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RNS Number:3245Q
TransCanada Pipelines Ld
29 September 2003
TRANSCANADA PIPELINES LIMITED
SECOND QUARTER 2003
Quarterly Report
Consolidated
Results-at-a-Glance
(unaudited) Three months ended June 30 Six months ended
June 30
(millions of dollars) 2003 2002 2003 2002
---------------------- --------- --------- --------- ---------
Net Income Applicable to 202 205 410 392
Common Shares --------- --------- --------- ---------
Management's Discussion and Analysis
The following discussion and analysis should be read in conjunction with the
accompanying unaudited consolidated financial statements of TransCanada
PipeLines Limited (TCPL or the company) for the six months ended June 30, 2003
and the notes thereto.
The company's plan of arrangement to establish TransCanada Corporation
(TransCanada) as the parent company of TCPL became effective on May 15, 2003.
Common shareholders of TCPL automatically became common shareholders of
TransCanada with each TCPL common share being automatically exchanged for one
TransCanada common share. The establishment of TransCanada has no impact on
TCPL's day to day operations, services or obligations. The assets and
liabilities of TCPL remain with TCPL. Debt holders and preferred shareholders of
TCPL continue to hold these securities in TCPL. TransCanada owns all of the
outstanding common shares of TCPL.
Results of Operations
Consolidated
TCPL's net income applicable to common shares for the six months ended June 30,
2003 was $410 million compared to $392 million for the comparable period in
2002. The increase of $18 million in the first six months of 2003 compared to
the same period in 2002 was primarily due to higher earnings from the Power
business and lower net expenses in the Corporate segment, partially offset by
lower earnings from the Transmission segment.
The Power segment earnings for the six months ended June 30, 2003 included $40
million after tax related to TCPL's earnings from its investment in Bruce Power
L.P. (Bruce) which was acquired in February 2003 and a $19 million positive
after-tax earnings impact of a June 2003 settlement with a former counterparty
which defaulted in 2001 under power forward contracts. This amount represents
the value of power forward contracts terminated at the time of default.
The lower earnings in the Transmission segment were primarily due to the decline
in the Alberta System's 2003 net earnings reflecting the one-year fixed revenue
requirement settlement reached between TCPL and its stakeholders in February
2003. In June 2002, TCPL received the National Energy Board (NEB) decision on
its Fair Return application (Fair Return decision) to determine the cost of
capital to be included in the calculation of 2001 and 2002 final tolls on its
Canadian Mainline. The results for the six months ending June 30, 2002 included
after-tax income of $25 million representing the impact of the Fair Return
decision for 2001 ($16 million) and six months ending June 30, 2002 ($9
million). The results for the six months ending June 30, 2002 also included
TCPL's $7 million share of a favourable ruling for Great Lakes related to
Minnesota use tax paid in prior years.
TCPL's net income applicable to common shares for second quarter 2003 was $202
million compared to $205 million for second quarter 2002. Second quarter 2003
results included $13 million after tax of TCPL's share of earnings from Bruce
and the $19 million after tax settlement with a former counterparty. Second
quarter 2002 results include $25 million of net income for the period January 1,
2001 to June 30, 2002 related to the Fair Return decision.
Funds generated from operations of $891 million for the six months ended June
30, 2003 were consistent with the same period in the prior year.
Segment
Results-at-a-Glance
(unaudited) Three months ended June 30 Six months ended
June 30
(millions of dollars) 2003 2002 2003 2002
---------------------- ------- ------- ------- -------
Transmission 144 174 302 337
Power 63 40 126 81
Corporate (5) (9) (18) (26)
------- ------- ------- -------
Net Income Applicable to 202 205 410 392
Common Shares ------- ------- ------- -------
Transmission
The Transmission business generated net earnings of $144 million and $302
million for the three and six months ended June 30, 2003, respectively, compared
to $174 million and $337 million for the same periods in 2002.
Transmission
Results-at-a-Glance
(unaudited) Three months ended June 30 Six months ended
June 30
(millions of dollars) 2003 2002 2003 2002
------- ------- ------- -------
----------------------
Wholly-Owned
Pipelines
Alberta System 44 52 86 102
Canadian Mainline 71 92 142 160
BC System 2 1 4 3
------- ------- ------- -------
117 145 232 265
------- ------- ------- -------
North American
Pipeline Ventures
Great Lakes 11 14 28 36
TC PipeLines, LP 4 4 7 8
Iroquois 4 6 11 11
Portland - 1 7 2
Foothills 5 4 9 9
Trans Quebec & 2 2 4 4
Maritimes
CrossAlta 1 2 4 7
Northern Development - (1) (1) (2)
Other - (3) 1 (3)
------- ------- ------- -------
27 29 70 72
------- ------- ------- -------
Net earnings 144 174 302 337
------- ------- ------- -------
Wholly-Owned Pipelines
The Alberta System's net earnings of $44 million in second quarter 2003
decreased $8 million compared to $52 million in the same quarter of 2002. Net
earnings for the six months ended June 30, 2003 decreased $16 million compared
to the same period in 2002. The decrease is primarily due to lower earnings from
the one-year 2003 Alberta System Revenue Requirement Settlement (the 2003
Settlement) reached in February 2003. The 2003 Settlement includes a fixed
revenue requirement component, before non-routine adjustments, of $1.277 billion
compared to $1.347 billion in 2002. The Alberta System's annual net earnings in
2003 are expected to be lower by approximately $40 million compared to annual
2002 net earnings of $214 million.
The Canadian Mainline's net earnings have decreased $21 million and $18 million
for the three and six months ended June 30, 2003, respectively, when compared to
the corresponding periods in 2002. The decrease in 2003 net earnings as compared
to the 2002 net earnings is mainly due to the NEB's Fair Return decision, which
included an increase in the deemed common equity ratio from 30 to 33 per cent
effective January 1, 2001 and resulted in recognition in June 2002 of $16
million of net earnings for the year ended December 31, 2001. Earnings in 2003
also reflect an increase in the approved rate of return on common equity from
9.53 per cent in 2002 to 9.79 per cent in 2003, partially offset by a lower
average investment base.
The NEB hearing to consider the Canadian Mainline 2003 Tolls and Tariff
Application concluded in May 2003. In this application, TCPL requested approval
of a higher composite depreciation rate, introduction of a new tolling zone in
Southwestern Ontario, an increase to the Interruptible Transportation bid floor
price, and certain cost/efficiency incentive mechanisms. The NEB decision is
anticipated in the third quarter of 2003.
Operating Statistics Alberta Canadian BC
Six months ended June 30 System* Mainline** System
(unaudited) ------ ------ ------ ------
---------------------
2003 2002 2003 2002 2003 2002
------ ------ ------ ------ ------ ------
Average investment base 4,938 5,074 8,659 8,937 238 199
($ millions)
Delivery volumes (Bcf)
Total 1,971 2,054 1,419 1,303 126 181
Average per day 10.9 11.3 7.8 7.2 0.7 1.0
--------------------- ------ ------ ------ ------ ------ ------
*Field receipt volumes for the Alberta System for the six months ended
June 30, 2003 were 1,937 Bcf
(2002 - 2,049 Bcf); average per day was 10.7 Bcf (2002 -
11.3 Bcf).
**Canadian Mainline deliveries originating at the Alberta BORDER="0" and
in Saskatchewan for the six months ended
June 30, 2003 were 1,093 Bcf (2002 - 1,101 Bcf); average per day was 6.0
Bcf (2002 - 6.1 Bcf).
North American Pipeline Ventures
TCPL's proportionate share of net earnings from its other Transmission
businesses was $27 million and $70 million for the three and six months ended
June 30, 2003, respectively. Net earnings were $2 million lower for each of the
second quarter 2003 and six months ended June 30, 2003 compared to the same
periods in 2002.
Earnings for second quarter 2003 were slightly lower than the same quarter in
2002 as a result of a weaker U.S. dollar and higher operating costs in Great
Lakes, partially offset by higher earnings from TransGas de Occidente which is
reported in Other.
The 2002 year-to-date results included TCPL's $7 million share of a favourable
ruling for Great Lakes related to Minnesota use tax paid in prior years.
Excluding the impact of the Great Lakes ruling in 2002, net earnings for the six
months ended June 30, 2003 increased $5 million compared to the same period in
2002. Portland's net earnings have increased $5 million for the six months ended
June 30, 2003 compared to the same period in 2002, primarily as a result of a
rate settlement in early 2003 and a subsequent positive depreciation adjustment
related to 2002 and recorded by TCPL in 2003. These increased earnings were
partially offset by lower earnings from CrossAlta and a weaker U.S. dollar.
Power
Power Results-at-a-Glance
(unaudited) Three months ended Six months ended
June 30 June 30
(millions of dollars) 2003 2002 2003 2002
------------------------ ------- ------- ------- -------
Western operations 60 27 103 61
Northeastern U.S. 36 46 61 87
operations
Bruce Power L.P. 16 - 54 -
investment
Power LP investment 7 8 18 18
General, administrative and (22) (14) (43) (31)
support costs ------- ------- ------- -------
Operating and other 97 67 193 135
income
Financial charges (4) (3) (6) (6)
Income taxes (30) (24) (61) (48)
------- ------- ------- -------
Net earnings 63 40 126 81
------- ------- ------- -------
Power's net earnings of $63 million in second quarter 2003 increased $23 million
compared to $40 million in second quarter 2002. Net earnings of $126 million for
the six months ended June 30, 2003 were $45 million higher when compared to the
same period in 2002. Strong earnings from the recently acquired interest in
Bruce, a settlement in Western Operations for the value of power forward
contracts terminated with a former counterparty and the addition of the ManChief
plant in late 2002 were the primary reasons for the increases. Partially
offsetting these increases were lower earnings from the Northeastern U.S.
Operations and higher general, administrative and support costs.
Operating and other income from Western Operations of $60 million and $103
million for the three and six months ended June 30, 2003 was $33 million and $42
million higher, respectively, compared to the same periods in 2002. The increase
was mainly due to a $31 million pre-tax ($19 million after tax) positive
earnings impact related to a June 2003 settlement with a former counterparty.
This amount reflects the settlement value of the outstanding power forward
contracts that were entered into in the normal course of business, but were
terminated by TCPL as a result of a former counterparty defaulting in 2001 under
power forward contracts. The ManChief acquisition in 2002 also contributed to
higher operating income.
Operating and other income from the Northeastern U.S. Operations of $36 million
and $61 million for the three and six months ended June 30, 2003, decreased $10
million and $26 million, respectively, compared to the same periods in 2002. The
decreases were primarily due to the higher cost of fuel gas at Ocean State
Power, fewer market opportunities in the first half of 2003 than in 2002 and the
unfavourable impact of a weaker U.S. dollar.
Bruce contributed $16 million of pre-tax equity income in second quarter 2003
compared to $38 million in the first quarter 2003. The decrease reflected lower
output as a result of a planned maintenance outage on one of the four Bruce B
reactors and seasonally lower wholesale spot market prices. Overall prices
achieved during the second quarter were $45 per megawatt hour (MWh) compared to
$63 per MWh in the last six weeks in first quarter 2003. A Bruce B unit reactor
returned to service slightly ahead of schedule on June 26, 2003 while the
remaining three Bruce B reactors ran at 100 per cent availability during the
second quarter 2003. TCPL's share of power output for the second quarter 2003
was 1,681 gigawatt hours (GWh) compared to 1,087 GWh for the six week period
ended March 31, 2003.
Excluding the planned outage of the Bruce B unit in second quarter 2003, the
Bruce B units have operated at 100 per cent availability during the entire first
half of 2003, the best performance in the plant's history. Approximately 38 per
cent of the output was sold into Ontario's wholesale spot market with the
remainder being sold under longer term contracts.
The restart of the two Bruce A units has been delayed primarily as a result of
additional safety modifications, documentation and testing necessary to meet
Canadian Nuclear Safety Commission (CNSC) requirements. Once CNSC approval has
been received on the first unit, the reactor will slowly ramp up to full power
and synchronize to the Ontario power grid. The second unit is expected to return
approximately one month later. The cumulative restart cost increased by Bruce to
the end of June 2003 for the two Bruce A units was approximately $610 million.
Bruce has incurred approximately $235 million on the two unit restart program in
the first six months of 2003, being an average of approximately $20 million per
unit per month. TCPL has a 31.6 per cent interest in Bruce.
Equity income from Bruce is directly impacted by fluctuations in wholesale spot
market prices for electricity as well as overall plant availability, which in
turn, is impacted by scheduled and unscheduled maintenance. To reduce its
exposure to spot market prices, Bruce has entered into fixed price sales
contracts for approximately 1,800 megawatts (MW) of output for the remainder of
2003. This represents approximately 57 per cent of the average 3,140 MW of Bruce
B capacity or approximately 38 per cent of the total 4,678 MW capacity including
two Bruce A reactors.
Operating and other income from the investment in TransCanada Power, L.P. for
the three and six months ended June 30, 2003 was consistent with the same
periods in 2002.
General, administrative and support costs for the three and six months ended
June 30, 2003 increased $8 million and $12 million, respectively, compared to
the same periods in 2002, mainly reflecting higher project development costs as
part of the continued investment in Power.
Power Sales Volumes*
(unaudited) Three months ended Six months ended
June 30 June 30
(GWh) 2003 2002 2003 2002
------------------------ ------- ------- ------- -------
Western operations 2,868 2,973 5,693 5,801
Northeastern U.S. operations 1,724 1,423 3,393 2,575
Bruce Power L.P. investment 1,681 - 2,768 -
Power LP investment 457 557 1,022 1,128
------- ------- ------- -------
Total 6,730 4,953 12,876 9,504
------------------------ ------- ------- ------- -------
*Power sales volumes include TCPL's share of Bruce Power L.P. output
(31.6 per cent) and the
Sundance B power purchase arrangement (50 per
cent).
Weighted Average Plant Three months ended Six months
Availability* June 30 ended June
30
(unaudited) 2003 2002 2003 2002
------------------------ ------- ------- ------- -------
Western operations 92% 94% 94% 96%
Northeastern U.S. operations 92% 99% 88% 99%
Bruce Power L.P. investment 77% ** 84% **
Power LP investment 90% 92% 94% 93%
All plants 86% 97% 89% 97%
------------------------ ------- ------- ------- -------
*Plant availability is reduced by planned and unplanned
outages.
**Acquired in February 2003.
Corporate
Net expenses were $5 million and $9 million for the three months ended June 30,
2003 and 2002, respectively. This $4 million decrease in net expenses for second
quarter 2003 is mainly due to the positive impact of foreign exchange rates. Net
expenses were $18 million for the six months ended June 30, 2003 compared to $26
million for the same period in 2002. This $8 million decrease is primarily due
to lower interest costs and the positive impact of foreign exchange rates
compared to the same period in the prior year.
Discontinued Operations
The Board of Directors approved a plan in July 2001 to dispose of the company's
Gas Marketing business. The company's exit from Gas Marketing was substantially
completed by December 31, 2001. The company mitigated its exposure associated
with the contingent liabilities related to the divested gas marketing operations
by obtaining from Mirant Corporation (Mirant) certain remaining contracts in
June and early July 2003 and simultaneously fully hedging the market price
exposures of these contracts. The company remains contingently liable for
certain of the residual obligations.
At June 30, 2003, TCPL reviewed the provision for loss on discontinued
operations, taking into consideration the potential impacts arising from Mirant
filing for bankruptcy protection in July 2003. As a result of this review, TCPL
concluded that the provision was adequate, and the continued deferral of the
approximately $100 million of deferred after-tax gains related to the Gas
Marketing business was appropriate. Accordingly, there was no earnings impact
related to discontinued operations in second quarter 2003.
Liquidity and Capital Resources
Funds Generated from Operations
Funds generated from operations were $891 million for the six months ended June
30, 2003, compared with $893 million for the same period in 2002. Funds
generated from operations of $434 million for second quarter 2003 were
comparable to second quarter 2002.
TCPL expects that its ability to generate sufficient 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 is adequate, and remains substantially
unchanged since December 31, 2002.
Investing Activities
In the three and six months ended June 30, 2003, capital expenditures, excluding
acquisitions, totalled $107 million (2002 - $98 million) and $183 million (2002
- $215 million), respectively, and related primarily to Iroquois' ongoing
Eastchester Expansion project into New York City, maintenance and capacity
capital in wholly-owned pipelines and ongoing construction of the MacKay River
power plant in Alberta. Acquisitions for the six months ended June 30, 2003
totalled $412 million (2002 - nil) and were almost entirely comprised of the
acquisition of a 31.6 per cent interest in Bruce for $376 million plus closing
adjustments.
Financing Activities
TCPL used a portion of its cash resources to fund long-term debt maturities of
$59 million and reduce notes payable by $82 million in the six months ended June
30, 2003. In June 2003, the company issued US$350 million of ten year notes
bearing interest at 4.00 per cent.
In July 2003, TCPL redeemed all of its outstanding US$160 million, 8.75 per cent
Junior Subordinated Debentures, also known as Cumulative Trust Originated
Preferred Securities. Holders of these debentures received US$25.0122 per
US$25.00 of the principal amount, which included accrued and unpaid interest to
the redemption date.
Dividends
On July 25, 2003, TCPL's Board of Directors declared an aggregate quarterly
dividend of $130 million for the quarter ending September 30, 2003 on the
outstanding common shares. This is the 159th consecutive quarterly dividend paid
by TCPL on its common shares, and is payable on October 31, 2003. The Board also
declared regular dividends on TCPL's preferred shares.
Risk Management
With respect to continuing operations, TCPL's market, financial and counterparty
risks remain substantially unchanged since December 31, 2002. See explanation
for discontinued operations' risk management activity under Results of
Operations - Discontinued Operations. For further information on risks, refer to
Management's Discussion and Analysis in TransCanada PipeLines Limited's 2002
Annual Report.
The processes within TCPL's risk management function are designed to ensure that
risks are properly identified, quantified, reported and managed. Risk management
strategies, policies and limits are designed to ensure TCPL's risk-taking is
consistent with its business objectives and risk tolerance. Risks are managed
within limits ultimately established by the Board of Directors and implemented
by senior management, monitored by risk management personnel and audited by
internal audit personnel.
TCPL manages market and financial risk exposures in accordance with its
corporate market risk policy and position limits. The company's primary market
risks result from volatility in commodity prices, interest rates and foreign
currency exchange rates. TCPL's counterparty risk exposure results from the
failure of a counterparty to meet its contractual financial obligations, and is
managed in accordance with its corporate counterparty risk policy.
Controls and Procedures
Within 90 days prior to the filing of this quarterly report, TCPL's management
evaluated the effectiveness of the design and operation of the company's
disclosure controls and procedures (disclosure controls) and internal controls
for financial reporting purposes (internal controls). Based on that evaluation,
the Chief Executive Officer and the Chief Financial Officer have concluded that:
*TCPL's disclosure controls are effective in ensuring that material
information relating to TCPL is made known to management on a timely basis,
and is included in this quarterly report; and
*TCPL's internal controls are effective in providing assurance that the
financial statements for this quarter are fairly presented in accordance
with Canadian generally accepted accounting principles.
To the best of these officers' knowledge and belief, there have been no
significant changes in internal controls or in other factors that could
significantly affect internal controls subsequent to the date on which such
evaluation was completed in connection with this quarterly report.
Critical Accounting Policy
TCPL's critical accounting policy, which remains unchanged since December 31,
2002, is the use of regulatory accounting for its regulated operations. For
further information on this critical accounting policy, refer to Management's
Discussion and Analysis in TransCanada PipeLines Limited's 2002 Annual Report.
Critical Accounting Estimates
Since a determination of many assets, liabilities, revenues and expenses is
dependent upon future events, the preparation of the company's consolidated
financial statements requires the use of estimates and assumptions which have
been made using careful judgment. TCPL's critical accounting estimates, which
remain unchanged since December 31, 2002, are depreciation expense and certain
deferred after-tax gains and remaining obligations related to the Gas Marketing
business. For further information on these critical accounting estimates, refer
to Results of Operations - Discontinued Operations and to Management's
Discussion and Analysis in TransCanada PipeLines Limited's 2002 Annual Report.
Outlook
The company expects higher Power net earnings in 2003 than originally
anticipated as a result of the contribution from Bruce and the settlement with a
former counterparty. The outlook for the company's other segments remains
relatively unchanged since December 31, 2002. For further information on
outlook, refer to Management's Discussion and Analysis in TransCanada PipeLines
Limited's 2002 Annual Report.
The company's earnings and cash flow combined with a strong balance sheet
continue to provide the financial flexibility for TCPL to make disciplined
investments in its core businesses of Transmission and Power. The strengthening
of the Canadian dollar compared to the U.S. dollar in 2003 has not and is not
expected to significantly impact TCPL's consolidated financial results. Credit
ratings on TCPL's senior unsecured debt assigned by Dominion Bond Rating Service
Limited (DBRS), Moody's Investors Service (Moody's) and Standard & Poor's are
currently A, A2 and A-, respectively. On May 9, 2003, Standard & Poor's resolved
its 'Credit Watch' on TCPL by reaffirming it's A- rating of TCPL's senior
unsecured debt and changing the outlook to 'negative'. DBRS and Moody's both
maintain a 'stable' outlook on their ratings.
Other Recent Developments
Transmission
Wholly-Owned Pipelines
Alberta System
On June 24, 2003, the Alberta Energy and Utilities Board (EUB) approved the 2003
Revenue Requirement Settlement and 2003 Tariff Settlement for the Alberta
System. These settlements will form the basis of the Alberta System tolls for
2003. TCPL is committed to filing a 2004 Alberta System General Rate Application
with the EUB by September 30, 2003.
In July 2003, TCPL along with other utilities filed evidence in the EUB's
Generic Cost of Capital Proceeding. The EUB expects to adopt a standardized
approach to determining the rate of return and capital structure for all
utilities under its jurisdiction at the conclusion of this proceeding.
Canadian Mainline
In May 2003, the Federal Court of Appeal granted TCPL leave to appeal the NEB's
decision, issued February 2003, to dismiss TCPL's request for a Review and
Variance of the NEB's June 2002 decision on the company's Fair Return
application. TCPL based its application for leave to appeal on two questions of
law. TCPL is concerned about its ability to obtain a fair return on its
investment in the Canadian Mainline as a result of the NEB's decisions.
North American Pipeline Ventures
Foothills
In May 2003, TCPL signed an agreement to purchase the remaining 50 per cent of
Foothills Pipe Lines Ltd. (Foothills) from Duke Energy Gas Transmission for $257
million, including $152 million of Duke's proportionate share of Foothill's
corporate debt. As a result, TCPL will own 100 per cent of Foothills and its
subsidiaries, subject to regulatory approvals prior to the final closing of this
transaction. Foothills and its subsidiaries hold the certificates to build the
Canadian portion of the Alaska Highway Project which would bring Prudhoe Bay
natural gas from Alaska to markets in Canada and the U.S. The "Prebuild" portion
of this project has been operating for more than 20 years, moving Alberta gas to
U.S. markets in advance of flows from Alaska. Subsidiaries of Foothills and TCPL
also hold certificates to build the Alaskan part of this project. It is
anticipated the purchase will close in third quarter 2003.
Northern Development
In June 2003, TCPL reached funding and participation agreements with the
Mackenzie Delta gas producers and the Aboriginal Pipeline Group (APG) for the
Mackenzie Gas Pipeline Project. The Preliminary Information Package for the
Mackenzie Gas Project has been submitted to relevant regulatory authorities and
regulatory applications are expected to be filed in 2004. Under the agreement,
TCPL has agreed to finance the APG for its one-third share of project definition
phase costs which are currently estimated to be $80 million over three years. If
the pipeline is approved and becomes operational, this loan will be repaid from
APG's share of pipeline revenues.
The producers have agreed to potentially reduce their ownership share of the
pipeline by five per cent, by providing TCPL the option to obtain this interest
at the decision to construct. TCPL will apply for an extension of its Alberta
pipeline system to connect with a Mackenzie Valley Pipeline south of the
Alberta-Northwest Territories Border.
TCPL also gains certain rights of first refusal if any of the producers choose
to sell their equity. TCPL would be entitled to acquire 50 per cent of any
opportunities, with the producers and APG sharing in the other 50 per cent.
Should the pipeline expand beyond its original capacity, and once the APG has
achieved a one-third ownership share, TCPL, the APG and the other owners will
each have the opportunity to obtain a one-third interest in additional
expansions.
Power
In June 2003, TCPL agreed to develop the Becancour Cogeneration Project, a 550
megawatt natural gas-fired cogeneration plant near Trois-Rivieres, Quebec.
Subject to regulatory approvals, construction of the estimated $500 million
facility is expected to begin next year with an in-service date late in 2006.
This plant will supply its entire power output to Hydro-Quebec Distribution
under a 20-year power purchase contract. The plant will also supply steam to
certain major businesses located within the Becancour Industrial Park.
Forward-Looking Information
Certain information in this quarterly report is forward-looking and is subject
to important risks and uncertainties. The results or events predicted in this
information may differ from actual results or events. 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, competitive factors in the pipeline and power industry sectors, and
the prevailing economic conditions in North America. For additional information
on these and other factors, see the reports filed by TCPL with Canadian
securities regulators and with the United States Securities and Exchange
Commission. TCPL disclaims any intention or obligation to update or revise any
forward-looking statements, whether as a result of new information, future
events or otherwise.
Consolidated Income
(unaudited) Three months ended Six months ended
June 30 June 30
(millions of dollars) 2003 2002 2003 2002
--------------------- --------- -------- -------- --------
Revenues 1,311 1,345 2,647 2,591
Operating Expenses
Cost of sales 189 170 369 303
Other costs and expenses 382 383 809 737
Depreciation 217 213 432 420
--------- -------- -------- --------
788 766 1,610 1,460
--------- -------- -------- --------
Operating Income 523 579 1,037 1,131
Other Expenses/(Income)
Financial charges 205 218 409 439
Financial charges of joint 23 22 45 45
ventures
Equity income (26) (8) (84) (18)
Interest and other income (22) (11) (35) (22)
--------- -------- -------- --------
180 221 335 444
--------- -------- -------- --------
Income before Income Taxes 343 358 702 687
Income Taxes - Current and 127 138 263 266
Future --------- -------- -------- --------
Net Income 216 220 439 421
Preferred Securities Charges 9 9 18 18
Preferred Share Dividends 5 6 11 11
--------- -------- -------- --------
Net Income Applicable to Common 202 205 410 392
Shares --------- -------- -------- --------
See accompanying Notes to the Consolidated Financial
Statements.
Consolidated Cash Flows
(unaudited) Three months ended Six months
June 30 ended June 30
(millions of dollars) 2003 2002 2003 2002
--------------------------- -------- -------- -------- --------
Cash Generated From Operations
Net income 216 220 439 421
Depreciation 217 213 432 420
Future income taxes 53 56 127 109
Equity income in excess of (8) (1) (59) (5)
distributions received
Other (44) (50) (48) (52)
-------- -------- -------- --------
Funds generated from operations 434 438 891 893
Decrease/(Increase) in operating 33 (2) 25 (56)
working capital -------- -------- -------- --------
Net cash provided by continuing 467 436 916 837
operations
Net cash (used in)/provided by (88) (7) (84) 51
discontinued operations -------- -------- -------- --------
379 429 832 888
-------- -------- -------- --------
Investing Activities
Capital expenditures (107) (98) (183) (215)
Acquisitions, net of cash acquired (3) - (412) -
Disposition of assets - - 5 -
Deferred amounts and other (47) (91) (70) (74)
-------- -------- -------- --------
Net cash used in investing (157) (189) (660) (289)
activities -------- -------- -------- --------
Financing Activities
Dividends and preferred securities (149) (140) (288) (267)
charges
Notes payable repaid, net (291) (69) (82) (240)
Long-term debt issued 475 - 475 -
Reduction of long-term debt (50) (24) (59) (116)
Non-recourse debt of joint ventures 29 4 46 5
issued
Reduction of non-recourse debt of (32) (29) (48) (42)
joint ventures
Common shares issued 2 16 18 31
-------- -------- -------- --------
Net cash (used in)/provided by (16) (242) 62 (629)
financing activities -------- -------- -------- --------
Increase/(Decrease) in Cash and 206 (2) 234 (30)
Short-Term Investments
Cash and Short-Term Investments
Beginning of period 240 271 212 299
-------- -------- -------- --------
Cash and Short-Term Investments
End of period 446 269 446 269
-------- -------- -------- --------
See accompanying Notes to the Consolidated
Financial Statements.
Consolidated Balance Sheet
June 30, December
2003 31,
(millions of dollars) (unaudited) 2002
------------------------------- ----------- -----------
ASSETS
Current Assets
Cash and short-term investments 446 212
Accounts receivable 604 691
Inventories 168 178
Other 101 102
----------- -----------
1,319 1,183
Long-Term Investments 713 291
Plant, Property and Equipment 16,975 17,496
Other Assets 996 946
----------- -----------
20,003 19,916
----------- -----------
------------------------------- ----------- -----------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Notes payable 215 297
Accounts payable 789 902
Accrued interest 206 227
Current portion of long-term debt 580 517
Current portion of non-recourse debt of joint 20 75
ventures
Provision for loss on discontinued 217 234
operations ----------- -----------
2,027 2,252
Deferred Amounts 326 353
Long-Term Debt 8,983 8,815
Future Income Taxes 318 226
Non-Recourse Debt of Joint Ventures 1,174 1,222
Junior Subordinated Debentures 239 238
----------- -----------
13,067 13,106
----------- -----------
Shareholders' Equity
Preferred securities 673 674
Preferred shares 389 389
Common shares 4,632 4,614
Contributed surplus 266 265
Retained earnings 1,005 854
Foreign exchange adjustment (29) 14
----------- -----------
6,936 6,810
----------- -----------
20,003 19,916
----------- -----------
See accompanying Notes to the Consolidated
Financial Statements.
Consolidated Retained Earnings
(unaudited) Six months ended June 30
(millions of dollars) 2003 2002
--------------------- -------- --------
Balance at beginning of period 854 586
Net income 439 421
Preferred securities charges (18) (18)
Preferred share dividends (11) (11)
Common share dividends (259) (239)
-------- --------
1,005 739
-------- --------
See accompanying Notes to the Consolidated Financial Statements.
Notes to Consolidated Financial Statements
(Unaudited)
1. Basis of Presentation
Pursuant to a plan of arrangement, effective May 15, 2003, common shares of
TransCanada PipeLines Limited (TCPL or the company) were exchanged on a
one-to-one basis for common shares of TransCanada Corporation (TransCanada).
As a result, TCPL became a wholly-owned subsidiary of TransCanada. The
consolidated financial statements for the six months ended June 30, 2003
include the accounts of TCPL and the consolidated accounts of all its
subsidiaries.
2. Significant Accounting Policies
The consolidated financial statements of TCPL have been prepared in
accordance with Canadian generally accepted accounting principles. The
accounting policies applied are consistent with those outlined in the
company's annual financial statements for the year ended December 31, 2002.
These consolidated financial statements reflect all normal recurring
adjustments that are, in the opinion of management, necessary to present
fairly the financial position and results of operations for the respective
periods. These consolidated financial statements do not include all
disclosures required in the annual financial statements and should be read
in conjunction with the annual financial statements included in TransCanada
PipeLines Limited's 2002 Annual Report. Amounts are stated in Canadian
dollars unless otherwise indicated. Certain comparative figures have been
reclassified to conform with the current period's presentation.
Since a determination of many assets, liabilities, revenues and expenses is
dependent upon future events, the preparation of these consolidated
financial statements requires the use of estimates and assumptions. In the
opinion of Management, these consolidated financial statements have been
properly prepared within reasonable limits of materiality and within the
framework of the company's significant accounting policies.
3. Segmented Information
Transmission Power Corporate Total
Three months ended 2003 2002 2003 2002 2003 2002 2003 2002
June 30 (unaudited - ---- ----- ----- ----- ----- ----- ----- -----
millions of dollars)
---- ----- ----- ----- ----- ----- ----- -----
Revenues 944 1,002 367 343 - - 1,311 1,345
Cost of sales - - (189) (170) - - (189) (170)
Other costs and (301) (286) (79) (95) (2) (2) (382) (383)
expenses
Depreciation (195) (198) (22) (15) - - (217) (213)
---- ----- ----- ----- ----- ----- ----- -----
Operating income 448 518 77 63 (2) (2) 523 579
/(loss)
Financial and (194) (208) (3) (3) (22) (22) (219) (233)
preferred equity
charges
Financial (22) (22) (1) - - - (23) (22)
charges of joint
ventures
Equity income 10 8 16 - - - 26 8
Interest and 3 - 4 4 15 7 22 11
other income
Income taxes (101) (122) (30) (24) 4 8 (127) (138)
---- ----- ----- ----- ----- ----- ----- -----
Net Income 144 174 63 40 (5) (9) 202 205
Applicable to
---- ----- ----- ----- ----- ----- ----- -----
Common Shares
Transmission Power Corporate Total
Six months ended 2003 2002 2003 2002 2003 2002 2003 2002
June 30 (unaudited - ---- ----- ----- ----- ----- ----- ----- -----
millions of dollars)
---- ----- ----- ----- ----- ----- ----- -----
Revenues 1,904 1,943 743 648 - - 2,647 2,591
Cost of sales - - (369) (303) - - (369) (303)
Other costs and (605) (546) (200) (187) (4) (4) (809) (737)
expenses
Depreciation (389) (390) (43) (30) - - (432) (420)
---- ----- ----- ----- ----- ----- ----- -----
Operating income 910 1,007 131 128 (4) (4) 1,037 1,131
/(loss)
Financial and (390) (414) (5) (6) (43) (48) (438) (468)
preferred equity
charges
Financial (44) (45) (1) - - - (45) (45)
charges of joint
ventures
Equity income 30 18 54 - - - 84 18
Interest and 8 6 8 7 19 9 35 22
other income
Income taxes (212) (235) (61) (48) 10 17 (263) (266)
---- ----- ----- ----- ----- ----- ----- -----
Net Income 302 337 126 81 (18) (26) 410 392
Applicable to
---- ----- ----- ----- ----- ----- ----- -----
Common Shares
Total Assets June 30, December
2003 31,
(millions of (unaudited) 2002
dollars) ---------- ---------
-------
Transmission 16,363 16,979
Power 2,608 2,292
Corporate 853 457
---------- ---------
Continuing 19,824 19,728
Operations
Discontinued 179 188
Operations ---------- ---------
20,003 19,916
---------- ---------
4. Long-Term Debt
On June 9, 2003, the company issued US$350 million of unsecured 4.00 per
cent notes maturing on June 15, 2013.
On July 3, 2003, the company redeemed the US$160 million 8.75 per cent
Junior Subordinated Debentures. Holders of these debentures received
US$25.0122 per US$25.00 of the principal amount, which included accrued and
unpaid interest to the redemption date, without premium or penalty.
5. Risk Management and Financial Instruments
The following represents the significant changes to the company's risk
management and financial instruments since December 31, 2002.
Foreign Investments
At June 30, 2003 and December 31, 2002, the company had foreign currency
denominated assets and liabilities which created an exposure to changes in
exchange rates. The company uses foreign currency derivatives to hedge this
exposure on an after-tax basis. The cross-currency swaps have a floating
interest rate which the company partially hedges by entering into interest
rate swaps and forward rate agreements. The company's portfolio of foreign
investment derivatives is comprised of contracts for periods up to four
years. The fair values shown in the table below for foreign exchange risk
are offset by translation gains or losses on the net assets and are recorded
in the foreign exchange adjustment in Shareholders' Equity.
Asset/(Liability) June 30, 2003
(millions of dollars) (unaudited) December 31, 2002
------------------------- -------------- ----------------
Carrying Fair Carrying Fair
Amount Value Amount Value
-------- -------- -------- --------
Foreign Exchange Risk
Cross-currency swaps
U.S. dollars 50 50 (8) (8)
Forward foreign exchange
contracts
U.S. dollars - - (4) (4)
------------------------- -------- -------- ---- -------- --------
At June 30, 2003, the notional principal amounts of cross-currency swaps
were US$250 million (December 31, 2002 - US$350 million) and the notional
principal amounts of forward foreign exchange contracts were nil (December
31, 2002 - US$225 million).
Reconciliation of Foreign Exchange June 30, December
Adjustment 2003 31,
(millions of dollars) (unaudited) 2002
----------------------------- --------- --------
Balance at beginning of year 14 13
Translation (losses)/gains on foreign (115) 3
currency denominated net assets
Foreign exchange gains/(losses) on 72 (2)
derivatives, and other --------- --------
(29) 14
----------------------------- --------- --------
6. Discontinued Operations
In July 2001, the Board of Directors approved a plan to dispose of the
company's Gas Marketing business. In December 1999, the Board of Directors
approved a plan (December Plan) to dispose of the company's International,
Canadian Midstream and certain other businesses. The company's disposals
under both plans were substantially completed at December 31, 2001.
The company mitigated its exposures associated with the contingent
liabilities related to the divested gas marketing operations by obtaining
certain remaining contracts in June and early July 2003 and simultaneously
fully hedging the market price exposures of these contracts. The company
remains contingently liable for certain of the residual obligations.
At June 30, 2003, TCPL reviewed the provision for loss on discontinued
operations and concluded that the provision was adequate and the continued
deferral of the approximately $100 million of deferred after-tax gains
related to the Gas Marketing business was appropriate. Accordingly, there
was no earnings impact related to discontinued operations in second quarter
2003.
Net income from discontinued operations was nil for the three and six months
ended June 30, 2003 and 2002. The provision for loss on discontinued
operations at June 30, 2003 was $217 million (December 31, 2002 - $234
million). The net assets of discontinued operations included in the
consolidated balance sheet at June 30, 2003 were $142 million (December 31,
2002 - $90 million).
7. Commitment
On June 18, 2003, an agreement was reached among the Mackenzie Delta gas
producers, the Aboriginal Pipeline Group (APG) and TCPL which governs TCPL's
role in the Mackenzie Gas Pipeline Project. The Mackenzie Gas Pipeline Project
would, if approved, result in a natural gas pipeline being constructed from
Inuvik, Northwest Territories to the northern BORDER="0" of Alberta, where it
would then connect with the Alberta System. Under the agreement, TCPL has agreed
to finance the APG for its one-third share of project definition phase costs
which are currently estimated to be $80 million over three years. If the
pipeline is approved and becomes operational, this loan will be repaid from
APG's share of pipeline revenues.
TransCanada welcomes questions from preferred shareholders and potential
investors. Please telephone:
Investor Relations, at 1-800-361-6522 (Canada and U.S. Mainland) or
direct dial David Moneta/Debbie Persad at (403) 920-7911. The investor
fax line is (403) 920-2457. Media Relations: Glenn Herchak/Hejdi Feick
at (403) 920-7877.
Visit TransCanada's Internet site at: http://www.transcanada.com
This information is provided by RNS
The company news service from the London Stock Exchange
END
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