RNS Number:2268S
TransCanada Pipelines Ld
18 November 2003
TRANSCANADA PIPELINES LIMITED
THIRD QUARTER 2003
Quarterly Report
Consolidated Results-at-a-Glance
(unaudited) Three months ended September 30 Nine months ended September 30
(millions of dollars) 2003 2002 2003 2002
Net Income Applicable to Common Shares
Continuing operations 198 175 608 567
Discontinued operations 50 - 50 -
248 175 658 567
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 nine months ended September 30,
2003 and the notes thereto.
Results of Operations
Consolidated
TCPL's net income applicable to common shares for third quarter 2003 was $248
million. This includes net income from discontinued operations which reflects
the income recognition of $50 million of the initially deferred gain of
approximately $100 million after tax relating to the 2001 disposition of the
company's Gas Marketing business.
Net income applicable to common shares from continuing operations (net earnings)
for third quarter 2003 of $198 million increased by $23 million compared to $175
million for third quarter 2002. All segments of the company contributed to the
increase. Higher net earnings from the Power business included $26 million
after tax from TCPL's investment in Bruce Power L.P. (Bruce Power), partially
offset by lower operating and other income from Power's Western Operations.
Higher net earnings in the Transmission business were mainly due to TCPL's $11
million share of future income tax benefits recognized by TransGas de Occidente,
partially offset by lower net earnings from the Alberta System.
TCPL's net income applicable to common shares for the nine months ended
September 30, 2003 was $658 million after reflecting net income from
discontinued operations of $50 million compared to $567 million for the
comparable period in 2002.
TCPL's net earnings applicable to common shares from continuing operations for
the nine months ended September 30, 2003 was $608 million compared to $567
million for the comparable period in 2002. The increase of $41 million in the
first nine months of 2003 compared to the same period in 2002 was primarily due
to higher net earnings from the Power business and lower net expenses in the
Corporate segment, partially offset by lower net earnings from the Transmission
segment.
The Power segment net earnings for the nine months ended September 30, 2003
included $66 million after tax from TCPL's investment in Bruce Power 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 the counterparty's default. These
increases are partially offset by reduced operating and other income from the
Northeastern U.S. Operations, combined with higher general, administrative and
support costs.
The decrease in 2003 year-to-date net expenses in the Corporate segment compared
to the same period in the prior year was primarily due to lower general and
administrative expenses related to services that support discontinued
operations, lower net interest costs and the positive impact of foreign exchange
rates.
The lower net earnings in the Transmission segment for the nine months ended
September 30, 2003 compared to the same period in the prior year 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 nine months ended
September 30, 2002 included after-tax income of $30 million representing the
impact of the Fair Return decision for 2001 ($16 million) and nine months ended
September 30, 2002 ($14 million). The results for the nine months ended
September 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.
Funds generated from continuing operations of $516 million for third quarter
2003 increased $49 million compared to third quarter 2002. Funds generated from
continuing operations of $1,407 million for the nine months ended September 30,
2003 increased $47 million compared to the same period last year.
Segment Results-at-a-Glance
(unaudited) Three months ended September 30 Nine months ended September 30
(millions of dollars) 2003 2002 2003 2002
Transmission 160 154 462 491
Power 50 35 176 116
Corporate (12) (14) (30) (40)
Continuing operations 198 175 608 567
Discontinued operations 50 - 50 -
Net Income Applicable to Common Shares 248 175 658 567
Transmission
The Transmission business generated net earnings of $160 million and $462
million for the three and nine months ended September 30, 2003, respectively,
compared to $154 million and $491 million for the same periods in 2002.
Transmission Results-at-a-Glance
(unaudited) Three months ended September 30 Nine months ended September 30
(millions of dollars) 2003 2002 2003 2002
Wholly-Owned Pipelines
Alberta System 50 56 136 158
Canadian Mainline 73 72 215 232
Foothills* 5 4 14 13
BC System - 1 4 4
128 133 369 407
North American Pipeline Ventures
Great Lakes 10 13 38 49
Iroquois 4 4 15 15
TC PipeLines, LP 4 4 11 12
Portland - - 7 2
Ventures LP 3 2 7 5
Trans Quebec & Maritimes 2 2 6 6
CrossAlta - 2 4 9
TransGas de Occidente 13 3 20 5
Northern Development (1) (3) (2) (5)
General, administrative, support and
other (3) (6) (13) (14)
32 21 93 84
Net earnings 160 154 462 491
* The remaining interests in Foothills, previously not held by TCPL, were
acquired in August 2003. Amounts in this table reflect TCPL's proportionate
interest in Foothills' earnings prior to the acquisition and 100 per cent
interest thereafter.
Wholly-Owned Pipelines
The Alberta System's net earnings of $50 million in third quarter 2003 decreased
$6 million compared to $56 million in the same quarter of 2002. Net earnings of
$136 million for the nine months ended September 30, 2003 decreased $22 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, initially expected to be approximately $40 million lower than
2002 annual net earnings of $214 million, are now expected to be approximately
$30 million below 2002 net earnings. This improved outlook for 2003 net
earnings is primarily attributable to lower financing and operating costs than
initially anticipated.
The Canadian Mainline's net earnings have increased $1 million and decreased $17
million for the three and nine months ended September 30, 2003, respectively,
when compared to the corresponding periods in 2002. The decrease in
year-to-date 2003 net earnings as compared to net earnings in the same period in
2002 is mainly due to the NEB's Fair Return decision, which resulted in the
recognition in June 2002 of $16 million of net earnings related to the year
ended December 31, 2001. Net earnings in 2003 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, offset by a lower average investment base.
In December 2002, the NEB approved TCPL's application to charge interim tolls
for transportation service, effective January 1, 2003. In August 2003, the NEB
approved interim tolls that the company will charge for the period September 1,
2003 to December 31, 2003. The NEB ordered that tolls will remain interim
pending a decision from the Federal Court of Appeal on TCPL's Fair Return Review
and Variance Application.
On August 15, 2003, TCPL acquired the remaining interests of Foothills Pipe
Lines Ltd. (Foothills) and its subsidiaries from Duke Energy Gas Transmission
(Duke) for $259 million, including assumption of $154 million of Duke's
proportionate share of Foothills' corporate debt. The net earnings prior to the
acquisition reflect TCPL's previous interests in Foothills. Prior to the
acquisition, TCPL directly and indirectly owned 50 per cent of Foothills, 69.5
per cent of Foothills (Sask.), 74.5 per cent of Foothills (Alta.) and 74.5 per
cent of Foothills (South B.C.).
Operating Statistics
Nine months ended September 30 Alberta Canadian BC
(unaudited) System* Mainline** Foothills*** System
2003 2002 2003 2002 2003 2002 2003 2002
Average investment base ($ 4,909 5,089 8,601 8,909 742 *** 237 204
millions)
Delivery volumes (Bcf)
Total 2,893 3,076 1,990 1,950 813 *** 227 270
Average per day 10.6 11.3 7.3 7.1 3.0 *** 0.8 1.0
* Field receipt volumes for the Alberta System for the nine months ended
September 30, 2003 were 2,926 Bcf (2002 - 3,094 Bcf); average per day was 10.7
Bcf (2002 - 11.3 Bcf).
** Canadian Mainline deliveries originating at the Alberta border and in
Saskatchewan for the nine months ended September 30, 2003 were 1,572 Bcf (2002 -
1,665 Bcf); average per day was 5.8 Bcf (2002 - 6.1 Bcf).
*** The remaining interests in Foothills were acquired in August 2003. The
year-to-date 2003 delivery volumes in the table represent 100 per cent of
Foothills.
North American Pipeline Ventures
TCPL's proportionate share of net earnings from its other Transmission
businesses was $32 million and $93 million for the three and nine months ended
September 30, 2003, respectively.
Net earnings for third quarter 2003 were $11 million higher than the same
quarter in 2002 primarily as a result of TCPL's $11 million share of future
income tax benefits recognized by TransGas de Occidente. In addition, there
were higher operating earnings from Ventures LP, and lower spending on Northern
Development. These increases were partially offset by lower contributions from
CrossAlta, higher operating costs in Great Lakes and the impact of a weaker U.S.
dollar.
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
nine months ended September 30, 2003 increased $16 million compared to the same
period in 2002. TCPL's share of Portland's net earnings has increased $5 million
for the nine months ended September 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.
In addition, earnings from TransGas de Occidente were higher as a result of
higher contractual tolls and recognition of future income tax benefits. These
increases were offset by lower earnings from CrossAlta and a weaker U.S. dollar.
Power
Power Results-at-a-Glance
(unaudited) Three months ended September 30 Nine months ended September 30
(millions of dollars) 2003 2002 2003 2002
Western operations 26 40 129 101
Northeastern U.S. operations 30 27 91 114
Bruce Power L.P. investment 38 - 92 -
Power LP investment 8 9 26 27
General, administrative and support
costs (23) (17) (66) (48)
Operating and other income 79 59 272 194
Financial charges (2) (3) (8) (9)
Income taxes (27) (21) (88) (69)
Net earnings 50 35 176 116
Power's net earnings of $50 million in third quarter 2003 increased $15 million
compared to $35 million in third quarter 2002. Earnings from the recently
acquired interest in Bruce Power was the primary reason for the increase.
Partially offsetting this increase was a lower contribution from Western
Operations and higher general, administrative and support costs.
Net earnings of $176 million for the nine months ended September 30, 2003 were
$60 million higher when compared to the same period in 2002. Bruce Power
earnings, a settlement in second quarter 2003 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
increase. Partially offsetting the increase were lower earnings from the
Northeastern U.S. Operations and higher general, administrative and support
costs.
Western Operations
Operating and other income in Western Operations for the three months ended
September 30, 2003 of $26 million was $14 million lower compared to the same
period in 2002. The decrease is due to lower prices achieved on power sales as
well as higher cost of natural gas fuel at the carbon black facility in southern
Alberta in 2003, partially offset by contribution from the ManChief plant.
Operating and other income in Western Operations for the nine months ended
September 30, 2003 of $129 million was $28 million higher compared to the same
period in 2002, 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 which defaulted in 2001 under power forward contracts. The
ManChief acquisition in 2002 also contributed to higher operating income.
Partially offsetting these increases were the effects in 2003 of lower prices
achieved on the overall sale of power and higher cost of natural gas fuel at the
carbon black facility.
Northeastern U.S. Operations
Operating and other income in Northeastern U.S. Operations of $30 million for
the three months ended September 30, 2003 increased $3 million compared to the
same period in 2002 primarily due to increased water flows through the Curtis
Palmer hydroelectric facility.
Operating and other income in Northeastern U.S. Operations of $91 million for
the nine months ended September 30, 2003 decreased $23 million compared to the
same period in 2002 primarily due to the higher cost of natural gas fuel at
Ocean State Power (OSP) resulting from an arbitration process, fewer market
opportunities in the first half of 2003 than in 2002 and the unfavourable impact
of a weaker U.S. dollar. OSP is currently in discussions with its natural gas
fuel supplier regarding changes to the price of its fuel supply.
Bruce Power L.P. Investment
Bruce Power L.P. (100 per cent basis) Three months Nine months ended
(unaudited) ended September September 30, 2003
(millions of dollars) 30, 2003
Revenues 297 939
Operating expenses 196 599
Operating income 101 340
Financial charges 17 49
Income before income taxes 84 291
TCPL's interest in Bruce Power income before income taxes* 27 66
Adjustments** 11 26
TCPL's income from Bruce Power before income taxes 38 92
* TCPL acquired its interest in Bruce Power on February 14, 2003. Bruce Power's
100 per cent income before income taxes from February 14 to September 30, 2003
was $210 million.
** See Note 7 to the September 30, 2003 financial statements for an explanation
of the purchase price amortizations.
Bruce Power contributed $38 million of pre-tax equity income in third quarter
2003 compared to $16 million in second quarter 2003. The increase reflected
higher output compared to the second quarter 2003 when one of the Bruce B units
was on a planned maintenance outage for almost the entire second quarter.
Overall prices achieved during third quarter 2003 were $45 per megawatt hour
(MWh) which is consistent with second quarter 2003. The average price achieved
for the nine months ended September 30, 2003 was approximately $49 per MWh.
Approximately 34 per cent of the output was sold into Ontario's wholesale spot
market in third quarter 2003 with the remainder being sold under longer term
contracts.
TCPL's share of power output for third quarter 2003 was 2,041 gigawatt hours
(GWh) compared to 1,681 GWh in second quarter 2003. The Bruce B units ran at an
average availability of 94 per cent for third quarter 2003. The average
availability during TCPL's period of ownership ending September 30, 2003 was 88
per cent.
On October 7, 2003, Bruce A Unit 4 began producing electricity to the Ontario
electricity grid. After performing and evaluating tests of the shutdown system,
Bruce A Unit 4 is expected to reconnect to the grid and will begin ramping up to
full power. Bruce Power is also working towards the removal of the Canadian
Nuclear Safety Commission shutdown guarantees on Bruce A Unit 3. Following
removal of the shutdown guarantees, Bruce A Unit 3 will undergo similar
commissioning tests and procedures as with Bruce A Unit 4. The cumulative
restart cost incurred by Bruce Power to the end of September 2003 for the two
Bruce A units was approximately $688 million. Bruce Power has incurred
approximately $315 million on the two unit restart program in the first nine
months of 2003, of which $80 million was incurred in third quarter 2003. TCPL
has a 31.6 per cent interest in Bruce Power.
Equity income from Bruce Power 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. Bruce B Unit 8
began scheduled maintenance on September 20, 2003 which is expected to continue
into the middle of fourth quarter 2003. To reduce its exposure to spot market
prices, Bruce Power has entered into fixed price sales contracts for
approximately 1,850 megawatts (MW) of output for the remainder of 2003.
Power LP Investment
Operating and other income of $8 million and $26 million for the three and nine
months ended September 30, 2003, was consistent with the same periods in 2002.
General, Administrative and Support Costs
General, administrative and support costs for the three and nine months ended
September 30, 2003 increased $6 million and $18 million, respectively, compared
to the same periods in 2002, mainly reflecting higher support costs as part of
the company's continued investment in Power.
Power Sales Volumes*
(unaudited) Three months ended September 30 Nine months ended September 30
(GWh) 2003 2002 2003 2002
Western operations 3,068 2,876 9,324 9,201
Northeastern U.S. operations 1,719 1,542 5,112 4,117
Bruce Power L.P. investment** 2,041 n/a 4,809 n/a
Power LP investment 582 651 1,604 1,779
Total 7,410 5,069 20,849 15,097
* 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).
** Acquired in February 2003. Sales volumes reflect TCPL's share for the period
February 14, 2003 to September 30, 2003.
Weighted Average Plant Availability* Three months ended September 30 Nine months ended September 30
(unaudited) 2003 2002 2003 2002
Western operations 91% 98% 93% 97%
Northeastern U.S. operations 99% 99% 92% 99%
Bruce Power L.P. investment** 94% n/a 88% n/a
Power LP investment 99% 98% 95% 94%
All plants 96% 99% 91% 97%
* Plant availability is reduced by planned and unplanned outages.
** Acquired in February 2003. TCPL's availability reflects the period February
14, 2003 to September 30, 2003 and refers only to the Bruce B units.
Corporate
Net expenses were $12 million and $14 million for the three months ended
September 30, 2003 and 2002, respectively. This $2 million decrease in net
expenses for third quarter 2003 is mainly due to lower general and
administrative expenses related to services that support discontinued
operations.
Net expenses were $30 million for the nine months ended September 30, 2003
compared to $40 million for the same period in 2002. This $10 million decrease
is primarily due to lower general and administrative expenses related to
services that support discontinued operations, lower net 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 exposures associated
with the contingent liabilities related to the divested gas marketing operations
by obtaining from a subsidiary of Mirant Corporation (Mirant) certain remaining
contracts in June and July 2003, and simultaneously hedging the market price
exposures of these contracts. The company remains contingently liable for
certain residual obligations.
At September 30, 2003, TCPL reviewed the provision for loss on discontinued
operations and the deferred gain, taking into consideration the impacts of
Mirant's filing for bankruptcy protection in July 2003 and the mitigation of the
contingent liabilities referred to above. As a result of this review, $50
million of the original approximately $100 million after-tax deferred gain was
recognized in income in third quarter 2003. In addition, TCPL concluded that
the remaining provision was adequate, and the deferral of the remaining
approximately $50 million of deferred after-tax gains related to the divested
Gas Marketing business was appropriate.
Liquidity and Capital Resources
Funds Generated from Operations
Funds generated from continuing operations were $516 million and $1,407 million
for the three and nine months ended September 30, 2003, respectively, compared
with $467 million and $1,360 million for the same periods in 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 nine months ended September 30, 2003, capital expenditures,
excluding acquisitions, totalled $81 million (2002 - $182 million) and $264
million (2002 - $397 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 nine months ended September 30, 2003 totalled $547 million
(2002 - $19 million) and were primarily comprised of:
* in third quarter 2003, the acquisition of the remaining interests in
Foothills for approximately $105 million,
* in third quarter 2003, the increase in interest in Portland Natural Gas
Transmission System (PNGTS) to 43.42 per cent for approximately US$19.3
million, and
* in first quarter 2003, the acquisition of a 31.6 per cent interest in
Bruce Power for approximately $409 million including closing adjustments.
In addition, TCPL assumed $154 million of debt on the Foothills acquisition.
Financing Activities
TCPL used a portion of its cash resources to fund long-term debt maturities of
$386 million in the nine months ended September 30, 2003. In June 2003, the
company issued U.S. $350 million of ten year notes bearing interest at 4.00 per
cent. For the nine months ended September 30, 2003, outstanding notes payable
increased by $279 million, while cash and short-term investments also increased
by $195 million.
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 October 28, 2003, TCPL's Board of Directors declared a dividend for the
quarter ending December 31, 2003 in an aggregate amount equal to the aggregate
quarterly dividend to be paid on January 30, 2004 by TransCanada Corporation on
its issued and outstanding common shares as at the close of business on December
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
As of the end of the period covered by this quarterly report, TCPL's management
together with TCPL's President and Chief Executive Officer and Chief Financial
Officer evaluated the effectiveness of the design and operation of the company's
disclosure controls and procedures. Based on this evaluation, the President and
Chief Executive Officer and the Chief Financial Officer of TCPL have concluded
that the disclosure controls and procedures are effective.
There were no changes in TCPL's internal control over financial reporting during
the most recent fiscal quarter that have materially affected or are reasonably
likely to materially affect TCPL's internal control over financial reporting.
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 from
December 31, 2002 continue to be 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 Power and the settlement
with a former counterparty. The outlook for the Alberta System has improved
since December 2002 as discussed under Results of Operations in the Transmission
segment. 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 net 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. DBRS and Moody's both maintain a '
stable' outlook on their ratings and Standard & Poor's maintains a 'negative'
outlook on its rating.
Other Recent Developments
Transmission
Wholly-Owned Pipelines
Alberta System
In July 2003, TCPL, along with other utilities, filed evidence in the Generic
Cost of Capital Proceeding with the Alberta Energy and Utilities Board (EUB).
TCPL has requested a return on capital of 11 per cent based on a deemed common
equity of 40 per cent in its Generic Cost of Capital Application. 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. This hearing is scheduled to commence on November 12, 2003.
In September 2003, TCPL filed with the EUB the first phase of the 2004 General
Rate Application (GRA), consisting of evidence in support of the applied for
rate base and revenue requirement. In the GRA, the company applied for a
composite depreciation rate of 4.13 per cent compared to the current
depreciation rate of 4.00 per cent. An EUB hearing to consider the 2004 GRA
Phase One application is scheduled to commence on March 16, 2004 in Calgary.
Phase Two of the application, dealing primarily with rate design and services,
is expected to be filed with the EUB on November 14, 2003.
Canadian Mainline
In July 2003, the NEB issued its decision on TCPL's 2003 Mainline Tolls
Application. In this decision, the NEB approved all key components of the
application including an increase in the composite depreciation rate from 2.89
per cent to 3.42 per cent, introduction of a new tolling zone in southwestern
Ontario, an increase to the Interruptible Transportation bid floor price and
continuation of the Fuel Gas Incentive Program. The rates included in this
decision are still considered interim pending the disposition of TCPL's appeal
to the Federal Court of Appeal regarding the NEB's Review and Variance
(RH-R-1-2002) decision.
In July 2003, TCPL filed a notice of appeal with the Federal Court of Appeal and
served notice of appeal on interested parties of the Review and Variance
application. The case is expected to be heard in an oral hearing late this year
or in the first quarter of 2004.
Foothills
In August 2003, TCPL completed its purchase of the remaining interests of
Foothills and its subsidiaries from Duke for $259 million, including assumption
of $154 million of Duke's proportionate share of Foothills' corporate debt. As
a result, TCPL now owns 100 per cent of Foothills and its subsidiaries.
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 United States. 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 section of this project.
North American Pipeline Ventures
Portland
In third quarter 2003, TCPL exercised its contractual right to increase its
ownership interest in PNGTS to 43.42 per cent from 33.29 per cent. On September
29, 2003, the additional interest was purchased from DTE East Coast Pipelines
Company for approximately US$47.1 million, including approximately US$27.8
million of assumed debt.
On October 18, 2003, TCPL entered into an agreement to acquire El Paso
Corporation's (El Paso) 29.64 per cent interest in PNGTS for approximately
US$137.2 million, including approximately US$80.7 million of assumed debt. The
transaction is expected to be completed by the end of this year and is subject
to the satisfaction of various closing conditions including the right of first
offer provisions.
Under the terms of the PNGTS partnership agreement, the other PNGTS partner, Gaz
Metropolitain and Company, Limited Partnership (Gaz Metropolitain), has the
right to acquire its pro rata share of El Paso's offered interest. This right is
exercisable for a period of thirty days after receipt of formal notice from El
Paso. Should this right of first offer not be exercised, TCPL' s interest in
Portland will increase to 73.06 per cent from 43.42 per cent. Should Gaz
Metropolitain's right of first offer be exercised, TCPL's total interest will
increase to 61.71 per cent. The purchase price paid by TCPL would be reduced
proportionately.
PNGTS operates a 471 kilometer, 220 million cubic feet per day interstate
natural gas pipeline which connects with the Trans Quebec & Maritimes Pipeline
(50 per cent owned by TCPL) near Pittsburg, New Hampshire.
Iroquois
The Eastchester expansion project is experiencing construction delays, which has
resulted in a postponement of the expected in-service date.
Liquefied Natural Gas
In September 2003, TCPL and ConocoPhillips Company announced the Fairwinds
partnership to jointly evaluate a site in Harpswell, Maine for the development
of a liquefied natural gas (LNG) regasification facility. The residents of the
Town of Harpswell have been asked to vote on leasing a town-owned site for the
facility. If leasing of the site is approved and necessary regulatory approvals
are subsequently received, construction of the LNG facility could begin in 2006
with the facility becoming operational in 2009. Natural gas from the LNG
facility would be delivered by pipeline to markets in the northeast U.S.
Power
In August 2003, TCPL successfully commenced operations under a fee for service
power purchase arrangement with the Ontario government through the Ontario
Electricity Financial Corporation (OEFC). Under the agreement, TCPL will supply
110 MW from a temporary facility adjacent to the Canadian Mainline near Cobourg,
Ontario, for a period ending as early as December 31, 2003. The OEFC retains an
option to extend the service contract until April 30, 2004. The Cobourg
facility was fully functional and in-service August 10, 2003.
A power blackout affecting much of Ontario and the northeastern U.S. on August
14, 2003 created unplanned outages for some of TCPL's power plants. Most
facilities were brought back on-line within hours and TCPL was also able to
deliver additional power to the Ontario market through its Cobourg facility.
This power blackout did not have a material impact on TCPL's net earnings.
On October 24, 2003, TCPL and Grandview Cogeneration Corporation, an affiliate
of Irving Oil Limited (Irving), announced an agreement to build a 90 MW natural
gas-fired cogeneration power plant in Saint John, New Brunswick at an estimated
capital cost of $85 million. This cogeneration facility will be developed and
owned by TCPL. Under a 20 year tolling arrangement, Irving will provide fuel for
the plant and contract for 100 per cent of the plant's heat and electricity
output. Pending regulatory approvals construction of the plant is expected to
begin in November 2003 with an anticipated in-service date by the end of 2004.
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 September 30 Nine months ended September
30
(millions of dollars) 2003 2002 2003 2002
Revenues 1,391 1,285 4,038 3,876
Operating Expenses
Cost of sales 164 163 533 466
Other costs and expenses 439 386 1,248 1,123
Depreciation 260 211 692 631
863 760 2,473 2,220
Operating Income 528 525 1,565 1,656
Other Expenses/(Income)
Financial charges 210 213 619 652
Financial charges of joint ventures 18 22 63 67
Equity income (67) (8) (151) (26)
Interest and other income (9) (14) (44) (36)
152 213 487 657
Income from Continuing Operations before 376 312 1,078 999
Income Taxes
Income Taxes - Current and Future 164 123 427 389
Net Income from Continuing Operations 212 189 651 610
Net Income from Discontinued Operations 50 - 50 -
Net Income 262 189 701 610
Preferred Securities Charges 8 8 26 26
Preferred Share Dividends 6 6 17 17
Net Income Applicable to Common Shares 248 175 658 567
Net Income Applicable to Common Shares
Continuing operations 198 175 608 567
Discontinued operations 50 - 50 -
248 175 658 567
See accompanying Notes to the Consolidated Financial
Statements.
Consolidated Cash Flows
(unaudited) Three months ended September 30 Nine months ended September 30
(millions of dollars) 2003 2002 2003 2002
Cash Generated From Operations
Net income from continuing operations 212 189 651 610
Depreciation 260 211 692 631
Future income taxes 121 71 248 180
Equity income in excess of distributions received (66) (1) (125) (6)
Other (11) (3) (59) (55)
Funds generated from continuing operations 516 467 1,407 1,360
Decrease/(Increase) in operating working capital 65 (12) 90 (68)
Net cash provided by continuing operations 581 455 1,497 1,292
Net cash (used in)/provided by discontinued
operations 67 (21) (17) 30
648 434 1,480 1,322
Investing Activities
Capital expenditures (81) (182) (264) (397)
Acquisitions, net of cash acquired (135) (19) (547) (19)
Disposition of assets - - 5 -
Deferred amounts and other (168) 62 (238) (12)
Net cash used in investing activities (384) (139) (1,044) (428)
Financing Activities
Dividends and preferred securities charges (150) (140) (438) (407)
Notes payable issued/(repaid), net 361 12 279 (228)
Long-term debt issued - - 475 -
Reduction of long-term debt (327) (114) (386) (230)
Non-recourse debt of joint ventures issued 14 19 60 24
Reduction of non-recourse debt of joint ventures (7) (9) (55) (51)
Redemption of junior subordinated debentures (218) - (218) -
Common shares issued - 12 18 43
Net cash (used in)/provided by financing activities (327) (220) (265) (849)
(Decrease)/Increase in Cash and Short-Term (63) 75 171 45
Investments
Cash and Short-Term Investments
Beginning of period 446 269 212 299
Cash and Short-Term Investments
End of period 383 344 383 344
Supplementary Cash Flow Information
Income taxes paid 68 50 192 205
Interest paid 186 217 618 639
See accompanying Notes to the Consolidated Financial Statements.
Consolidated Balance Sheet
September 30, 2003 December 31,
(millions of dollars) (unaudited) 2002
ASSETS
Current Assets
Cash and short-term investments 383 212
Accounts receivable 548 691
Inventories 174 178
Other 83 102
1,188 1,183
Long-Term Investments 792 291
Plant, Property and Equipment 17,076 17,496
Other Assets 1,246 946
20,302 19,916
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Notes payable 576 297
Accounts payable 813 902
Accrued interest 229 227
Current portion of long-term debt 526 517
Current portion of non-recourse debt of
joint ventures 20 75
Provision for loss on discontinued
operations 168 234
2,332 2,252
Deferred Amounts 424 353
Long-Term Debt 9,233 8,815
Future Income Taxes 434 226
Non-Recourse Debt of Joint Ventures 803 1,222
Junior Subordinated Debentures 21 238
13,247 13,106
Shareholders' Equity
Preferred securities 673 674
Preferred shares 389 389
Common shares 4,632 4,614
Contributed surplus 267 265
Retained earnings 1,123 854
Foreign exchange adjustment (29) 14
7,055 6,810
20,302 19,916
See accompanying Notes to the Consolidated Financial Statements.
Consolidated Retained Earnings
(unaudited) Nine months ended September 30
(millions of dollars) 2003 2002
Balance at beginning of period 854 586
Net income 701 610
Preferred securities charges (26) (26)
Preferred share dividends (17) (17)
Common share dividends (389) (359)
1,123 794
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 nine months ended September 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 TCPL'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
September 30
(unaudited -
millions of
dollars) 2003 2002 2003 2002 2003 2002 2003 2002
Revenues 1,070 971 321 314 - - 1,391 1,285
Cost of sales - - (164) (163) - - (164) (163)
Other costs
and expenses (339) (301) (99) (81) (1) (4) (439) (386)
Depreciation (240) (196) (19) (15) (1) - (260) (211)
Operating
income/(loss) 491 474 39 55 (2) (4) 528 525
Financial and
preferred
equity charges (198) (202) (2) (3) (24) (22) (224) (227)
Financial
charges of
joint ventures (18) (22) - - - - (18) (22)
Equity income 29 8 38 - - - 67 8
Interest and
other income 3 6 2 4 4 4 9 14
Income taxes (147) (110) (27) (21) 10 8 (164) (123)
Continuing
operations 160 154 50 35 (12) (14) 198 175
Discontinued
operations 50 -
Net Income
Applicable to
Common Shares 248 175
Transmission Power Corporate Total
Nine months
ended
September 30
(unaudited -
millions of
dollars) 2003 2002 2003 2002 2003 2002 2003 2002
Revenues 2,974 2,914 1,064 962 - - 4,038 3,876
Cost of sales - - (533) (466) - - (533) (466)
Other costs
and expenses (944) (847) (299) (268) (5) (8) (1,248) (1,123)
Depreciation (629) (586) (62) (45) (1) - (692) (631)
Operating
income/(loss) 1,401 1,481 170 183 (6) (8) 1,565 1,656
Financial and
preferred
equity charges (588) (616) (7) (9) (67) (70) (662) (695)
Financial
charges of
joint ventures (62) (67) (1) - - - (63) (67)
Equity income 59 26 92 - - - 151 26
Interest and
other income 11 12 10 11 23 13 44 36
Income taxes (359) (345) (88) (69) 20 25 (427) (389)
Continuing
operations 462 491 176 116 (30) (40) 608 567
Discontinued
operations 50 -
Net Income
Applicable to
Common Shares 658 567
Total Assets September 30, 2003 December 31,
(millions of dollars) (unaudited) 2002
Transmission 16,667 16,979
Power 2,675 2,292
Corporate 830 457
Continuing operations 20,172 19,728
Discontinued operations 130 188
20,302 19,916
4. Junior Subordinated Debentures
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 September 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 net
exposure on an after-tax basis. 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) September 30, 2003
(millions of dollars) (unaudited) December 31, 2002
Carrying Fair Carrying Fair
Amount Value Amount Value
Foreign Exchange Value
Cross-currency swaps
U.S. dollars 51 51 (8) (8)
At September 30, 2003, the notional principal amount of cross-currency swaps was
US$250 million (December 31, 2002 - US$350 million).
Reconciliation of Foreign Exchange Adjustment September 30, 2003 December 31,
(millions of dollars) (unaudited) 2002
Balance at beginning of period 14 13
Translation (losses)/gains on foreign currency denominated (115) 3
net assets
Foreign exchange gains/(losses) on derivatives, 72 (2)
and other
Balance at end of period (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 from a subsidiary
of Mirant Corporation (Mirant) certain remaining contracts in June and July
2003, and simultaneously hedging the market price exposures of these contracts.
The company remains contingently liable for certain residual obligations.
At September 30, 2003, TCPL reviewed the provision for loss on discontinued
operations and the deferred gain, taking into consideration the impacts of
Mirant's filing for bankruptcy protection in July 2003 and the mitigation of the
contingent liabilities referred to above. As a result of this review, $50
million of the original approximately $100 million after-tax deferred gain was
recognized in income in third quarter 2003. In addition, TCPL concluded that
the remaining provision was adequate, and the deferral of the remaining
approximately $50 million of deferred after-tax gains related to the Gas
Marketing business was appropriate.
Net income from discontinued operations was $50 million, net of $29 million in
taxes, for the three and nine months ended September 30, 2003 compared to nil
for the same periods in 2002. The provision for loss on discontinued operations
at September 30, 2003 was $168 million (December 31, 2002 - $234 million). The
net assets of discontinued operations included in the consolidated balance sheet
at September 30, 2003 were $94 million (December 31, 2002 - $90 million).
7. Investment in Bruce Power L.P.
On February 14, 2003, TCPL acquired a 31.6 per cent interest in Bruce Power L.P.
(Bruce Power) for approximately $409 million, including closing adjustments. As
part of the acquisition, TCPL also funded a one-third share ($75 million) of a
$225 million accelerated deferred rent payment to Ontario Power Generation,
which is recorded in Other Assets.
The purchase price of TCPL's 31.6 per cent interest in Bruce Power has been
allocated as follows.
Purchase Price Allocation
(unaudited)
(millions of dollars)
Net book value of assets acquired 281
Valuation of Bruce Power sales agreements (131)
Excess of fair value over book value of other net assets
acquired 259
409
The amount allocated to the investment in Bruce Power includes an excess
purchase price of approximately $259 million over TCPL's share of the book value
of the underlying net assets, other than the Bruce Power sales agreements. This
amount will be primarily assigned to the capital lease of the Bruce plant and
will be amortized on a straight-line basis over the lease term which extends to
2018, resulting in an annual amortization expense of approximately $16 million.
The value, being $131 million, allocated to the Bruce Power sales agreements
will be amortized to income over the remaining term of the underlying sales
contracts. The approximate amount of income relating to the amortization of the
fair value allocated to these contracts is: 2003 - $38 million; 2004 - $37
million; 2005 - $25 million; 2006 - $29 million; and 2007 - $2 million. The
investment in Bruce Power L.P. is recorded in Long-Term Investments.
8. 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 result in a natural gas pipeline being constructed from Inuvik, Northwest
Territories to the northern border 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; this share is 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 shareholders and potential investors.
Please telephone:
Investor Relations, at 1-800-361-6522 (Canada and U.S. Mainland) or direct dial
David Moneta/Debbie Stein 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
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