RNS Number:8627U
TransCanada Pipelines Ld
30 January 2004
TRANSCANADA PIPELINES LIMITED
FOURTH QUARTER 2003
Quarterly Report
Consolidated Results-at-a-Glance
(unaudited) Three months ended December 31 Year ended December 31
(millions of dollars) 2003 2002 2003 2002
Net Income Applicable to Common Shares
Continuing operations 193 180 801 747
Discontinued operations - - 50 -
193 180 851 747
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 year ended December 31, 2003 and
the notes thereto.
Results of Operations
Consolidated
TCPL's net income applicable to common shares from continuing operations (net
earnings) and net income for fourth quarter 2003 were $193 million compared to
$180 million for fourth quarter 2002. The increase of $13 million was primarily
due to higher earnings from the Power business. Higher net earnings from the
Power business included $7 million after tax from TCPL's investment in Bruce
Power L.P. (Bruce Power) and lower general, administrative and support costs.
TCPL's net income applicable to common shares for the year ended December 31,
2003 was $851 million compared to $747 million for the comparable period in
2002. Included in 2003 was net income from discontinued operations of $50
million reflecting the third quarter 2003 income recognition of a portion of the
initially deferred gain of approximately $100 million after tax relating to the
2001 disposition of the company's Gas Marketing business.
TCPL's net earnings applicable to common shares from continuing operations for
the year ended December 31, 2003 were $801 million compared to $747 million for
the comparable period in 2002. The increase of $54 million in 2003 compared to
2002 was primarily due to higher net earnings of $74 million from the Power
business and lower net expenses in the Corporate segment, partially offset by
lower net earnings from the Gas Transmission business.
Net earnings from the Power business for the year ended December 31, 2003
included $73 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 were partially offset by reduced operating and other income from the
Northeastern U.S. Operations, combined with higher general, administrative and
support costs.
The $11 million decrease in 2003 net expenses in the Corporate segment was
primarily due to the positive impacts of a weaker U.S. dollar in 2003 compared
to 2002.
The lower net earnings of $31 million in the Gas Transmission business for the
year ended December 31, 2003 compared to 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 year ended December 31, 2002
included after-tax income of $16 million representing the impact of the Fair
Return decision for 2001. The 2003 results for the Gas Transmission segment
included TCPL's $11 million share of future income tax benefits recognized by
TransGas de Occidente (TransGas) while the 2002 results included TCPL's $7
million share of a favourable ruling for Great Lakes related to Minnesota use
tax paid in prior years.
Segment Results-at-a-Glance
(unaudited) Three months ended December 31 Year ended December 31
(millions of dollars) 2003 2002 2003 2002
Gas Transmission 160 162 622 653
Power 44 30 220 146
Corporate (11) (12) (41) (52)
Continuing operations 193 180 801 747
Discontinued operations - - 50 -
Net Income Applicable to Common Shares 193 180 851 747
Funds generated from continuing operations of $403 million for fourth quarter
2003 decreased $64 million compared to fourth quarter 2002. Funds generated
from continuing operations of $1,810 million for the year ended December 31,
2003 decreased $17 million compared to last year.
Gas Transmission
The Gas Transmission business generated net earnings of $160 million and $622
million for the quarter and year ended December 31, 2003, respectively, compared
to $162 million and $653 million for the same periods in 2002.
Gas Transmission Results-at-a-Glance
(unaudited) Three months ended December Year ended December 31
31
(millions of dollars) 2003 2002 2003 2002
Wholly-Owned Pipelines
Alberta System 54 56 190 214
Canadian Mainline 75 75 290 307
Foothills* 6 4 20 17
BC System 2 2 6 6
137 137 506 544
Other Gas Transmission
Great Lakes 14 17 52 66
Iroquois 3 3 18 18
TC PipeLines, LP 4 5 15 17
Portland** 4 - 11 2
Ventures LP 3 2 10 7
Trans Quebec & Maritimes 2 2 8 8
CrossAlta 2 4 6 13
TransGas de Occidente 2 1 22 6
Northern Development (2) (1) (4) (6)
General, administrative, support and (9) (8) (22) (22)
other
23 25 116 109
Net earnings 160 162 622 653
* The remaining interests in Foothills, previously not held by TCPL, were acquired
on August 15, 2003.
** TCPL increased its ownership interest in Portland from 33.3 per cent to 43.4 per cent on September
29, 2003 and from 43.4 per cent to 61.7 per cent on December 3, 2003.
Wholly-Owned Pipelines
The Alberta System's net earnings of $54 million in fourth quarter 2003
decreased $2 million compared to $56 million in the same quarter of 2002. Net
earnings for the year ended December 31, 2003 decreased $24 million compared to
the prior year. This 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. As discussed in the third quarter 2003
Quarterly Report to Shareholders, the lower negotiated 2003 revenue requirement
was expected to reduce 2003 earnings by approximately $30 million relative to
2002 earnings of $214 million. However, lower financing and operating costs
partially offset the previously anticipated reduction in earnings.
The Canadian Mainline's fourth quarter net earnings of $75 million are
consistent with net earnings in the same quarter of 2002. The 2003 net earnings
of $290 million are $17 million lower than 2002 net earnings due to the impact
of the NEB's Fair Return decision in 2002. This decision included an increase
in the deemed common equity ratio from 30 to 33 per cent effective January 1,
2001 and resulted in additional net earnings of $16 million for the year ended
December 31, 2001, recognized in June 2002. The impact of a lower average
investment base was substantially offset by an increase in the approved rate of
return on common equity from 9.53 per cent in 2002 to 9.79 per cent in 2003.
In December 2002, the NEB approved TCPL's application to charge interim tolls
for transportation service, effective January 1, 2003. In August 2003,
subsequent to the NEB's decision on the 2003 Tolls and Tariff Application, it
approved interim tolls that the company charged from September 1, 2003 to
December 31, 2003. The NEB ordered that tolls will remain interim pending a
decision from the Federal Court of Appeal on TCPL's appeal of the NEB's decision
on TCPL's Fair Return Review and Variance Application, which is expected to be
heard commencing February 16, 2004.
Operating Statistics
Year ended December 31 Alberta Canadian BC
(unaudited) System* Mainline** Foothills*** System
2003 2002 2003 2002 2003 2002 2003 2002
Average investment base ($ 4,878 5,074 8,565 8,884 739 *** 236 211
millions)
Delivery volumes (Bcf)
Total 3,883 4,146 2,628 2,630 1,110 *** 325 371
Average per day 10.6 11.4 7.2 7.2 3.0 *** 0.9 1.0
* Field receipt volumes for the Alberta System for the year ended December 31, 2003 were 3,892 Bcf (2002 -
4,101 Bcf); average per day was 10.7 Bcf (2002 - 11.2 Bcf).
** Canadian Mainline deliveries originating at the Alberta border and in Saskatchewan for the year ended
December 31, 2003 were 2,055 Bcf (2002 - 2,221 Bcf); average per day was 5.6 Bcf (2002 - 6.1 Bcf).
*** The remaining interests in Foothills were acquired in August 2003. The annual 2003 delivery volumes in
the table represent 100 per cent of Foothills.
Other Gas Transmission
TCPL's proportionate share of net earnings from Other Gas Transmission was $23
million and $116 million for the quarter and year ended December 31, 2003,
respectively.
Net earnings for fourth quarter 2003 were slightly lower than the same quarter
in 2002. Higher contributions from Portland, Ventures LP and TransGas were more
than offset by lower earnings from CrossAlta, higher project development costs,
and the impact of a weaker U.S. dollar.
The 2002 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 2003 increased $14
million compared to 2002. Earnings from TransGas were $16 million higher as a
result of higher contractual tolls and the recognition of future tax benefits in
2003. TCPL's share of Portland's net earnings in 2003 has increased $9 million
compared to last year primarily due to the impacts of a rate settlement in early
2003 and TCPL's increased ownership interest in 2003. These increases were
partially offset by a weaker U.S. dollar and lower earnings from CrossAlta due
to reduced storage margins as a result of unfavourable market conditions.
On December 3, 2003, TCPL increased its ownership interest in Portland Natural
Gas Transmission System Partnership (Portland) from 43.4 per cent to 61.7 per
cent. The company acquired the additional interest from El Paso Corporation for
US$82 million, including US$50 million of assumed debt.
Power
Power Results-at-a-Glance
(unaudited) Three months ended December 31 Year ended December 31
(millions of dollars) 2003 2002 2003 2002
Western operations 31 30 160 131
Northeastern U.S. operations 36 35 127 149
Bruce Power L.P. investment 7 - 99 -
Power LP investment 9 9 35 36
General, administrative and support (20) (25) (86) (73)
costs
Operating and other income 63 49 335 243
Financial charges (4) (4) (12) (13)
Income taxes (15) (15) (103) (84)
Net earnings 44 30 220 146
Power's net earnings in fourth quarter 2003 of $44 million increased $14 million
compared to $30 million in fourth quarter 2002. Earnings from the February 2003
acquisition of the 31.6 per cent interest in Bruce Power and reduced general,
administrative and support costs were the primary reasons for the increase.
Net earnings for the year ended December 31, 2003 of $220 million were $74
million higher compared to the prior year. Bruce Power earnings, a second
quarter 2003 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 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 for fourth quarter 2003 in Western Operations of $31
million was comparable to fourth quarter 2002. Higher contributions from the
Sundance power purchase arrangements reflecting lower transmission costs were
partially offset by the unfavourable effects in fourth quarter 2003 of lower
prices achieved on the overall sale of power.
Operating and other income for the year ended December 31, 2003 in Western
Operations of $160 million was $29 million higher compared to the prior year,
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. A full year of earnings from
the ManChief plant, acquired in late 2002, and higher contributions from the
Sundance power purchase arrangements reflecting lower transmission costs 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 the higher cost of natural gas fuel at the carbon black facility.
Northeastern U.S. Operations
Operating and other income for fourth quarter 2003 in Northeastern U.S.
Operations of $36 million increased marginally compared to fourth quarter 2002.
Increased water flows through the Curtis Palmer hydroelectric facility and
earnings from the Cobourg temporary generation facility were partially offset by
the unfavourable impact of a weaker U.S. dollar and higher natural gas fuel cost
at Ocean State Power (OSP) resulting from an arbitration process.
Operating and other income for the year ended December 31, 2003 in Northeastern
U.S. Operations of $127 million decreased $22 million compared to 2002 primarily
due to the impact of higher operating costs at OSP and the unfavourable impact
of a weaker U.S. dollar. Partially offsetting these decreases were incremental
earnings from the growth in volumes and margins in the Northeastern U.S. retail
business with large commercial and industrial customers. The long- term gas
supply for OSP is subject to a yearly price renegotiation, taking effect after
the tenth year of the contract. If OSP and the suppliers are unable to reach
an agreement on price in a given year, the matter is settled by arbitration.
OSP is currently in arbitration with its natural gas fuel suppliers regarding
changes to the pricing of its fuel supply.
Bruce Power L.P. Investment
Bruce Power Results-at-a-Glance Three months Year ended
ended December December 31,
31, 2003 2003
(unaudited)
(millions of dollars)
Bruce Power (100 per cent basis)
Revenues 269 1,208
Operating expenses 254 853
Operating income 15 355
Financial charges 20 69
(Loss)/Income before income taxes (5) 286
TCPL's interest in Bruce Power (loss)/income before income (1) 65
taxes*
Adjustments ** 8 34
TCPL's income from Bruce Power before income taxes 7 99
* TCPL acquired its interest in Bruce Power on February 14, 2003. Bruce Power's 100 per cent income
before income taxes from February 14, 2003 to December 31, 2003 was $205 million.
** See Note 7 to the December 31, 2003 financial statements for an explanation of the amounts included in
Adjustments.
Bruce Power contributed $7 million of pre-tax equity income in fourth quarter
2003 compared to $38 million in third quarter 2003. The decrease reflected lower
power output and higher maintenance costs compared to third quarter 2003,
primarily due to a maintenance outage at one of the Bruce B units for the entire
fourth quarter 2003. Overall prices achieved during fourth quarter 2003 were
approximately $45 per megawatt hour (MWh) which is consistent with third quarter
2003. The average price achieved for the year ended December 31, 2003 was
approximately $48 per MWh. Approximately 30 per cent of the output was sold into
Ontario's wholesale spot market in fourth quarter 2003 with the remainder being
sold under longer term contracts.
TCPL's share of power output for fourth quarter 2003 from four Bruce B units
and one Bruce A unit was 1,846 gigawatt hours (GWh) compared to 2,041 GWh in
third quarter 2003. This includes power output from Bruce A Unit 4 from
November 1, 2003 to December 31, 2003 of approximately 275 GWh. Bruce A Unit 4
began producing electricity to the Ontario electricity grid on October 7, 2003
and was considered commercially in-service November 1, 2003. Bruce B Unit 8 was
offline for the entire fourth quarter for maintenance. As well, Bruce B Unit 7
incurred a week long forced outage in the fourth quarter. The Bruce units ran at
an average availability of 73 per cent in the fourth quarter. The average
availability during TCPL's period of ownership ending December 31, 2003 was 83
per cent.
Bruce A Unit 3 reconnected to the Ontario electricity grid on January 8, 2004.
Similar to the Bruce A Unit 4 startup process, after performing and evaluating
tests of the shutdown system, Bruce A Unit 3 is expected to reconnect to the
grid and begin ramping up to full power. Bruce Power's cumulative restart cost
for the two Bruce A units was approximately $720 million. Bruce Power incurred
approximately $300 million on the two unit restart program for the period
February 14, 2003 to December 31, 2003, of which approximately $32 million was
incurred in fourth quarter 2003. TCPL did not provide any funding to Bruce
Power subsequent to the acquisition of its ownership interest in February 2003.
The two Bruce A units add 1,500 megawatts (MW) of capacity bringing Bruce
Power's total capacity to 4,660 MW.
Bruce Power spent approximately $147 million on capital expenditures at Bruce B
for the period February 14, 2003 to December 31, 2003, the majority of which was
for safety systems and power uprate programs. In 2004, Bruce Power's capital
expenditure program for the two Bruce A and four Bruce B reactors is expected to
total approximately $400 million.
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. To reduce its
exposure to spot market prices, Bruce Power has entered into fixed price sales
contracts for approximately 1,560 MW of output for 2004. The average
availability in 2004 for the six Bruce units is expected to be 80 per cent
compared to 85 per cent for the year ended December 31, 2003. This decrease
reflects planned maintenance outages for two Bruce B and two Bruce A units and a
test of the Bruce B vacuum building expected in the fall, which will require all
four Bruce B units to be taken offline for approximately one month. There is a
planned maintenance outage at one of the Bruce A units for approximately one
month, towards the end of first quarter 2004.
Power LP Investment
Operating and other income of $9 million and $35 million for the three and
twelve months ended December 31, 2003, was consistent with the same periods in
2002.
General, Administrative and Support Costs
General, administrative and support costs for fourth quarter 2003 of $20 million
were $5 million lower compared to fourth quarter 2002. The decrease is primarily
due to lower business development costs in fourth quarter 2003.
General, administrative and support costs for the year ended December 31, 2003
increased $13 million compared to the prior year, mainly reflecting higher
support costs as part of the company's continued investment in Power.
Power Sales Volumes
(unaudited) Three months ended December Year ended December 31
31
(GWh) 2003 2002 2003 2002
Western operations* 2,972 2,864 12,296 12,065
Northeastern U.S. operations 1,794 1,513 6,906 5,630
Bruce Power L.P. investment** 1,846 n/a 6,655 n/a
Power LP investment 549 637 2,153 2,416
Total 7,161 5,014 28,010 20,111
* Sales volumes include TCPL's share of the Sundance B power purchase arrangement (50 per cent).
** Acquired in February 2003. Sales volumes reflect TCPL's share of Bruce Power output (31.6 per cent)
for the period February 14, 2003 to December 31, 2003.
Weighted Average Plant Availability* Three months ended December Year ended December 31
31
(unaudited) 2003 2002 2003 2002
Western operations 94% 99% 93% 99%
Northeastern U.S. operations 99% 82% 94% 95%
Bruce Power L.P. investment** 73% n/a 83% n/a
Power LP investment 98% 98% 96% 94%
All plants 89% 92% 90% 96%
* Plant availability is reduced by planned and unplanned outages.
** Acquired in February 2003. TCPL's availability reflects the period February 14, 2003 to December 31, 2003.
Corporate
Net expenses were $11 million and $12 million for the three months ended
December 31, 2003 and 2002, respectively. Net expenses were $41 million for the
year ended December 31, 2003 compared to $52 million for 2002. The $11 million
decrease in net expenses for 2003 is primarily due to the positive impacts of a
weaker U.S. dollar compared to the prior year. These positive impacts
substantially offset the negative impacts of a weaker U.S. dollar reflected in
the other segments.
Discontinued Operations
The company's exit from the Gas Marketing business was substantially completed
by December 31, 2001. In third quarter 2003, $50 million of the original
approximately $100 million after-tax deferred gain related to Gas Marketing was
recognized in income. At December 31, 2003, TCPL reviewed the provision for
loss on discontinued operations and the deferred gain and concluded that the
remaining provision was adequate and the deferral of the remaining approximately
$50 million of deferred after-tax gain related to the Gas Marketing business was
appropriate.
TCPL's investments in Gasoducto del Pacifico, INNERGY Holdings S.A. and P.T.
Paiton Energy Company, which were approved for disposal under a plan in December
1999, will be accounted for as part of continuing operations as of December 31,
2003 due to the length of time it has taken the company to dispose of these
assets. It is the intention of the company to continue with the plan to dispose
of these investments.
Liquidity and Capital Resources
Funds Generated from Operations
Funds generated from continuing operations were $403 million and $1,810 million
for the three and twelve months ended December 31, 2003, respectively, compared
with $467 million and $1,827 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 months and year ended December 31, 2003, capital expenditures,
excluding acquisitions, totalled $127 million (2002 - $202 million) and $391
million (2002 - $599 million), respectively, and related primarily to Iroquois'
ongoing Eastchester Expansion project into New York City, maintenance and
capacity capital in wholly-owned pipelines and construction of the MacKay River
power plant in Alberta.
Acquisitions for the year ended December 31, 2003 totalled $570 million (2002 -
$228 million) and were primarily comprised of:
* in fourth quarter 2003, the increase in interest in Portland from 43.4 per
cent to 61.7 per cent for approximately US$32 million,
* in third quarter 2003, the increase in interest in Portland from 33.3 per
cent to 43.4 per cent for approximately US$19 million,
* in third quarter 2003, the acquisition of the remaining interests in
Foothills for approximately $105 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 and US$78 million of debt on the
Foothills and Portland acquisitions, respectively.
Financing Activities
TCPL used a portion of its cash resources to retire long-term debt of $358
million and $744 million in the quarter and year ended December 31, 2003,
respectively. In November 2003, the company issued $450 million of ten year
notes bearing interest at 5.65 per cent and in June 2003, the company issued
US$350 million of ten year notes bearing interest at 4.00 per cent. For the
year ended December 31, 2003, outstanding notes payable decreased by $62
million, while cash and short-term investments increased by $126 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 January 27, 2004, TCPL's Board of Directors declared a dividend for the
quarter ending March 31, 2004 in an aggregate amount equal to the aggregate
quarterly dividend to be paid on April 30, 2004 by TransCanada Corporation on
the issued and outstanding common shares as at the close of business on March
31, 2004. 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
In 2004, the outcome of regulatory proceedings could have a significant impact
on the expected results for the Alberta System and Canadian Mainline. Plant
availability and fluctuating power prices could have a significant impact on
Power results. Excluding these impacts as well as the settlement with a former
counterparty in 2003 and the recognition of the TransGas future tax benefits in
2003, the outlook for the company is 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 Gas Transmission and Power. The
strengthening of the Canadian dollar compared to the U.S. dollar in 2003 has not
significantly impacted TCPL's consolidated financial results in 2003 and is not
expected to have a significant impact in 2004. 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
Gas Transmission
Wholly-Owned Pipelines
Alberta System
In July 2003, TCPL, along with other utilities, filed evidence in the Generic
Cost of Capital (GCOC) Proceeding with the Alberta Energy and Utilities Board
(EUB). TCPL has requested a return on equity of 11 per cent based on a deemed
common equity of 40 per cent in its GCOC 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.
The oral portion of the hearing was completed on January 16, 2004 with written
arguments to follow.
In September 2003, TCPL filed Phase I of the 2004 General Rate Application (GRA)
with the EUB, consisting of evidence in support of the applied for rate base and
revenue requirement. The company applied for a composite depreciation rate of
4.13 per cent compared to the current depreciation rate of 4.00 per cent. Phase
II of the application, dealing primarily with rate design and services, was
filed in December 2003. EUB hearings to consider the 2004 GRA Phase I and Phase
II applications are scheduled to commence, in Calgary, on April 1, 2004 and June
1, 2004, respectively.
In December 2003, the EUB approved TCPL's application to charge interim tolls
for transportation service, effective January 1, 2004. Final tolls for 2004
will be determined based on the EUB decisions for the GCOC hearing and both
phases of the GRA.
On December 1 and 2, 2003, two natural gas pipeline failures occurred on the
Alberta System. Deliveries of gas to local communities were not impacted as a
result of either incident. Following preliminary investigations into the causes
of the two pipeline ruptures, TCPL found evidence of external corrosion on the
pipeline. No one was injured and the impacted segment of the Alberta System was
repaired within days. The incidents are not expected to have an impact on the
company's earnings.
Canadian Mainline
In July 2003, TCPL filed a notice of appeal with the Federal Court of Appeal and
served notice of appeal on parties to the NEB proceeding on TCPL's Fair Return
Review and Variance Application. In September 2003, TCPL filed a Memorandum of
Fact and Law with the Federal Court of Appeal, and in October 2003 all
interested parties filed their memoranda in response to TCPL's filing. The case
will be heard in an oral hearing scheduled to commence February 16, 2004.
In December 2003, the NEB approved interim tolls effective January 1, 2004 for
the Canadian Mainline. The 2004 Tolls and Tariff Application for the Canadian
Mainline was filed on January 26, 2004 and includes a request for an 11 per cent
return on a 40 per cent deemed common equity component.
Other Gas Transmission
Iroquois
Iroquois continues to make progress on the construction of the Eastchester
expansion project and is expected to place the expansion facilities into service
in February 2004.
Northern Development
For the Mackenzie Gas Pipeline Project, TCPL has agreed to finance the
Aboriginal PipeLine Group (APG) for its one-third share of project definition
phase costs which is estimated to be approximately $90 million over three years.
In the year ended December 31, 2003, TCPL funded $34 million which is included
in Other Assets. Regulatory applications for the Mackenzie Gas Pipeline Project
have been delayed and are expected to be filed mid-2004.
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 are expected to vote in first quarter 2004 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 supplied 110
MW of capacity from a temporary facility adjacent to the Canadian Mainline near
Cobourg, Ontario up to December 31, 2003. Demobilization of the temporary
facility began in early January 2004 and is expected to be complete by late
spring.
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. 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. Construction of the plant
commenced in December 2003 and is expected to be in-service in December 2004.
Construction of MacKay River, a 165 MW facility near Fort McMurray, Alberta, was
completed in fourth quarter 2003 and commissioning is underway.
The fourth quarter scheduled maintenance outage of Bruce B Unit 8 was originally
planned to take approximately eight weeks, but was extended after inspections
identified some erosion on support plates in three of the unit's eight steam
generators. Repairs have been completed and approved by the Canadian Nuclear
Safety Commission and the unit is in the process of being returned to service.
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 December 31 Year ended December 31
(millions of dollars) 2003 2002 2003 2002
Revenues 1,319 1,338 5,357 5,214
Operating Expenses
Cost of sales 159 161 692 627
Other costs and expenses 434 423 1,682 1,546
Depreciation 222 217 914 848
815 801 3,288 3,021
Operating Income 504 537 2,069 2,193
Other Expenses/(Income)
Financial charges 202 215 821 867
Financial charges of joint ventures 14 23 77 90
Equity income (14) (7) (165) (33)
Interest and other income (16) (17) (60) (53)
186 214 673 871
Income from Continuing Operations before
Income Taxes and Non-Controlling 318 323 1,396 1,322
Interests
Income Taxes - Current and Future 108 128 535 517
Non-Controlling Interests 2 - 2 -
Net Income from Continuing Operations 208 195 859 805
Net Income from Discontinued Operations - - 50 -
Net Income 208 195 909 805
Preferred Securities Charges 10 10 36 36
Preferred Share Dividends 5 5 22 22
Net Income Applicable to Common Shares 193 180 851 747
Net Income Applicable to Common Shares
Continuing operations 193 180 801 747
Discontinued operations - - 50 -
193 180 851 747
See accompanying Notes to the Consolidated Financial
Statements.
Consolidated Cash Flows
(unaudited) Three months ended December Year ended December 31
31
(millions of dollars) 2003 2002 2003 2002
Cash Generated From Operations
Net income from continuing operations 208 195 859 805
Depreciation 222 217 914 848
Future income taxes (18) 67 230 247
Equity income in excess of distributions received (3) - (128) (6)
Other (6) (12) (65) (67)
Funds generated from continuing operations 403 467 1,810 1,827
Decrease in operating working capital 29 101 112 33
Net cash provided by continuing operations 432 568 1,922 1,860
Net cash provided by/(used in) discontinued - 29 (17) 59
operations
432 597 1,905 1,919
Investing Activities
Capital expenditures (127) (202) (391) (599)
Acquisitions, net of cash acquired (23) (209) (570) (228)
Deferred amounts and other 43 (103) (190) (115)
Net cash used in investing activities (107) (514) (1,151) (942)
Financing Activities
Dividends and preferred securities charges (150) (139) (588) (546)
Advances from parent 39 - 46 -
Notes payable (repaid)/issued, net (341) 182 (62) (46)
Long-term debt issued 455 - 930 -
Reduction of long-term debt (358) (256) (744) (486)
Non-recourse debt of joint ventures issued - 20 60 44
Reduction of non-recourse debt of joint ventures (16) (29) (71) (80)
Redemption of junior subordinated debentures - - (218) -
Common shares issued - 7 18 50
Net cash used in financing activities (371) (215) (629) (1,064)
(Decrease)/Increase in Cash and Short-Term (46) (132) 125 (87)
Investments
Cash and Short-Term Investments
Beginning of period 383 344 212 299
Cash and Short-Term Investments
End of period 337 212 337 212
Supplementary Cash Flow Information
Income taxes paid 28 52 220 257
Interest paid 222 227 846 866
See accompanying Notes to the Consolidated Financial
Statements.
Consolidated Balance Sheet
(unaudited)
December 31 (millions of dollars) 2003 2002
ASSETS
Current Assets
Cash and short-term investments 337 212
Accounts receivable 603 691
Inventories 165 178
Other 88 107
1,193 1,188
Long-Term Investments 733 345
Plant, Property and Equipment 17,451 17,496
Other Assets 1,164 937
20,541 19,966
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Notes payable 367 297
Accounts payable 1,069 990
Accrued interest 208 227
Current portion of long-term debt 550 517
Current portion of non-recourse debt of joint ventures 19 75
2,213 2,106
Deferred Amounts 466 549
Long-Term Debt 9,465 8,815
Future Income Taxes 427 226
Non-Recourse Debt of Joint Ventures 761 1,222
Junior Subordinated Debentures 22 238
13,354 13,156
Non-Controlling Interests 82 -
Shareholders' Equity
Preferred securities 672 674
Preferred shares 389 389
Common shares 4,632 4,614
Contributed surplus 267 265
Retained earnings 1,185 854
Foreign exchange adjustment (40) 14
7,105 6,810
20,541 19,966
See accompanying Notes to the Consolidated Financial Statements.
Consolidated Retained Earnings
(unaudited) Year ended December 31
(millions of dollars) 2003 2002
Balance at beginning of year 854 586
Net income 909 805
Preferred securities charges (36) (36)
Preferred share dividends (22) (22)
Common share dividends (520) (479)
1,185 854
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 year ended December 31, 2003 include
the accounts of TCPL and the consolidated accounts of all its subsidiaries.
On December 3, 2003, TCPL increased its ownership interest in Portland Natural
Gas Transmission System Partnership (Portland) from 43.4 per cent to 61.7 per
cent. Subsequent to the acquisition, Portland was fully consolidated in the
company's financial statements, with 38.3 per cent reflected in non-controlling
interests.
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.
Regulation
In December 2002, the National Energy Board (NEB) approved TCPL's application
for the Canadian Mainline to charge interim tolls for transportation service,
effective January 1, 2003. In August 2003, subsequent to the NEB's decision on
the 2003 Tolls and Tariff Application, it approved interim tolls for the period
September 1, 2003 to December 31, 2003. The NEB determined that tolls will
remain interim pending a decision from the Federal Court of Appeal on TCPL's
Fair Return Review and Variance Application. Any adjustments to the interim
tolls will be recorded in accordance with the final NEB decision.
3. Segmented Information
Gas Transmission Power Corporate Total
Three months ended December 31 2003 2002 2003 2002 2003 2002 2003 2002
(unaudited - millions of
dollars)
Revenues 982 1,007 337 331 - - 1,319 1,338
Cost of sales - - (159) (161) - - (159) (161)
Other costs and expenses (326) (319) (106) (103) (2) (1) (434) (423)
Depreciation (202) (197) (20) (20) - - (222) (217)
Operating income/(loss) 454 491 52 47 (2) (1) 504 537
Financial and preferred equity
charges and
non-controlling interests (193) (205) (4) (4) (22) (21) (219) (230)
Financial charges of joint (14) (23) - - - - (14) (23)
ventures
Equity income 7 7 7 - - - 14 7
Interest and other income 6 5 4 2 6 10 16 17
Income taxes (100) (113) (15) (15) 7 - (108) (128)
Continuing operations 160 162 44 30 (11) (12) 193 180
Discontinued operations - -
Net Income Applicable to
Common Shares 193 180
Gas Transmission Power Corporate Total
Year ended December 31 2003 2002 2003 2002 2003 2002 2003 2002
(unaudited - millions of
dollars)
Revenues 3,956 3,921 1,401 1,293 - - 5,357 5,214
Cost of sales - - (692) (627) - - (692) (627)
Other costs and expenses (1,270) (1,166) (405) (371) (7) (9) (1,682) (1,546)
Depreciation (831) (783) (82) (65) (1) - (914) (848)
Operating income/(loss) 1,855 1,972 222 230 (8) (9) 2,069 2,193
Financial and preferred equity
charges and
non-controlling interests (781) (821) (11) (13) (89) (91) (881) (925)
Financial charges of joint (76) (90) (1) - - - (77) (90)
ventures
Equity income 66 33 99 - - - 165 33
Interest and other income 17 17 14 13 29 23 60 53
Income taxes (459) (458) (103) (84) 27 25 (535) (517)
Continuing operations 622 653 220 146 (41) (52) 801 747
Discontinued operations 50 -
Net Income Applicable to
Common Shares 851 747
Total Assets
December 31 2003 2002
(millions of dollars) (unaudited)
Gas Transmission 16,972 16,979
Power 2,746 2,391
Corporate 812 457
Continuing Operations 20,530 19,827
Discontinued 11 139
Operations
20,541 19,966
4. Long-Term Debt
December 31 2003 2002
(millions of dollars) (unaudited)
Alberta System 2,341 2,892
Foreign exchange differential recoverable through
the tollmaking process (16) (271)
2,325 2,621
Canadian Mainline 4,913 5,277
Foreign exchange differential recoverable through
the tollmaking process (60) (330)
4,853 4,947
Other 2,837 1,764
10,015 9,332
Less: current portion of long-term debt 550 517
9,465 8,815
On June 9, 2003, the company issued US$350 million of unsecured 4.00 per cent
notes maturing on June 15, 2013. On November 18, 2003, the company issued $450
million of unsecured 5.65 per cent notes maturing on January 15, 2014.
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 December 31, 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 account in Shareholders' Equity.
Asset/(Liability)
December 31 2003 2002
(millions of dollars) (unaudited)
Carrying Fair Carrying Fair
Amount Value Amount Value
Foreign Exchange
Cross-currency swaps
U.S. dollars 65 65 (8) (8)
At December 31, 2003, the notional principal amounts of cross-currency swaps
were US$250 million (2002 - US$350 million).
Reconciliation of Foreign Exchange Adjustment
December 31 2003 2002
(millions of dollars) (unaudited)
Balance at beginning of year 14 13
Translation (losses)/gains on foreign currency denominated net (136) 3
assets
Foreign exchange gains/(losses) on derivatives, and 82 (2)
other
(40) 14
Foreign Exchange and Interest Rate Management Activity
The company manages the foreign exchange risk of U.S. dollar debt, U.S. dollar
expenses and the interest rate exposures of the Alberta System, the Canadian
Mainline and the Foothills System through the use of foreign currency and
interest rate derivatives. These derivatives are comprised of contracts for
periods up to nine years. Certain of the realized gains and losses on these
derivatives are shared with shippers on predetermined terms.
Asset/(Liability)
December 31 2003 2002
(millions of dollars) (unaudited)
Carrying Fair Carrying Fair
Amount Value Amount Value
Foreign Exchange
Cross-currency swaps (26) (26) 56 56
Interest Rate
Interest rate swaps
Canadian dollars 2 15 4 56
U.S. dollars - 8 (1) 4
At December 31, 2003, the notional principal amounts of cross-currency swaps
were US$282 million (2002 - US$282 million). Notional principal amounts for
interest rate swaps were $964 million (2002 - $874 million) and US$100 million
(2002 - US$175 million).
6. Discontinued Operations
The Board of Directors approved plans to dispose of the company's International,
Canadian Midstream, and certain other businesses (December Plan) and the Gas
Marketing business in December 1999 and July 2001, respectively. The company's
disposals under both plans were substantially completed at December 31, 2001.
TCPL's investments in Gasoducto del Pacifico, INNERGY Holdings S.A. and P.T.
Paiton Energy Company approved for disposal under the December Plan will be
accounted for as part of continuing operations as of December 31, 2003, due to
the length of time it has taken the company to dispose of these assets. It is
the intention of the company to continue with its plan to dispose of these
investments.
The company mitigated certain of its remaining exposures associated with the
contingent liabilities related to the divested Gas Marketing operations by
acquiring from a subsidiary of Mirant Corporation certain contracts under which
it still had exposure in 2003, and simultaneously hedging the market price
exposures of these contracts. The company remains contingently liable for
certain residual obligations. In 2003, $50 million of the original
approximately $100 million after-tax deferred gain was recognized in income.
The after-tax deferred gain is included in Deferred Amounts.
At December 31, 2003, TCPL reviewed the provision for loss on discontinued
operations and the deferred gain and concluded that the remaining provision was
adequate and the deferral of the remaining approximately $50 million of
after-tax deferred gain related to the Gas Marketing business was appropriate.
Revenues from discontinued operations for the year ended December 31, 2003 were
$2 million (2002 - $36 million). Net income/(loss) from discontinued operations
for the year ended December 31, 2003 was $50 million, net of $29 million income
taxes (2002 - nil). The provision for loss on discontinued operations at
December 31, 2003 was $41 million (2002 - $83 million). The provision for loss
on discontinued operations is included in Accounts Payable.
7. Investment in Bruce Power L.P.
On February 14, 2003, the company acquired a 31.6 per cent interest in Bruce
Power L.P. (Bruce Power) for $409 million, including closing adjustments. As
part of the acquisition, the company also funded a one-third share ($75 million)
of a $225 million accelerated deferred rent payment made by Bruce Power to
Ontario Power Generation. The resulting note receivable from Bruce Power 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
Capital lease 301
Power sales agreements (131)
Pension liability and other (42)
409
The amount allocated to the investment in Bruce Power includes a purchase price
allocation of $301 million to the capital lease of the Bruce Power plant which
will be amortized on a straight-line basis over the lease term which extends to
2018, resulting in an annual amortization expense of $19 million. The amount
allocated to the power sales agreements will be amortized to income over the
remaining term of the underlying sales contracts. 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 amount
allocated to the pension liability will be amortized to income over the 11 year
expected average remaining service life of Bruce Power employees, resulting in
an annual amortization of $3 million.
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, which is estimated to be
approximately $90 million over three years. In the year ended December 31,
2003, TCPL funded $34 million of this loan which is included in Other Assets.
The ability to recover this investment is contingent upon the outcome of the
project.
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: Hejdi Feick/Anita Perry at (403) 920-7859.
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
FR DDGDBBBXGGSG
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