System, the Alberta System and the Canadian Mainline. The
building containment integrity improvement program also continued at compressor
station sites across the Canadian Mainline. Additionally, the demolition and
clean up of four mainline compressor plants was carried out in 2006. TCPL will
continue to actively invest in improving its environmental protection practices
in 2007 and the future.
For information on management of risks with respect to the Pipelines business,
refer to the "Risks and Risk Management" section of this MD&A.
PIPELINES - OUTLOOK
As demand for natural gas continues to grow across North America, TCPL's
Pipelines business will continue to play a critical role in the reliable
transportation of natural gas. For 2007, the business will continue to focus on
the reliable delivery of natural gas to growing markets, connecting new supply,
progressing development of new infrastructure to connect natural gas from the
north, LNG in the east, and development of the Keystone Pipeline.
It is expected that producers will continue to explore and develop new fields,
particularly in northeastern B.C. and the west central foothills regions of
Alberta. There will also be significant activity aimed at unconventional
resources such as coalbed methane although activity is expected to decline from
last year's level. New facilities will be required to move this incremental
supply from the location of the resource. New customer requests to serve markets
in eastern Canada and the U.S. will require expansion of certain facilities on
the Canadian Mainline for 2007 and 2008. This will include the addition of 18 MW
of compression and a 7 km looping project. The estimated capital cost for these
projects is $63 million.
It is expected that incremental supply from LNG will serve growing North
American markets in the mid to long term. As a result, TCPL will take prudent
steps to further understand the potential commercial and operational
implications of connecting LNG facilities to those systems affected.
MANAGEMENT'S DISCUSSION AND ANALYSIS 29
TCPL will continue to focus on operational excellence and collaborative efforts
with all stakeholders on negotiated settlements and service options that will
increase the value of TCPL's business to customers and shareholders.
Earnings
With the closing of the acquisition of ANR and Great Lakes, and the Company's
increased ownership in PipeLines LP, TCPL expects higher net earnings from
Pipelines in 2007 compared to 2006. TCPL's earnings from its Canadian Wholly
Owned Pipelines are primarily determined by the average investment base, ROE,
deemed common equity and opportunity for incentive earnings. In the short to
medium term, the Company expects a modest level of investment in these mature
assets and, therefore, anticipates a continued net decline in the average
investment base due to depreciation. Accordingly, without an increase in ROE,
deemed common equity or incentive opportunities, future earnings from the
Canadian Wholly Owned Pipelines are anticipated to decrease. However, these
mature assets will continue to generate strong cash flows that can be redeployed
to other projects offering higher returns. Under the current regulatory model,
earnings from the Canadian Wholly Owned Pipelines are not affected by short-term
fluctuations in the commodity price of natural gas, changes in throughput
volumes or changes in contract levels. In addition, the Tamazunchale pipeline
will provide an increase in 2007 earnings as a result of its first full year of
operations.
In November 2006, the NEB established the 2007 ROE for the Canadian Mainline at
8.46 per cent compared to 8.88 per cent in 2006. In addition, the 2007 average
investment base is expected to continue to decline. These two factors are
expected to lower earnings on the Canadian Mainline in 2007, relative to 2006,
barring any offsetting factors.
Alberta System's earnings will be negatively influenced in 2007 by the decrease
in the EUB's generic ROE to 8.51 per cent in 2007 from 8.93 per cent in 2006,
and the anticipated decrease in the average investment base. The three-year
revenue requirement settlement reached in 2005 does provide the opportunity for
limited incentive earnings as the settlement contains some at-risk components.
There is a possibility that the at-risk OM&A cost components of the settlement
will have a negative impact on the Alberta System's earnings in 2007.
In 2007, reduced firm contract volumes on the Gas Transmission Northwest System,
partially due to the bankruptcy of Calpine, are expected to have a negative
impact on the Gas Transmission Northwest System's earnings compared to 2006. It
is uncertain what impact the rate case proceeding may have on the system's
financial results. Net earnings, excluding gains, from Other Pipelines are
expected to be relatively consistent with 2006.
Capital Expenditures
Total capital spending for the Wholly Owned Pipelines during 2006 was $434
million. Overall capital spending for the Wholly Owned Pipelines in 2007 is
expected to be approximately $400 million, excluding any capital expenditures of
ANR.
30 MANAGEMENT'S DISCUSSION AND ANALYSIS
NATURAL GAS THROUGHPUT VOLUMES
(Bcf)
2006 2005 2004
Canadian Mainline(1) 2,955 2,997 2,621
Alberta System(2) 4,051 3,999 3,909
Gas Transmission Northwest System(3) 790 777 181
Foothills 1,051 1,051 1,139
BC System 351 321 360
North Baja(3) 95 84 13
Great Lakes 816 850 801
Northern Border 799 808 845
Iroquois 384 394 356
TQM 158 166 159
Ventures LP 179 138 136
Portland 52 62 50
Tuscarora 28 25 25
Gas Pacifico 52 34 28
TransGas 22 19 18
Tamazunchale(4) - - -
(1)
Canadian Mainline deliveries originating at the Alberta border and in
Saskatchewan in 2006 were 2,224 Bcf (2005 - 2,215 Bcf; 2004 - 2,017 Bcf).
(2)
Field receipt volumes for the Alberta System in 2006 were 4,160 Bcf (2005 -
4,034 Bcf; 2004 - 3,952 Bcf).
(3)
TCPL acquired GTN on November 1, 2004. The delivery volumes for 2004
represent November and December 2004 throughput for GTN.
(4)
The Tamazunchale pipeline went into service December 1, 2006.
MANAGEMENT'S DISCUSSION AND ANALYSIS 31
,G39651.JPG
BEAR CREEK An 80 MW natural gas-fired cogeneration plant located near Grande
Prairie, Alberta
MACKAY RIVER A 165 MW natural gas-fired cogeneration plant located near Fort
McMurray, Alberta.
REDWATER A 40 MW natural gas-fired cogeneration plant located near Redwater,
Alberta.
SUNDANCE A&B The Sundance power facility in Alberta is the largest coal-fired
electrical generating facility in Western Canada. TCPL owns the 560 MW Sundance
A PPA, which expires in 2017. TCPL effectively owns 50 per cent of the 706 MW
Sundance B PPA, which expires in 2020.
SHEERNESS The Sheerness plant consists of two 390 MW coal-fired thermal power
generating units. TCPL owns the 756 MW Sheerness PPA, which expires in 2020.
CARSELAND An 80 MW natural gas-fired cogeneration plant located near
Carseland, Alberta.
32 MANAGEMENT'S DISCUSSION AND ANALYSIS
CANCARB The 27 MW Cancarb facility at Medicine Hat, Alberta is fuelled by
waste heat from TCPL's adjacent thermal carbon black facility.
BRUCE POWER TCPL owns 31.6 per cent of Bruce B, consisting of operating Units
5 to 8 with approximately 3,200 MW of generating capacity. In addition, TCPL
owns 48.7 per cent of Bruce A, consisting of operating Units 3 and 4 with
approximately 1,500 MW of generating capacity and currently idle Units 1 and 2
with approximately 1,500 MW of generating capacity, which are currently being
refurbished and are expected to restart in late 2009 or early 2010.
HALTON HILLS The 683 MW natural gas-fired power plant near the town of Halton
Hills, Ontario is under development and is expected to be placed in service in
second quarter 2010.
PORTLANDS ENERGY The 550 MW high efficiency, combined cycle natural gas
generation power plant located in downtown Toronto is 50 percent owned by TCPL
and is under construction. The plant is expected to be operational in
simple-cycle mode, delivering 340 MW of electricity to the City of Toronto
beginning June 2008. It is anticipated to be fully commissioned in its full
combined-cycle mode, delivering 550 MW of power in second quarter 2009.
BECANCOUR Construction of the 550 MW Becancour natural gas-fired cogeneration
power plant located near Trois-Rivieres, Quebec was completed and the plant
placed into service in September 2006. The entire power output will be supplied
to Hydro-Quebec under a 20-year power purchase contract. Steam is also sold to
industrial customers for use in commercial processes.
CARTIER WIND Construction of the 740 MW Cartier Wind project, 62 per cent
owned by TCPL, continued in 2006. The first of six wind projects,
Baie-des-Sables, with a generation capacity of 110 MW, was placed into service
in November 2006. Planning and construction on the remaining five projects will
continue, subject to future appropriations and approvals.
GRANDVIEW A 90 MW natural gas-fired cogeneration power plant located in Saint
John, New Brunswick was commissioned and placed into service in January 2005.
Under a 20-year tolling arrangement, 100 per cent of the plant's heat and
electricity output is sold to Irving Oil.
TC HYDRO TCPL's hydroelectric facilities on the Connecticut and Deerfield
Rivers consist of 13 stations and associated dams and reservoirs with a total
generating capacity of 567 MW and are located in New Hampshire, Vermont and
Massachusetts.
OSP The OSP plant is a 560 MW natural gas-fired, combined-cycle facility in
Rhode Island.
EDSON Edson is an underground natural gas storage facility connected to the
Alberta System located near Edson, Alberta. The central processing system is
capable of maximum injection and withdrawal rates of 725 mmcf/d of natural gas.
Edson has a working natural gas storage capacity of approximately 50 Bcf.
Construction of the Edson facility was substantially completed in third quarter
2006 and the facility was placed into service on December 31, 2006.
CROSSALTA CrossAlta is an underground natural gas storage facility connected
to the Alberta System and is located near Crossfield, Alberta. CrossAlta has a
working natural gas capacity of 50 Bcf with a maximum deliverability capability
of 400 mmcf/d. TCPL holds a 60 per cent ownership in CrossAlta.
CACOUNA Cacouna, a joint venture with Petro-Canada, is a proposed LNG project
in Quebec at Gros Cacouna harbour on the St. Lawrence River, capable of
receiving, storing and regassifying imported LNG with an average send-out
capacity of approximately 500 mmcf/d of natural gas.
BROADWATER Broadwater, a joint venture with Shell US Gas & Power LLC, is a
proposed LNG project located offshore of New York State in Long Island Sound,
capable of receiving, storing and regassifying imported LNG with an average
send-out capacity of approximately 1 Bcf/d of natural gas.
MANAGEMENT'S DISCUSSION AND ANALYSIS 33
HIGHLIGHTS
Net Earnings
*
Energy's net earnings in 2006 were $452 million compared to $566 million
in 2005.
*
Excluding gains related to Power LP and Paiton Energy in 2005, Energy's
net earnings in 2006 increased $194 million to $452 million compared to
$258 million in 2005, primarily due to increased operating income from
Western Power Operations.
Expanding Asset Base
*
At December 31, 2006, approximately 2,100 MW of new power plants were
under construction, with an anticipated total capital cost of more than
$3.2 billion.
*
Since 1999, TCPL's Power business has grown its nominal generating
capacity by approximately 5,200 MW (including 2,100 MW under
construction), representing an investment of more than $4 billion to the
end of 2006. TCPL has committed an additional $1.9 billion to complete
the assets under construction.
Power
*
In September 2006, the Becancour cogeneration plant was commissioned and
placed into service.
*
Construction on the Portlands Energy project commenced in September
2006.
*
In November 2006, construction on the Baie-des-Sables Cartier Wind
project was completed and placed into service.
*
In November 2006, TCPL was awarded a contract to build, own and operate
a natural gas-fired power plant near the town of Halton Hills, Ontario.
*
In 2006, construction continued on the Bruce A restart and refurbishment
project, which includes restart of the currently idle Units 1 and 2, and
replacement of the steam generators on Unit 4.
*
2006 included the first full year of earnings from the Sheerness PPA,
acquired in December 2005 from the Alberta Balancing Pool.
Natural Gas Storage
*
Construction of the Edson natural gas storage facility was substantially
completed in third quarter 2006 and was placed into service on December
31, 2006.
Plant Availability
*
Weighted average power plant availability was 93 per cent in 2006,
excluding Bruce Power, compared to 87 per cent in 2005.
*
Including Bruce Power, weighted average power plant availability was 91
per cent in 2006, compared to 84 per cent in 2005.
34 MANAGEMENT'S DISCUSSION AND ANALYSIS
ENERGY RESULTS-AT-A-GLANCE
Year ended December 31 (millions of dollars)
2006 2005 2004
Bruce Power 235 195 130
Western Power Operations 297 123 138
Eastern Power Operations 187 137 108
Natural Gas Storage 93 32 27
Power LP Investment - 29 29
General, administrative, support costs and other (144 ) (129 ) (127 )
Operating income 668 387 305
Financial charges (23 ) (11 ) (13 )
Interest income and other 5 5 14
Income taxes (198 ) (123 ) (95 )
452 258 211
Gain on sale of Paiton Energy - 115 -
Gains related to Power LP - 193 187
Net earnings 452 566 398
,G652090.JPG Energy's net earnings in 2006 were $452 million compared to $566 million in
2005. In 2005, TCPL sold its approximate 11 per cent interest in Paiton
Energy to subsidiaries of the Tokyo Electric Power Company for gross
proceeds of US$103 million ($122 million) resulting in an after-tax gain of
$115 million. In August 2005, TCPL sold its ownership interest in Power LP
to EPCOR Utilities Inc. (EPCOR) for net proceeds of $523 million resulting
in an after-tax gain of $193 million.
Excluding the Paiton Energy and Power LP-related gains in 2005, Energy's
net earnings in 2006 of $452 million increased $194 million compared to
$258 million in 2005. The increase was primarily due to higher
contributions from each of its
existing businesses and a $23-million favourable impact on future income taxes arising from reductions in Canadian
federal and provincial corporate income tax rates enacted in 2006. Partially offsetting these increases was the loss of
operating income associated with the sale of the Power LP interest in 2005 and reduced earnings in 2006 due to the
effect of a weaker U.S. dollar on earnings from Energy's U.S. operations.
Included in 2004 net earnings was an after-tax gain of $187 million comprising a
$15-million after-tax gain on the sale of TCPL's Curtis Palmer and ManChief
power facilities to Power LP as well as $172 million of after-tax dilution
gains.
Excluding the gain on the sale of Paiton Energy in 2005 and Power LP-related
gains in 2005 and 2004, Energy's net earnings for the year ended December 31,
2005 of $258 million increased $47 million compared to $211 million in 2004. The
increase was primarily due to higher operating income from Bruce Power and
Eastern Power Operations, partially offset by a reduced contribution from
Western Power Operations and lower interest income and other.
MANAGEMENT'S DISCUSSION AND ANALYSIS 35
POWER PLANTS - NOMINAL GENERATING CAPACITY AND FUEL TYPE
MW Fuel Type
Bruce Power(1) 2,474 Nuclear
Western Power Operations
Sheerness(2) 756 Coal
Sundance A(3) 560 Coal
Sundance B(3) 353 Coal
MacKay River 165 Natural gas
Carseland 80 Natural gas
Bear Creek 80 Natural gas
Redwater 40 Natural gas
Cancarb 27 Natural gas
2,061
Eastern Power Operations
Halton Hills(4) 683 Natural gas
TC Hydro(5) 567 Hydro
OSP 560 Natural gas
Becancour(6) 550 Natural gas
Cartier Wind(7) 458 Wind
Portlands Energy(8) 275 Natural gas
Grandview(9) 90 Natural gas
3,183
Total Nominal Generating Capacity 7,718
(1)
Represents TCPL's 48.7 per cent proportionate interest in Bruce A and 31.6
per cent proportionate interest in Bruce B. Bruce A consists of four 750 MW
reactors. Bruce A Unit 3 was returned to service in first quarter 2004.
Bruce A Units 1 and 2 are currently being refurbished and are expected to
restart in late 2009 or early 2010. Bruce B consists of four reactors which
are currently in operation, with a combined capacity of approximately 3,200
MW.
(2)
TCPL directly acquires 756 MW from Sheerness through a long-term PPA.
(3)
TCPL directly or indirectly acquires 560 MW from Sundance A and 353 MW from
Sundance B through long-term PPAs, which represents 100 per cent of the
Sundance A and 50 per cent of the Sundance B power plant output,
respectively.
(4)
Currently in development.
(5)
Acquired in second quarter 2005.
(6)
Placed in service in third quarter 2006.
(7)
First of six wind farms placed in service in fourth quarter 2006. Represents
TCPL's 62 per cent share of the total 740 MW project.
(8)
Currently under construction. Represents TCPL's 50 per cent share of this
550 MW facility.
(9)
Placed in service in first quarter 2005.
ENERGY - FINANCIAL ANALYSIS
Bruce Power
On October 31, 2005, Bruce Power and the OPA completed a long-term agreement
whereby Bruce A will restart and refurbish the currently idle Units 1 and 2,
extend the operating life of Unit 3 by replacing its steam generators and fuel
channels when required and replace the steam generators on Unit 4. As a result
of an agreement between Bruce Power and the OPA, and Cameco Corporation's
(Cameco) decision not to participate in the restart and refurbishment program,
the Bruce A partnership was formed by TCPL and BPC Generation Infrastructure
Trust (BPC), with each owning a
36 MANAGEMENT'S DISCUSSION AND ANALYSIS
48.7 per cent (2005 - 47.9 per cent) interest in Bruce A at December 31, 2006.
TCPL and BPC each incurred a net cash outlay of approximately $100 million in
2005 to acquire Cameco's interest. The remaining 2.6 per cent is owned by the
Power Worker's Union Trust No. 1 and The Society of Energy Professionals Trust.
The Bruce A partnership subleases the Bruce A facilities, which comprises Units
1 to 4, from Bruce B. TCPL continues to own 31.6 per cent of Bruce B, which
consists of Units 5 to 8.
Upon reorganization, both Bruce A and Bruce B became jointly controlled entities
and TCPL proportionately consolidated these investments on a prospective basis
from October 31, 2005. The following Bruce Power financial results reflect the
operations of the full six-unit operation for all periods.
Bruce Power Results-at-a-Glance(1)
Year ended December 31 (millions of dollars)
2006 2005 2004
Bruce Power (100 per cent basis)
Revenues
Power 1,861 1,907 1,563
Other(2) 71 35 20
1,932 1,942 1,583
Operating expenses
Operations and maintenance (912 ) (871 ) (793 )
Fuel (96 ) (77 ) (68 )
Supplemental rent (170 ) (164 ) (156 )
Depreciation and amortization (134 ) (198 ) (161 )
(1,312 ) (1,310 ) (1,178 )
Revenues, net of operating expenses 620 632 405
Financial charges under equity accounting(3) - (58 ) (67 )
620 574 338
TCPL's proportionate share 228 188 107
Adjustments 7 7 23
TCPL's operating income from Bruce Power(3) 235 195 130
Bruce Power - Other Information
Plant availability 88% 80% 82%
Sales volumes (GWh)(4)
Bruce Power - 100 per cent 36,470 32,900 33,600
TCPL's proportionate share 13,317 10,732 10,608
Results per MWh(5)
Bruce A revenues $58
Bruce B revenues $48
Combined Bruce Power revenues $51 $58 $47
Combined Bruce Power fuel $3 $2 $2
Combined Bruce Power total operating expenses(6) $35 $40 $35
Percentage of output sold to spot market 35% 49% 52%
(1)
All information in this table includes adjustments to eliminate the effects
of inter-partnership transactions between Bruce A and Bruce B.
(2)
Includes fuel cost recoveries for Bruce A of $30 million for 2006 ($4
million from November 1 to December 31, 2005).
MANAGEMENT'S DISCUSSION AND ANALYSIS 37
(3)
TCPL's consolidated equity income in 2005 includes $168 million which
represents TCPL's 31.6 per cent share of Bruce Power earnings for the ten
months ended October 31, 2005.
(4)
Gigawatt hours.
(5)
Megawatt hours.
(6)
Net of fuel cost recoveries.
TCPL's operating income from its combined investment in Bruce Power for 2006 was
$235 million compared to $195 million for 2005. The increase of $40 million was
primarily due to an increased ownership interest in the Bruce A facilities and
higher sales volumes resulting from increased plant availability, partially
offset by lower overall realized prices.
Combined Bruce Power prices achieved during 2006 (excluding other revenues) were
$51 per MWh compared to $58 per MWh in 2005, reflecting lower prices on
uncontracted volumes sold into the spot market. Bruce Power's combined operating
expenses (net of fuel cost recoveries) decreased to $35 per MWh for 2006 from
$40 per MWh in 2005 primarily due to increased output and higher fuel cost
recoveries in 2006.
The Bruce units ran at a combined average availability of 88 per cent in 2006,
compared to an 80 per cent average availability during 2005. The higher
availability in 2006 was the result of 114 fewer days of planned maintenance
outages as well as 65 fewer forced outage days in 2006 compared to 2005.
TCPL's operating income from its combined investment in Bruce Power for 2005 was
$195 million compared to $130 million for the same period in 2004. This increase
was primarily due to higher realized prices in 2005, partially offset by higher
maintenance costs, higher depreciation and lower capitalization of labour and
other in-house costs following the restart of Unit 3 in first quarter 2004.
Adjustments to TCPL's combined interest in Bruce Power's income before income
taxes for 2005 were lower than in 2004 primarily due to a lower amortization of
the purchase price allocated to the fair value of sales contracts in place at
the time of acquisition.
Income from Bruce B is directly impacted by fluctuations in wholesale spot
market prices for electricity. Income from both Bruce A and Bruce B units is
impacted by overall plant availability, which in turn, is impacted by scheduled
and unscheduled maintenance. To reduce its exposure to spot market prices, as at
December 31, 2006, Bruce B entered into fixed price sales contracts to sell
forward approximately 6,900 GWh for 2007 and 2,900 GWh for 2008. As a result of
the contract with the OPA, all of the output from Bruce A was sold at a fixed
price of $58.63 per MWh ($57.37 to March 31, 2006), before recovery of fuel
costs from the OPA. Under the terms of the arrangement between Bruce A and the
OPA, effective October 31, 2005, Bruce A receives a contract price for power
generated, whereby the price is adjusted for inflation annually on April 1. Post
refurbishment, prices are adjusted for any capital cost variances associated
with the restart and refurbishment projects. Bruce A contract prices will not
vary with changes in the wholesale price of power in the Ontario market. As part
of this contract, sales from the Bruce B Units 5 to 8 are subject to a floor
price of $45.99 per MWh ($45.00 to March 31, 2006), adjusted annually for
inflation on April 1. Payments received pursuant to the Bruce B floor price
mechanism may be subject to a recapture payment dependent on annual spot prices
over the term of the contract. Bruce B net earnings to December 31, 2006
included no amounts received pursuant to this floor mechanism.
The overall plant availability percentage in 2007 is expected to be in the low
90s for the four Bruce B units and the mid 70s for the two operating Bruce A
units. Two planned outages are scheduled for Bruce A Unit 3 with the first
outage expected to last one month in second quarter 2007 and a second outage
expected to last approximately two months beginning in late third quarter 2007.
A one month outage of Bruce A Unit 4 is expected to commence in first quarter
2007. The only planned maintenance outage for 2007 for Bruce B is an
approximately two and a half month outage for Unit 6 that began in January 2007
and is expected to be completed in early second quarter 2007.
38 MANAGEMENT'S DISCUSSION AND ANALYSIS
The Bruce partners have agreed that all excess cash from both Bruce A and Bruce
B will be distributed on a monthly basis and that separate cash calls will be
made for major capital projects, including the Bruce A restart and refurbishment
project.
The project to restart and refurbish Bruce A Units 1 and 2 was initiated in
2005. Substantial work on the project began in 2006 after Bruce received formal
acceptance of its environmental assessment from the Canadian Nuclear Safety
Commission in July 2006. Bruce Power has separated Units 1 and 2 from the
operating reactors in Units 3 and 4. At the end of December 2006, eight
replacement steam generators had been delivered and preparations made for the
installation in early 2007. Work on manufacturing the Unit 4 steam generators
also occurred during the year.
Bruce Power's capital program for the restart and refurbishment project is
expected to total approximately $4.25 billion and TCPL's approximately $2.125
billion share will be financed through capital contributions to 2011. A capital
cost risk-and reward-sharing schedule with the OPA is in place for spending
below or in excess of the $4.25 billion base case estimate. The first unit is
expected to be online in late 2009, subject to approval by the Canadian Nuclear
Safety Commission. Restarting Units 1 and 2, which have a capacity of
approximately 1,500 MW, will boost the Bruce facilities' overall output to more
than 6,200 MW. As at December 31, 2006, Bruce A had incurred $1.092 billion in
costs with respect to the restart and refurbishment project.
Western Power Operations
As at December 31, 2006, Western Power Operations directly controlled
approximately 2,100 MW of power supply in Alberta from its three long-term PPAs
and five natural gas-fired cogeneration facilities. The Western Power Operations
power supply portfolio comprises approximately 1,700 MW of low-cost, base-load
coal-fired generation supply and approximately 400 MW of natural gas-fired
cogeneration assets. This supply portfolio is among the lowest-cost, most
competitive generation in the Alberta market area. The three long-term PPAs
include the December 31, 2005 acquisition of the remaining rights and
obligations of the 756 MW Sheerness PPA in addition to the Sundance A and
Sundance B PPAs acquired in 2001 and 2002, respectively. The Sheerness PPA was
acquired from the Alberta Balancing Pool for $585 million on December 31, 2005
and has a remaining term of approximately 14 years. The PPAs entitle TCPL to the
output capacity of these coal facilities, ending in 2017 to 2020. The success of
Western Power Operations is the direct result of its two integrated functions -
marketing and plant operations.
The marketing function, based in Calgary, Alberta, purchases and resells
electricity sourced from the PPAs, markets uncommitted generation volumes from
the cogeneration facilities, and purchases and resells power and gas to maximize
the value of the cogeneration facilities. The marketing function is integral to
optimizing Energy's return from its portfolio of power supply and managing risks
around uncontracted volumes. A portion of TCPL's supply is held for sale in the
spot market for operational reasons and is also dependent upon the availability
of acceptable contract terms in the forward market. This approach to portfolio
management assists in minimizing costs in situations where TCPL would otherwise
have to purchase power in the open market to fulfil its contractual obligations.
In 2006, approximately 35 per cent of power sales volumes were sold into the
spot market. To reduce exposure to spot market prices of uncontracted volumes,
as at December 31, 2006, Western Power Operations entered into fixed price sales
contracts to sell forward approximately 10,600 GWh for 2007 and 8,300 GWh for
2008.
Plant operations consist of five natural gas-fired cogeneration power plants
located in Alberta with an approximate combined output capacity of 400 MW
ranging from 27 MW to 165 MW per facility. A portion of the expected output is
sold under long-term contracts and the remainder is subject to fluctuations in
the price of power and gas. Market heat rate is an economic measure for natural
gas-fired power plants determined by dividing the average price of power per MWh
by the average price of natural gas per gigajoule (GJ) for a given period. To
the extent power is not sold under long-term contracts and plant fuel gas has
not been purchased under long-term contracts, the higher the market heat rate,
the more profitable is a natural gas-fired generating facility. Market heat
rates in Alberta increased in 2006 by more than 60 per cent as a result of a
decrease in average spot market natural gas prices combined with an increase in
power prices. Market heat rates averaged approximately 13.5 GJ/MWh in 2006
compared to approximately 8.3 GJ/MWh in 2005. The market heat rates are expected
to return to more modest levels in 2007.
All plants in Western Power Operations operated with an average plant
availability in 2006 of approximately 88 per cent compared to 85 per cent in
2005. Bear Creek returned to service in mid 2006 after experiencing an unplanned
outage in 2005 resulting from technical difficulties with its gas turbine. Since
its return to service, it has operated as expected.
MANAGEMENT'S DISCUSSION AND ANALYSIS 39
Western Power Operations Results-at-a-Glance
Year ended December 31 (millions of dollars)
2006 2005 2004
Revenues
Power 1,185 715 606
Other(1) 169 158 120
1,354 873 726
Commodity purchases resold
Power (767 ) (476 ) (377 )
Other(1) (135 ) (104 ) (64 )
(902 ) (580 ) (441 )
Plant operating costs and other (135 ) (149 ) (125 )
Depreciation (20 ) (21 ) (22 )
Operating income 297 123 138
(1)
Includes Cancarb Thermax and natural gas sales.
Western Power Operations Sales Volumes
Year ended December 31 (GWh)
2006 2005 2004
Supply
Generation 2,259 2,245 2,105
Purchased
Sundance A & B and Sheerness PPAs 12,712 6,974 6,842
Other purchases 1,905 2,687 2,748
16,876 11,906 11,695
Contracted vs. Spot
Contracted 11,029 10,374 10,705
Spot 5,847 1,532 990
16,876 11,906 11,695
Operating income in 2006 of $297 million was $174 million higher than the $123
million earned in 2005. This increase was primarily due to incremental earnings
from the December 31, 2005 acquisition of the 756 MW Sheerness PPA and increased
margins from a combination of higher overall realized power prices and higher
market heat rates on uncontracted volumes of power sold. Revenues and commodity
purchases resold increased in 2006 compared to 2005 primarily due to the
acquisition of the Sheerness PPA, as well as higher realized power prices. Plant
operating costs and other, which include fuel gas consumed in generation,
decreased due to lower natural gas prices. Purchased power volumes in 2006
increased compared to 2005 primarily due to the acquisition of the Sheerness
PPA. In 2006, approximately 35 per cent of power sales volumes were sold into
the spot market compared to 13 per cent in 2005.
Operating income for 2005 was $123 million or $15 million lower compared to $138
million earned in 2004. This decrease was primarily due to reduced margins in
2005 resulting from the lower market heat rates on uncontracted volumes of power
generated, fee revenues earned in 2004 from Power LP and a lower contribution
from Bear Creek. Revenues and commodity purchases resold increased in 2005,
compared to 2004, primarily due to higher realized
40 MANAGEMENT'S DISCUSSION AND ANALYSIS
prices. Plant operating costs and other, which include fuel gas consumed in
generation, increased due to higher operating and fuel usage costs at MacKay
River resulting from a full year of operation and higher natural gas prices.
Generation volumes in 2005 increased compared to 2004 primarily due to a full
year of operations at MacKay River, partially offset by an unplanned outage at
Bear Creek. TCPL ceased to earn fees to manage and operate Power LP's plants
with the sale of Power LP in August 2005. In 2005, approximately 13 per cent of
power sales volumes were sold into the spot market compared to eight per cent in
2004.
Eastern Power Operations
Eastern Power Operations conducts its business primarily in the deregulated New
England power market and in eastern Canada. In the New England market, Eastern
Power Operations has established a successful marketing operation and in 2006,
significantly increased its marketing presence. Growth in generation capacity in
eastern Canada was also significant. The first of the six Cartier Wind wind farm
projects, Baie-des-Sables, was placed in service in November 2006. The 550 MW
Becancour power plant near Trois Rivieres, Quebec began operations in September
2006. Including facilities that are under construction or in development,
Eastern Power Operations owns approximately 3,200 MW of power generation
capacity. To reduce exposure to spot market prices of uncontracted volumes, as
at December 31, 2006, Eastern Power Operations had fixed price sales contracts
to sell forward approximately 11,900 GWh for 2007 and 9,600 GWh for 2008.
Eastern Power Operations' success in the New England deregulated power markets
is the direct result of a knowledgeable, region-specific marketing operation
which is conducted through its wholly owned subsidiary, TransCanada Power
Marketing Ltd. (TCPM), located in Westborough, Massachusetts. TCPM has firmly
established itself as a leading energy provider and marketer in the region and
is focused on selling power under short - and long-term contracts to wholesale,
commercial and industrial customers while managing a portfolio of power supplies
sourced from both its own generation and wholesale power purchases. TCPM is a
full requirement electric service provider offering varied products and services
to assist customers in managing their power supply and power prices in volatile
deregulated power markets.
Eastern Power Operations' current operating power generation assets are TC
Hydro, OSP, Becancour, Grandview and the Baie-des-Sables wind farm. The TC Hydro
assets include 13 hydroelectric stations housing 39 hydroelectric generating
units on the Connecticut River System in New Hampshire and Vermont and the
Deerfield River System in Massachusetts and Vermont. Water flows in 2006 through
the hydro assets were above long-term averages as a result of higher
precipitation in the areas surrounding the river systems. These higher than
expected water flows were partially offset by lower than expected power prices
in the market during 2006.
OSP is a 560 MW natural gas-fired plant located in Rhode Island, owned 100 per
cent by TCPL. In 2006, plant availability and utilization of the OSP facility
improved compared to 2005. OSP realized lower overall natural gas fuel supply
costs in 2006 compared to 2005 due to lower spot prices of natural gas as a
result of a restructuring of its long-term gas supply contracts which took place
in 2005.
Becancour is a 550 MW natural gas-fired cogeneration plant located near Trois
Rivieres, Quebec. After nearly three years of planning and construction, and an
investment of approximately $500 million, Becancour was placed in service in
September 2006. The facility is capable of generating approximately 4,500 GWh of
power per year. Under long-term contracts, the facility will supply electricity
to Hydro-Quebec to help meet growing electricity demands and provide an
important source of steam for industrial processes.
Grandview is a 90 MW natural gas-fired cogeneration facility on the site of the
Irving Oil Refinery (Irving) in Saint John, New Brunswick. Under a 20-year
tolling arrangement which will expire in 2025, Irving supplies fuel for the
plant and contracts for 100 per cent of the plant's heat and electricity output.
Eastern Power Operations' growing presence in eastern Canada is represented by
the development of the Portlands Energy project and the Halton Hills power plant
and construction in 2007 on the second and third of six proposed wind farms of
the Cartier Wind project.
In November 2006, the Baie-des-Sable wind farm went into commercial operation
and is currently one of the largest wind farms in Canada, providing up to 110 MW
of power to the Hydro Quebec grid. Baie-des-Sable is the first phase
MANAGEMENT'S DISCUSSION AND ANALYSIS 41
of a multi-phase, multi-year project called the Cartier Wind project that is
owned 62 per cent by TCPL. The other phases of Cartier Wind will continue,
subject to future appropriations and approvals, through 2012 at six different
locations in the Gaspe region of Quebec and capacity is expected to total 740 MW
when all phases are complete. Commitments are in place for the 100 MW Anse a
Valleau phase and the 100 MW Carleton phase Anse a Valleau is presently under
construction and is expected to be placed into commercial service during third
quarter 2007 and construction at Carleton will commence in late 2007 with
expected commercial service to begin in fourth quarter 2008.
In September 2006, Portlands Energy, a 50/50 partnership between Ontario Power
Generation and TCPL, announced that it had signed a 20-year ACES contract with
the OPA to construct a 550 MW high efficiency, combined-cycle natural gas
generation plant to be located in downtown Toronto, Ontario. The capital cost of
the Portlands Energy project is estimated to be approximately $730 million and
is expected to be operational in simple cycle mode, delivering 340 MW of
electricity to the City of Toronto, beginning June 1, 2008. Upon the expected
completion in second quarter 2009, the Company anticipates that this plant will
provide up to 550 MW of power under the ACES contract.
In November 2006, TCPL announced that it had been awarded a 20-year Greater
Toronto Area (GTA) West Trafalgar Clean Energy Supply contract by the OPA to
build, own and operate a 683 MW natural gas-fired power plant near the town of
Halton Hills, Ontario. TCPL expects to invest approximately $670 million in the
Halton Hills Generating Station, which is anticipated to be in service in second
quarter 2010.
On June 15, 2006, the FERC approved a settlement agreement to implement a
newly-designed Forward Capacity Market (FCM) for power generation in the New
England power markets. The FCM design is intended to promote investment in new
and existing power resources needed to meet the growing consumer demand and
maintain a reliable power system. The settlement agreement provides for a
multi-year transition period beginning in December 2006 and ending in 2010,
whereby fixed payments, ranging from US$3.05 to US$4.10 per kilowatt-month, will
be made to owners of existing installed capacity. These payments will be reduced
in the event of facility-forced outages. Eastern Power Operations' 560 MW OSP
plant and 567 MW TC Hydro generation facilities are eligible to receive payments
during the transition period starting in December 2006. Under the new FCM
design, Independent System Operator New England will project the needs of the
power system three years in advance and then hold an annual auction to purchase
power resources to satisfy a region's future needs. June 1, 2010 is identified
as the first period for which suppliers would receive payments pursuant to the
FCM auction mechanism.
Eastern Power Operations Results-at-a-Glance(1)
Year ended December 31 (millions of dollars)
2006 2005 2004
Revenues
Power 789 505 535
Other(2) 292 412 238
1,081 917 773
Commodity purchases resold
Power (379 ) (215 ) (288 )
Other(2) (257 ) (373 ) (211 )
(636 ) (588 ) (499 )
Plant operating costs and other (226 ) (167 ) (146 )
Depreciation (32 ) (25 ) (20 )
Operating income 187 137 108
(1)
Curtis Palmer is included until April 30, 2004.
(2)
Other includes natural gas.
42 MANAGEMENT'S DISCUSSION AND ANALYSIS
Eastern Power Operations Sales Volumes(1)
Year ended December 31 (GWh)
2006 2005 2004
Supply
Generation 4,700 2,879 1,467
Purchased 3,091 2,627 4,731
7,791 5,506 6,198
Contracted vs. Spot
Contracted 7,374 4,919 6,055
Spot 417 587 143
7,791 5,506 6,198
(1)
Curtis Palmer is included until April 30, 2004.
Operating income for 2006 was $187 million or $50 million higher than the $137
million earned in 2005. This increase is primarily due to incremental income
from the full year of ownership of the TC Hydro assets, the placing into service
of the 550 MW Becancour cogeneration plant in September 2006, a $10-million
after-tax one-time restructuring payment in first quarter 2005 from OSP to its
natural gas fuel suppliers, and higher overall margins on power sales volumes in
2006. Partially offsetting these increases was the negative impact of a weaker
U.S. dollar in 2006 compared to 2005.
Eastern Power Operations' revenues in 2006 were $1,081 or $164 million higher
than the $917 million earned in 2005. This is due to the placing into service of
the Becancour facility, increased sales volumes to commercial and industrial
customers, and higher realized prices. Other revenue and other commodity
purchases resold decreased year-over-year as a result of a reduction in the
quantity of natural gas purchased and resold under the new natural gas supply
contracts at OSP. Power commodity purchases resold were higher in 2006 due to
the impact of higher purchased volumes, combined with higher prices for
purchased power. Purchased power volumes were higher in 2006 due to higher
contracted sales volumes, partially offset by the increased power generation
from the purchase of the TC Hydro assets as volumes generated from the TC Hydro
assets reduced the requirement to purchase power to fulfil contractual sales
obligations. Plant operating costs and other in 2006 were higher primarily due
to the full year of operations of the TC Hydro assets as well as the placing
into service of the Becancour and Baie-des-Sables facilities.
Operating income for 2005 was $137 million or $29 million higher than the $108
million earned in 2004. The incremental income from the acquisition of the TC
Hydro assets and income from the Grandview cogeneration facility were the
primary reasons for this increase. Partially offsetting these increases were the
contract restructuring payment made by OSP in first quarter 2005, a $10-million
after-tax reduction in income as a result of the sale of Curtis Palmer to Power
LP in April 2004, and a loss of operating income primarily associated with the
expiration of certain long-term sales contracts in 2004.
Power LP Divestiture
On August 31, 2005, TCPL sold all of its interest in Power LP to EPCOR for net
proceeds of $523 million resulting in an after-tax gain of $193 million. This
divestiture included approximately 14.5 million partnership units, representing
approximately 30.6 per cent of the outstanding units, 100 per cent of the
general partnership of Power LP, and management and operations agreements
governing the ongoing operation of Power LP's generation assets. TCPL's
investment in Power LP generated operating income of $29 million in each of 2005
and 2004.
MANAGEMENT'S DISCUSSION AND ANALYSIS 43
Plant Availability
,G993188.JPG Weighted average power plant availability for all plants, excluding Bruce Power, was 93 per cent
in 2006 compared to 87 per cent in 2005 and 96 per cent in 2004. Plant availability represents the
percentage of time in the year that the plant is available to generate power, whether actually
running or not, and is reduced by planned and unplanned outages. Western Power Operations' plant
availability was impacted in 2006 and 2005 by an unplanned outage at Bear Creek, which returned to
service in August 2006. An additional planned outage was taken in 2005 at the MacKay River
facility, further decreasing the plant availability for Western Power Operations in 2005.
Availability of 95 per cent was achieved in Eastern Power Operations in 2006. Availability was
lower in 2005 as a result of OSP experiencing two significant outages.
Weighted Average Plant Availability(1)
Year ended December 31
2006 2005 2004
Bruce Power(2) 88% 80% 82%
Western Power Operations(3) 88% 85% 95%
Eastern Power Operations(4) 95% 83% 95%
Power LP investment(5) - 94% 97%
All plants, excluding Bruce Power investment 93% 87% 96%
All plants 91% 84% 90%
(1)
Plant availability represents the percentage of time in the period that the
plant is available to generate power, whether actually running or not and is
reduced by planned and unplanned outages.
(2)
Bruce A Unit 3 is included effective March 1, 2004.
(3)
The Sheerness PPA is included in Western Power Operations, effective
December 31, 2005.
(4)
TC Hydro, Becancour and Cartier Wind's Baie-des-Sables are included in
Eastern Power Operations effective April 1, 2005, September 17, 2006 and
November 21, 2006, respectively.
(5)
Power LP is included to August 31, 2005.
Natural Gas Storage
With the completion of the 50 Bcf Edson storage facility, TCPL became one of the
largest natural gas storage providers in western Canada in 2006. TCPL owns or
controls 138 Bcf of natural gas storage capacity in Alberta, which includes a 60
per cent ownership interest in CrossAlta Gas Storage & Services Ltd.
(CrossAlta), an independently operated 50 Bcf storage facility. TCPL also has
contracts for 38 Bcf in 2007 of long-term, Alberta-based storage capacity from a
third party.
Natural Gas Storage Capacity
Working Gas Maximum Injection/
Storage Capacity Withdrawal Capacity
(Bcf ) (mmcf/d )
Edson 50 725
CrossAlta 50 480
Third Party Storage (for 2007) 38 630
138 1,835
44 MANAGEMENT'S DISCUSSION AND ANALYSIS
TCPL believes the market fundamentals for natural gas storage are strong. The
additional gas storage capacity will help balance seasonal and short-term supply
and demand, and provide flexibility to the supply of natural gas to Alberta and
North America. The increasing seasonal imbalance in North American natural gas
supply and demand has increased gas price volatility and the demand for storage
service. Alberta-based storage will continue to serve market needs and could
play an important role should northern gas be connected to North American
markets. Energy's natural gas storage business operates independently from
TCPL's regulated natural gas transmission business.
TCPL manages its exposure to seasonal gas price spreads by hedging storage
capacity with a portfolio of third party storage contracts and gas purchases and
sales. TCPL offers a broad range of flexible injection and withdrawal storage
alternatives specific to customer needs in multi-year contract terms. In
addition to term gas storage contracts, TCPL actively manages its storage assets
with a combination of gas hedging activities and short-term third party
contracts to take advantage of market opportunities and meet unique customer
needs. Market volatility frequently creates arbitrage opportunities and TCPL
offers market centre solutions to capture these short-term price movements.
Market centre products consist of short-term deliver- redeliver contracts,
parking, peak-day supply and other related services.
The Edson storage operation is an underground natural gas storage facility
consisting of a single depleted reservoir, the Viking D pool, a central
processing facility and associated pipeline gathering system. The plant is
located near Edson, Alberta. The Viking D pool produced approximately 71 Bcf of
gas over its productive life from the 1980's to early 2004. The natural gas
storage facility is expected to have a working natural gas capacity of
approximately 50 Bcf, is connected to TCPL's Alberta System and has a central
processing system capable of maximum injection and withdrawal rates of 725 mmcf/
d of natural gas. Construction of the Edson facility was substantially completed
in 2006 and placed into service on December 31, 2006.
The CrossAlta storage facility is a 50 Bcf natural gas storage facility located
near the town of Crossfield, Alberta. CrossAlta is a joint venture with BP
Canada that has been in operation since 1994 and markets its own storage
capacity and services. Gas is stored in a depleted gas reservoir that has been
used to produce gas at this location since the 1960s. CrossAlta successfully
completed a major expansion in the fall of 2005. The expansion increased total
working natural gas capacity from 40 Bcf to 50 Bcf, with the potential to expand
to 80 Bcf. The storage facility has a peak withdrawal capacity of 480 mmcf/d
with the potential to expand to 1,000 mmcf/d.
The third-party natural gas storage capacity contracted by TCPL is also located
in Alberta. The capacity has increased annually from 18 Bcf in 2005 to 28 Bcf in
2006 and is expected to reach 38 Bcf in 2007. The contract expires in 2030,
subject to mutual early termination rights in 2015.
Natural Gas Storage operating income of $93 million for the year ended December
31, 2006 increased $61 million and $66 million, compared to 2005 and 2004,
respectively. The increases were primarily due to higher contributions from
CrossAlta as a result of increased capacity and higher natural gas storage
spreads, and income from contracted third-party natural gas storage capacity.
The Edson facility did not contribute to earnings in 2006 as the asset was
placed into service on December 31, 2006.
LNG Projects
TCPL continues to pursue two LNG proposals, the Broadwater and Cacouna projects.
Broadwater, a joint venture with Shell US Gas & Power LLC (Shell), is a proposed
LNG facility in the New York and Connecticut State waters in Long Island Sound.
The Broadwater terminal would be capable of receiving, storing, and regassifying
imported LNG with an average send-out capacity of approximately 1 Bcf/d of
natural gas. TCPL, on behalf of Broadwater, filed an application in January 2006
with the FERC for approval of the project. The U.S. Coast Guard issued a report
which determined that the waterways associated with the project are suitable if
additional measures are implemented to manage the safety and security risks
associated with the project. Broadwater's application to the New York Department
of State for a determination that the project is consistent with New York's
coastal zone policies was deemed complete by the state in November 2006. Also in
November, the FERC issued a Draft Environmental Impact Statement to fulfil the
requirements of the National Environmental Policy Act and the FERC's
implementing regulations. The Statement concludes that with strict adherence to
federal and state permit requirements and regulations, Broadwater's proposed
mitigation measures
MANAGEMENT'S DISCUSSION AND ANALYSIS 45
and the FERC's recommendations, the Broadwater project will not result in a
significant impact on the environment. At December 31, 2006 the Company had
capitalized $31 million related to Broadwater.
Cacouna, a joint venture with Petro-Canada, is a proposed LNG project at the
Gros Cacouna harbour on the St. Lawrence River in Quebec. The proposed terminal
would be capable of receiving, storing, and regassifying imported LNG with an
average throughput capacity of approximately 500 mmcf/d of natural gas. A public
hearing on the Cacouna facility was held in May and June 2006. In December 2006,
the Quebec government released the report of the Joint Commission on the Cacouna
Energy project, which contained several recommendations and opinions but appears
to be favourable to the project. TCPL continues to work towards gaining
regulatory approval and, if the necessary approvals are obtained, the facility
is anticipated to be in service by 2010.
ENERGY - OPPORTUNITIES AND DEVELOPMENTS
TCPL is committed to growing its North American Energy business through
acquisitions and development of greenfield opportunities in markets it knows and
has a competitive advantage - primarily western Canada, the northwestern U.S.,
eastern Canada and the northeastern U.S. The North American energy industry is
expansive and will provide many opportunities for greenfield growth in power
generation, power infrastructure projects and natural gas storage. In addition
to greenfield growth opportunities, TCPL will endeavour to pursue acquisitions
resulting from industry and corporate restructurings and corporate bankruptcies.
In addition to natural gas-fired facilities, Energy will focus on generation
sourced from wind, hydro and nuclear. Its diverse power supply portfolio will
continue to include low-cost, base-load facilities with low operating costs and
high reliability, which may be underpinned by secure long-term contracts.
The Becancour natural gas-fired cogeneration power plant and the first of six
wind farms in the Cartier Wind project, both located in Quebec, were placed in
service in 2006. The remaining five Cartier Wind farms will continue, although
certain phases of the project are subject to future appropriations and
approvals. Construction began in 2006 on Portlands Energy's 550 MW, combined
cycle natural gas generation plant in downtown Toronto. In 2006, TCPL also
announced that it had been awarded a 20-year GTA West Trafalgar Clean Energy
Supply contract by the OPA to build, own and operate a 683 MW natural gas-fired
power plant near the town of Halton Hills, Ontario which is expected to be
completed in 2010. The Bruce A restart and refurbishment continued in 2006 and
Units 1 and 2 are expected to be restarted in late 2009 or early 2010.
Construction of the 50 Bcf Edson natural gas storage facility was substantially
completed and the facility placed into service on December 31, 2006.
TCPL is pursuing two LNG projects, Broadwater and Cacouna. Broadwater is a joint
project with Shell to build a 1 Bcf/d LNG facility in the waters of the Long
Island Sound. Cacouna is a joint venture with Petro-Canada to construct a 500
mmcf/d LNG facility at Gros Cacouna.
ENERGY - BUSINESS RISKS
Fluctuating Power and Natural Gas Market Prices
TCPL operates in competitive, generally deregulated power and natural gas
markets in North America. Volatility in power and natural gas prices is caused
by various market forces such as fluctuating supply and demand which are greatly
affected by weather events. Energy's earnings from the sale of uncontracted
volumes are subject to price volatility. Although Energy commits a significant
portion of its supply to medium- to long-term sales contracts, it retains an
amount of unsold supply in order to provide flexibility in managing the
Company's portfolio of owned assets. The Company's risk management practices are
described further in the section on Risk Management. See the "Uncontracted
Volumes" section below.
Uncontracted Volumes
Energy has certain uncontracted power sales volumes in Western and Eastern Power
Operations and through its investment in Bruce Power. Sale of uncontracted power
volumes into the spot market is subject to market price
46 MANAGEMENT'S DISCUSSION AND ANALYSIS
volatility which directly impacts earnings. Bruce B has a significant amount of
uncontracted volumes sold into the wholesale power spot market while 100 per
cent of the Bruce A output is sold to the OPA under fixed-price contract terms.
The natural gas storage business is subject to fluctuating natural gas seasonal
spreads generally determined by the differential in natural gas prices in the
traditional summer injection and winter withdrawal seasons. As a result, the
Company hedges capacity with a portfolio of contractual commitments with varying
terms.
Plant Availability
Maintaining plant availability is essential to the continued success of the
Energy business. Plant operating risk is mitigated through a commitment to
TCPL's operational excellence strategy that provides low-cost, reliable
operating performance at each of the Company's facilities. Unexpected plant
outages and/or the duration of outages could result in lower plant output and
sales revenue, reduced margins and increased maintenance costs. At certain
times, unplanned outages may require power or natural gas purchases at market
prices to enable TCPL to meet its contractual obligations.
Weather
Extreme temperature and weather events in North America and the Gulf of Mexico
often create price volatility and demand for power and natural gas. These same
events may also restrict the availability of power and natural gas. Seasonal
changes in temperature can also affect the efficiency and output capability of
natural gas-fired power plants. Variability in wind speeds may impact the
earnings of the Cartier Wind assets in Quebec.
Hydrology
Energy's power business is subject to hydrology risk with its ownership of
hydroelectric power generation facilities in the northeastern U.S. Weather
changes, weather events, local river management and potential dam failures at
these plants or upstream facilities pose potential risks to the Company.
Execution and Capital Cost
Energy's new construction program in Ontario and Quebec, including its
investment in Bruce Power, is subject to execution and capital cost risk. At
Bruce Power, Bruce A's four unit restart and refurbishment program is also
subject to a capital cost risk-and reward-sharing mechanism with the OPA.
Asset Commissioning
Recently constructed assets including Edson, Baie-des-Sables and Becancour were
all placed in service during 2006 and are in the first full year of operation in
2007. Although all of TCPL's newly constructed assets go through rigorous
acceptance testing prior to being placed in service, there is a risk that these
assets may have lower than expected availability or performance, especially in
the assets' first year of operations.
Power Regulatory
TCPL operates in both regulated and deregulated power markets. As electricity
markets evolve across North America, there is the potential for regulatory
bodies to implement new rules that could negatively impact TCPL as a generator
and marketer of electricity. These may be in the form of market rule changes,
price caps, emission controls, unfair cost allocations to generators or attempts
to control the wholesale market by encouraging new plant construction. TCPL
continues to monitor regulatory issues and reform as well as participate in and
lead discussions around these topics.
For information on management of risks with respect to the Energy business,
refer to the "Risks and Risk Management" section of this MD&A.
ENERGY - OUTLOOK
In Energy, net earnings in 2007 are expected to approximate or be slightly lower
than 2006 net earnings due to the non-recurring $23-million future tax benefit
in 2006 arising from reductions in federal and provincial income tax rates.
Operating income is expected to be relatively consistent with 2006, although
this is very dependent on commodity prices in each region as well as other
factors such as hydrology and storage spreads. TCPL's operating income from its
investment in Bruce B can be significantly impacted by the effect, on
uncontracted output, of changes in spot market prices for power. Excluding any
changes in spot market prices for 2007 compared to 2006, Bruce Power's operating
MANAGEMENT'S DISCUSSION AND ANALYSIS 47
income is expected to decline in 2007 compared to 2006, reflecting lower
projected generation volumes and higher operating costs resulting from an
increase in planned outages in 2007. Western Power Operations' operating income
in 2007 is expected to approximate 2006. Although TCPL has sold forward
significant output from its Alberta PPAs and power plants, Western Power
Operations' operating income in 2007 can be significantly impacted by changes in
the spot market price of power and market heat rates in Alberta. Eastern Power
Operations' operating income is expected to increase in 2007 primarily due to a
full year of operations for both the Becancour natural gas-fired cogeneration
facility and the first of six wind farms of the Cartier Wind project as well as
the positive impact of the NEPOOL forward capacity payments received by OSP and
TC Hydro commencing December 1, 2006. Gas Storage's operating income is expected
to increase in 2007 over 2006 primarily due to the placing into service of the
Edson facility at the end of 2006, partially offset by expected lower storage
spreads.
The earnings outlook for Energy may be affected by factors such as fluctuating
market prices for power and natural gas, market heat rates, sales of
uncontracted power volumes, natural gas storage spreads, plant availability,
regulatory changes, weather, currency movements, and overall stability of the
energy industry. See "Energy - Business Risks" for a complete discussion of
these factors.
CORPORATE
CORPORATE RESULTS-AT-A-GLANCE
Year ended December 31 (millions of dollars)
2006 2005 2004
Indirect financial charges and non-controlling interests 139 131 81
Interest income and other (43 ) (29 ) (34 )
Income taxes (133 ) (65 ) (43 )
Net (earnings)/expenses, after tax (37 ) 37 4
Corporate reflects net expenses not allocated to specific business segments,
including:
*
Indirect Financial Charges and Non-Controlling Interests Direct
financial charges are reported in their respective business segments and
are primarily associated with the debt and preferred securities related
to the Company's wholly owned pipelines. Indirect financial charges,
including the related foreign exchange impacts, primarily reside in
Corporate. These costs are directly impacted by the amount of debt that
TCPL maintains and the degree to which TCPL is impacted by fluctuations
in interest rates and foreign exchange.
*
Interest Income and Other Interest income includes interest earned on
invested cash balances and income tax refunds. Gains and losses on
foreign exchange related to working capital in Corporate are also
included in interest income and other.
*
Income Taxes Income tax recoveries includes income taxes calculated on
Corporate's net expenses as well as income tax refunds and adjustments.
Net earnings, after tax, in Corporate were $37 million in 2006 compared to net
expenses of $37 million in 2005 and $4 million in 2004.
The increase of $74 million in net earnings in 2006, compared to 2005, was
primarily due to a $50-million income tax benefit related to the resolution of
certain income tax matters reported in third quarter 2006, $12 million of income
tax refunds and related interest income in fourth quarter 2006, and a
$10-million favourable impact on future income taxes arising from reductions in
Canadian federal and provincial corporate income tax rates in second quarter
2006. In addition, net earnings in 2006 were positively impacted by the effect
of a weaker U.S. dollar.
The increase of $33 million in net expenses in 2005 compared to 2004 was
primarily due to increased interest expense on higher average long-term debt and
commercial paper balances in 2005 as well as the release in 2004 of previously
48 MANAGEMENT'S DISCUSSION AND ANALYSIS
established restructuring provisions. Income tax refunds and positive tax
adjustments were comparable in 2004 and 2005.
In 2007, Corporate's net expenses are expected to be higher in 2007 compared to
2006 primarily due to income tax refunds and positive income tax adjustments
realized in 2006 that are not expected to recur in 2007. Financing costs
associated with the acquisition of ANR are expected to increase net expenses in
Corporate in 2007. In addition, Corporate's results could be impacted by debt
levels, interest rates, foreign exchange movements and income tax refunds and
adjustments. The performance of the Canadian dollar relative to the U.S. dollar
will either positively or negatively impact Corporate's results, although this
impact is mitigated by offsetting exposures in certain of TCPL's other
businesses as well as through the Company's hedging activities.
DISCONTINUED OPERATIONS
In 2006, the Company recognized income from discontinued operations of $28
million, reflecting bankruptcy settlements with Mirant related to TCPL's Gas
Marketing business divested in 2001. In 2005, the Company reviewed the provision
for loss on discontinued operations and concluded that the provision was
adequate. In 2004, $52 million was recognized in income which related to the
original $102 million after-tax deferred gain included in the sale of the Gas
Marketing business.
LIQUIDITY AND CAPITAL RESOURCES
Summarized Cash Flow
Year ended December 31 (millions of dollars)
2006 2005 2004
Funds generated from operations 2,374 1,950 1,701
(Increase)/decrease in working capital (300 ) (48 ) 28
Net cash provided by operations 2,074 1,902 1,729
Net cash used in investing activities (2,114 ) (1,335 ) (1,648 )
Net cash provided by/(used in) financing activities 220 (556 ) (147 )
Effect of foreign exchange rate changes on cash and short-term 9 11 (87 )
investments
Increase/(decrease) in cash and short-term investments 189 22 (153 )
Cash and short-term investments - beginning of year 212 190 343
Cash and short-term investments - end of year 401 212 190
MANAGEMENT'S DISCUSSION AND ANALYSIS 49
HIGHLIGHTS
Investing Activities
*
At December 31, 2006, total capital expenditures and acquisitions,
including assumed debt, were approximately $7.0 billion over the past
three years.
Dividends
*
In January 2007, TransCanada's Board of Directors authorized the issue
of common shares from treasury at a two per cent discount under
TransCanada's DRP, beginning with the dividend payable April 30, 2007 to
shareholders of record at March 30, 2007. TCPL preferred shareholders
may reinvest their dividends to obtain TransCanada common shares.
Funds Generated from Operations
,G738810.JPG Funds Generated from Operations Funds generated from operations were $2.4 billion in 2006 compared
to $2.0 billion and $1.7 billion, in 2005 and 2004, respectively. The increase in 2006 compared to
2005 was mainly as a result of higher net income, excluding gains, and lower current income tax
expense. The Pipelines business was the primary source of funds generated from operations for each
of the three years. As a result of rapid growth in the Energy business in the last few years, the
Energy segment's funds generated from operations increased in 2006 compared to the two prior
years.
At December 31, 2006, TCPL's ability to generate adequate amounts of cash in the short term and
the long term when needed, and to maintain financial capacity and flexibility to provide for
planned growth, was consistent with recent years.
Investing Activities
Capital expenditures, totalled $1,572 million in 2006 compared to $754 million
in 2005 and $530 million in 2004, respectively. Expenditures in all three years
related primarily to construction of new power plants and natural gas storage
facilities in Canada as well as maintenance and capacity capital in the
Pipelines business.
,G539738.JPG During 2006, PipeLines LP acquired an additional 49 per cent interest in Tuscarora, subject to
closing adjustments, for US$100 million, in addition to indirectly assuming US$37 million of debt.
In addition, PipeLines LP acquired an additional 20 per cent general partnership interest in
Northern Border for US$307 million, in addition to indirectly assuming US$122 million of debt. At
December 31, 2006, TCPL held a 13.4 per cent interest in PipeLines LP. In 2006, TCPL sold its 17.5
per cent general partner interest in Northern Border Partners, L.P. for proceeds of $23 million.
During 2005, TCPL acquired the remaining rights and obligations of the Sheerness PPA for $585
million, invested a net cash outlay of $100 million in Bruce A as part of the Bruce Power
reorganization, purchased the TC Hydro assets from USGen New England, Inc. (USGen) for US$503
million and acquired an additional 3.52 per cent ownership interest in Iroquois for
US$14 million. TCPL sold its ownership interest in Power LP for proceeds of $444 million, net of current tax, its
approximate 11 per cent ownership interest in Paiton Energy for proceeds of $125 million, net of current tax, and
PipeLines LP units for proceeds of $102 million, net of current tax.
During 2004, TCPL acquired GTN for US$1.2 billion, excluding assumed debt of
approximately US$500 million, and sold the ManChief and Curtis Palmer power
facilities to Power LP for US$403 million, excluding closing adjustments.
Financing Activities
On February 22, 2007, the Company completed its acquisition of ANR and an
additional interest in Great Lakes which was financed through the issuance of a
combination of debt and common shares. At the same time, PipeLines LP completed
the acquisition of its interest in Great Lakes through the issuance of a
combination of debt and equity. These financings are summarized in the section
"Subsequent Events" in this MD&A.
This information is provided by RNS
The company news service from the London Stock Exchange
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