RNS Number:8316L
TransCanada Pipelines Ld
03 May 2005
6-K
0000099070
xxxxxxx
03/31/2005
NYSE
EDGAR Advantage Service Team
(800) 688 - 1933
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 6-K
REPORT OF FOREIGN PRIVATE ISSUER
PURSUANT TO RULE 13a-16 OR 15d-16 OF
THE SECURITIES EXCHANGE ACT OF 1934
For the month of May 2005
COMMISSION FILE No. 1-8887
TransCanada PipeLines Limited
(Translation of Registrant's Name into English)
450 - 1 Street S.W., Calgary, Alberta, T2P 5H1, Canada
(Address of Principal Executive Offices)
Indicate by check mark whether the registrant files or will file annual reports
under cover of Form 20-F or Form 40-F
Form 20-F o Form 40-F y
Indicate by check mark whether the registrant by furnishing the information
contained in this Form is also thereby furnishing the information to the
Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.
Yes o No y
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I
The documents listed below in this Section and filed as Exhibits 13.1 to 13.3
and 99.1 to this Form 6-K are hereby filed with the Securities and Exchange
Commission for the purpose of being and hereby are incorporated by reference
into Registration Statement on Form F-9 (Reg. No. 333-121265) under the
Securities Act of 1933, as amended.
13.1 Management's Discussion and Analysis of Financial Condition and Results
of Operations of the registrant as at and for the period ended March
31, 2005.
13.2 Consolidated comparative interim unaudited financial statements of the
registrant for the period ended March 31, 2005 (included in the
registrant's First Quarter 2005 Quarterly Report).
13.3 U.S. GAAP reconciliation of the consolidated comparative interim
unaudited financial statements of the registrant contained in the
registrant's First Quarter 2005 Quarterly Report.
99.1 Schedule of earnings coverage calculations at March 31, 2005.
II
The document listed below in this Section and in the Exhibit Index to this Form
6-K is hereby filed with the Securities and Exchange Commission.
99.2 Comfort letter of KPMG LLP dated April 29, 2005.
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.
TRANSCANADA PIPELINES LIMITED
By: /s/ Russell K. Girling
Russell K. Girling
Executive Vice-President, Corporate
Development and Chief Financial Officer
By: /s/ Lee G. Hobbs
Lee G. Hobbs
Vice-President and Controller
May 3, 2005
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EXHIBIT INDEX
13.1 Management's Discussion and Analysis of Financial Condition and
Results of Operations of the registrant as at and for the period ended
March 31, 2005.
13.2 Consolidated comparative interim unaudited financial statements of the
registrant for the period ended March 31, 2005 (included in the
registrant's First Quarter 2005 Quarterly Report).
13.3 U.S. GAAP reconciliation of the consolidated comparative interim
unaudited financial statements of the registrant contained in the
registrant's First Quarter 2005 Quarterly Report.
31.1 Certification of Chief Executive Officer pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002.
31.2 Certification of Chief Financial Officer pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002.
32.1 Certification of Chief Executive Officer regarding Periodic Report
containing Financial Statements.
32.2 Certification of Chief Financial Officer regarding Periodic Report
containing Financial Statements.
99.1 Schedule of earnings coverage calculations at March 31, 2005.
99.2 Comfort letter of KPMG LLP dated April 29, 2005.
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Exhibit 13.1
TRANSCANADA PIPELINES LIMITED - FIRST QUARTER 2005
Quarterly Report
Management's Discussion and Analysis
Management's discussion and analysis (MD&A) dated April 29, 2005 should be read
in conjunction with the accompanying unaudited consolidated financial statements
of TransCanada PipeLines Limited (TCPL or the company) for the three months
ended March 31, 2005 and should also be read in conjunction with the audited
consolidated financial statements and MD&A contained in TCPL's 2004 Annual
Report for the year ended December 31, 2004. Additional information relating to
TCPL, including the company's Annual Information Form and continuous disclosure
documents, is available on SEDAR at www.sedar.com under TransCanada PipeLines
Limited. Amounts are stated in Canadian dollars unless otherwise indicated.
Segment Results-at-a-Glance
Three months ended March 31 (unaudited) 2005 2004
(millions of dollars)
Gas Transmission 211 149
Power 30 65
Corporate (9) -
Net Income Applicable to Common Shares 232 214
Results of Operations
Consolidated
TCPL's net income applicable to common shares (net earnings) for first quarter
2005 was $232 million compared to $214 million for the same period in 2004. The
increase of $18 million was primarily due to significantly higher net income
from the Gas Transmission business resulting mainly from a gain of $48 million
after tax on the sale of 3.5 million common units of TC PipeLines, LP (PipeLines
LP) in first quarter 2005. Excluding this gain, Gas Transmission's net earnings
for first quarter 2005 increased $14 million mainly due to net income of $23
million generated from the
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Gas Transmission Northwest System and the North Baja System (collectively GTN),
which were acquired by TCPL on November 1, 2004. This increase from GTN was
partially offset by lower net income from the Alberta System and the Other Gas
Transmission businesses.
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A decrease of $35 million in Power's net income for first quarter 2005 compared
to first quarter 2004 was primarily due to lower operating and other income from
Eastern Operations and Bruce Power L.P. (Bruce Power). Operating and other
income from Eastern Operations was lower by $29 million in first quarter 2005
compared to the same period in 2004 primarily as a result of a $10 million
after-tax ($16 million pre-tax) cost for the restructuring of natural gas supply
contracts by Ocean State Power (OSP) and a $7 million reduction in after-tax
income ($12 million pre tax) as a result of the sale of the Curtis Palmer
hydroelectric facilities to TransCanada Power, L.P. (Power LP) in April 2004.
Bruce Power's equity income was lower mainly due to increased operating
expenses.
The increase of $9 million in the Corporate segment's net expenses was mainly as
a result of higher financial charges in first quarter 2005 compared to the same
period in 2004, and income tax refunds and refund interest received in first
quarter 2004, partially offset by certain positive tax adjustments recorded in
first quarter 2005.
Funds generated from operations of $407 million for first quarter 2005 decreased
$8 million compared to first quarter 2004.
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Gas Transmission
The Gas Transmission business generated net income of $211 million for the
quarter ended March 31, 2005 compared to $149 million for the same period in
2004.
Gas Transmission Results-at-a-Glance
Three months ended March 31 (unaudited)
(millions of dollars) 2005 2004
Wholly-Owned Pipelines
Canadian Mainline 63 64
Alberta System 37 40
GTN (1) 23
Foothills System 5 6
BC System 2 2
130 112
Other Gas Transmission
Great Lakes 14 17
Iroquois 4 8
PipeLines LP 4 4
Portland 6 6
Ventures LP 3 3
TQM 2 2
CrossAlta 5 1
TransGas 3 3
Northern Development (1) (1)
General, administrative, support costs and other (7) (6)
33 37
Gain related to PipeLines LP 48 -
81 37
Net Income 211 149
--------------------
(1) TCPL acquired GTN on November 1, 2004.
Wholly-Owned Pipelines
Canadian Mainline's first quarter 2005 net income of $63 million was $1 million
lower than the same quarter in 2004. This decrease is primarily due to a lower
rate of return on common equity (ROE), as determined by the National Energy
Board (NEB), of 9.46 per cent in 2005 compared to 9.56 per cent in 2004 and a
lower average investment base, partially offset by a prior year negative
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earnings adjustment of $2 million recorded in first quarter 2004. Canadian
Mainline's interim tolls and net income in 2005 assume a capital structure
comprised of 33 per cent deemed common equity pending the decision on the 2004
Tolls and Tariff Application (Phase II) hearing dealing with capital structure.
The Alberta System's net income of $37 million in first quarter 2005 is $3
million lower than the same quarter in 2004. The decrease is primarily due to a
lower investment base in 2005 as well as a lower approved rate of return in
2005. Net income in 2005 reflects a return of 9.50 per cent, as prescribed by
the Alberta Energy and Utilities Board (EUB), on deemed common equity of 35 per
cent.
GTN, which was acquired by TCPL in November 2004, generated net income of $23
million in first quarter 2005. The decrease of $1 million in the Foothills
System's first quarter 2005 net income compared to the same period in the prior
year is primarily due to a lower average investment base in 2005.
Operating Statistics
Three months ended Canadian Alberta System Gas Foothills System BC System
March 31 Mainline (1) (2) Transmission
Northwest
System (3)
(unaudited) 2005 2004 2005 2004 2005 2005 2004 2005 2004
Average investment
base ($ millions) 7,910 8,314 4,559 4,762 n/a (3) 693 722 220 231
Delivery volumes
(Bcf)
Total 767 723 1,051 1,013 215 287 281 94 87
Average per day 8.5 7.9 11.7 11.1 2.4 3.2 3.1 1.1 1.0
--------------------
(1) Canadian Mainline deliveries originating at the Alberta border and in
Saskatchewan for the three months ended March 31, 2005 were 531 Bcf (2004 - 510
Bcf); average per day was 5.9 Bcf (2004 - 5.6 Bcf).
(2) Field receipt volumes for the Alberta System for the three months ended
March 31, 2005 were 965 Bcf (2004 - 950 Bcf); average per day was 10.7 Bcf (2004
- 10.4 Bcf).
(3) TCPL acquired GTN on November 1, 2004. Both the Gas Transmission Northwest
System and the North Baja System are currently operating under fixed rate models
approved by the Federal Energy Regulatory Commission and, as a result, the
systems' current results are not dependent on average investment base. The North
Baja System's total delivery volumes were 19 Bcf; average per day was 0.2 Bcf.
Other Gas Transmission
TCPL's proportionate share of net income from its Other Gas Transmission
businesses was $81 million for the three months ended March 31, 2005 compared to
$37 million for the same period in 2004. The first quarter 2005 results include
a $48 million after-tax gain on sale of an approximate 20 per cent interest in
PipeLines LP. Excluding this gain, net income for the quarter decreased $4
million compared to the same period in 2004. The decrease is mainly due to
lower income from Iroquois primarily as
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a result of a positive tax adjustment recorded in first quarter 2004, and lower
income from Great Lakes as a result of lower short-term revenues and higher
operating and maintenance costs in first quarter 2005. Other Gas Transmission
results were also negatively impacted by a weaker U.S. dollar compared to 2004.
These decreases were partially offset by higher earnings from CrossAlta as a
result of favourable natural gas storage market conditions. As at March 31,
2005, TCPL had capitalized $3 million of costs related to its Broadwater
liquified natural gas (LNG) project.
On March 23, 2005, TCPL sold 3.5 million common units of PipeLines LP for net
proceeds of approximately $151 million (US$124 million), resulting in an
after-tax gain of approximately $48 million (US$40 million). In April 2005,
underwriters purchased an additional 74,200 common units, exercising, in part,
their option to purchase up to 525,000 additional units on the same terms and
conditions as the 3.5 million common units previously sold. PipeLines LP did
not receive any proceeds from the sale of the common units. Subsequent to this
transaction and the underwriters' exercise of their option, TCPL continues to
own a 13.4 per cent interest in PipeLines LP represented by the general partner
interest of 2.0 per cent as well as an 11.4 per cent limited partner interest.
Power
Power Results-at-a-Glance
Three months ended March 31 (unaudited)
(millions of dollars) 2005 2004
Western operations 30 35
Eastern operations 5 34
Bruce Power investment 30 48
Power LP investment 9 10
General, administrative, support costs and other (25) (25)
Operating and other income 49 102
Financial charges (4) (2)
Income taxes (15) (35)
Net Income 30 65
Power's net income in first quarter 2005 of $30 million decreased $35 million
compared to $65 million in first quarter 2004. The decrease resulted mainly
from lower operating and other income in Eastern Operations and Bruce Power.
Eastern Operations' operating and other income was $29 million lower in first
quarter 2005 compared to first quarter 2004 due to a $16 million pre-tax ($10
million after-tax) one-time contract
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restructuring payment from OSP to its natural gas fuel suppliers and a $12
million pre-tax ($7 million after-tax) reduction in income as a result of the
sale of the Curtis Palmer hydroelectric facilities to Power LP in April 2004.
Bruce Power's equity income was lower by $18 million in first quarter 2005
compared to first quarter 2004. Effective March 1, 2004, Bruce Power moved from
a five-unit operation to a six-unit operation with the commercial startup of
Unit 3. Planned maintenance outages on Units 3 and 4 in first quarter 2005
reduced the otherwise potential increase in total plant output as a result of
adding a sixth operating unit. Bruce Power experienced higher operating
expenses, including depreciation, in first quarter 2005 as a result of adding
Unit 3. The $18 million decrease in Bruce Power's equity income reflects this
increase in operating expenses, partially offset by a three per cent increase in
total plant output and slightly higher realized prices.
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Western Operations
Western Operations Results-at-a-Glance (1)
Three months ended March 31 (unaudited)
(millions of dollars) 2005 2004
Revenue
Power sales 164 147
Other (2) 11 7
175 154
Cost of sales (109) (90)
Other costs and expenses (31) (22)
Depreciation (5) (7)
Operating and other income 30 35
--------------------
(1) ManChief is included until April 30, 2004
(2) Includes Cancarb Thermax, inter-segment eliminations and miscellaneous
Western Operations Sales Volumes (1)
Three months ended March 31 (unaudited)
(GWh) 2005 2004
Generation vs. Purchased
Generation 636 362
Purchased
Sundance A & B PPAs 1,831 1,812
Other purchases (2) 731 702
3,198 2,876
Contracted vs. Spot
Contracted 2,685 2,678
Spot 513 198
3,198 2,876
--------------------
(1) ManChief is included until April 30, 2004
(2) Includes Sheerness PPA volumes
Western Operations' operating and other income in first quarter 2005 was $30
million compared to $35 million earned in the same period in 2004. The $5
million decrease was mainly due to reduced margins in first quarter 2005
resulting from lower market heat rates on uncontracted volumes of power
generated. Lower market heat rates are the result of spot market power prices
in Alberta that averaged approximately $3 per megawatt hour (MWh) less, and
average natural gas prices that were slightly higher, in first quarter 2005
compared to 2004. A significant portion of plant generation in Western
Operations is sold under long-term contract to mitigate price risk. Some output
is intentionally not committed under long-term contract to assist in managing
Power's overall portfolio of generation. This approach to portfolio management
assists in minimizing costs in situations where TCPL would otherwise have to
purchase power in the open market to fulfill its contractual obligations.
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Western Operations' revenues increased in first quarter 2005 primarily due to
the start-up of the MacKay River facility in mid-2004 and higher revenues from
the Sundance power purchase arrangements (PPAs) partially offset by the sale of
the ManChief plant to Power LP in April 2004. Generation volumes in first
quarter 2005 increased 274 gigawatt hours (GWh) to 636 GWh primarily due to the
start-up of the MacKay River facility. Partially offsetting this increase are
decreases in volumes associated with unplanned outages at the Bear Creek
cogeneration facility in first quarter 2005 and the sale of the ManChief plant.
Revenues and cost of sales, related to the Sundance A and B PPAs, increased in
2005 primarily due to higher plant availability and higher power prices under
the PPA's. Other costs and expenses were higher in 2005 primarily due to
operating costs associated with the MacKay River facility. Depreciation was
lower in first quarter 2005 due to the sale of the ManChief plant partially
offset by the start-up of the MacKay River facility. In first quarter 2005,
approximately 16 per cent of power sales volumes were sold into the spot market
compared to seven per cent in 2004. To reduce its exposure to spot market
prices on uncontracted volumes, Western Operations, as at March 31, 2005, had
fixed price sales contracts to sell forward 7,200 GWh of power for the remainder
of 2005 and 7,400 GWh of power for 2006.
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Eastern Operations
Eastern Operations Results-at-a-Glance (1)
Three months ended March 31 (unaudited)
(millions of dollars) 2005 2004
Revenue
Power sales 114 146
Other - 1
114 147
Cost of sales (51) (76)
Other costs and expenses (54) (30)
Depreciation (4) (7)
Operating and other income 5 34
--------------------
(1) Curtis Palmer is included until April 30, 2004.
Eastern Operations Sales Volumes (1)
Three months ended March 31 (unaudited)
(GWh) 2005 2004
Generation vs. Purchased
Generation 444 377
Purchased 811 1,234
1,255 1,611
Contracted vs. Spot
Contracted 1,189 1,544
Spot 66 67
1,255 1,611
--------------------
(1) Curtis Palmer is included until April 30, 2004.
Operating and other income in first quarter 2005 from Eastern Operations of $5
million was $29 million lower compared to $34 million earned in the same period
in 2004. The decrease was due primarily to a $16 million pre-tax ($10 million
after-tax) contract restructuring payment made by OSP to its natural gas fuel
suppliers and a $12 million pre-tax ($7 million after-tax) reduction in income
as a result of the sale of the Curtis Palmer hydroelectric facilities to Power
LP in April 2004. Partially offsetting these decreases was income from the
Grandview cogeneration facility in New Brunswick which was placed in-service in
January 2005. In addition, TCPL mitigated the impact of increased fuel gas costs
at OSP in first quarter 2005.
In first quarter 2005, OSP concluded negotiations with its two Canadian natural
gas fuel suppliers and terminated the 20-year purchase contracts which were to
expire in 2011. Pricing under the terminated purchase contracts had been
subject to numerous arbitration proceedings since late 2001. The latest
arbitration, in August 2004, had substantially increased OSP's cost of natural
gas to a price in excess of market. New contracts were entered into with the
existing natural gas suppliers, effective March 2005 and expiring in October
2008, at an agreed upon pricing mechanism based on market, which is not subject
to future arbitration proceedings. As part of these arrangements, payments of
$16
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million were made to the natural gas suppliers. The contract restructuring was
a positive event for OSP and management determined, based on current market
conditions, there was no asset impairment writedown of OSP required.
Generation volumes in first quarter 2005 increased 67 GWh to 444 GWh compared to
377 GWh in 2004 primarily due to the Grandview cogeneration facility being
placed into service on January 1, 2005. Partially offsetting this increase are
decreases in volumes associated with the sale of the Curtis Palmer hydroelectric
facility to Power LP in April 2004 and reduced generation from the OSP facility.
Purchased and contracted sales volumes, and the related revenues and cost of
sales, decreased year-over-year primarily due to the expiration of long-term
contracts held at the end of 2004. Other costs and expenses increased $24
million primarily as a result of OSP's settlement with its fuel gas suppliers
and higher fuel gas costs. Depreciation in first quarter 2005 decreased from
first quarter 2004 due to the sale of Curtis Palmer to Power LP in April 2004.
In first quarter 2005, approximately five per cent of power sales volumes were
sold into the spot market compared to four per cent in 2004. Eastern Operations
is focused on selling the majority of its power under contract to wholesale,
commercial and industrial customers while managing a portfolio of power supplies
sourced from its own generation, wholesale power purchases and power purchased
from Power LP's Castleton plant. To reduce its exposure to spot market prices,
Eastern Operations, as at March 31, 2005, had entered into fixed price sales
contracts to sell forward 3,600 GWh of power for the remainder of 2005 and 2,800
GWh of power for 2006. Certain contracted volumes are dependent on customer
usage levels.
Bruce Power Investment
Bruce Power Results-at-a-Glance
Three months ended March 31 (unaudited)
(millions of dollars) 2005 2004
Bruce Power (100 per cent basis)
Revenues 418 399
Operating expenses
Cash costs (materials, labour, services and fuel) (265) (219)
Non-cash costs (depreciation and amortization) (48) (31)
(313) (250)
Operating income 105 149
Financial charges (17) (18)
Income before income taxes 88 131
TCPL's interest in Bruce Power income before income taxes 28 41
Adjustments 2 7
TCPL's income from Bruce Power before income taxes 30 48
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Bruce Power's equity income was lower by $18 million in first quarter 2005
compared to first quarter 2004. Effective March 1, 2004, Bruce Power moved from
a five-unit operation to a six-unit operation with the commercial startup of
Unit 3. Planned maintenance outages on Units 3 and 4 in first quarter 2005
reduced the otherwise potential increase in total plant output as a result of
adding a sixth operating unit. Bruce Power experienced higher operating
expenses, including depreciation, in first quarter 2005 as a result of adding
Unit 3. The $18 million decrease in Bruce Power's equity income reflects this
increase in operating expenses, partially offset by a three per cent increase in
total plant output and slightly higher realized prices.
TCPL's share of power output from Bruce Power for first quarter 2005 was 2,598
GWh compared to 2,530 GWh in first quarter 2004. This increase primarily
reflects higher output in 2005 as a result of a reduction in unplanned outages
in first quarter 2005 compared to first quarter 2004. Approximately 79 reactor
days of planned maintenance outages as well as 17 reactor days of minor
unplanned outages occurred in first quarter 2005. In first quarter 2004, Bruce
Power experienced 49 reactor days of unplanned outages and Unit 3 was
unavailable for 60 days due to completion of initial restart activities. The
Bruce units ran at an average availability of 81 per cent in first quarter 2005,
compared to an 80 per cent average availability during first quarter 2004. A
scheduled maintenance outage on Unit 3 began on January 8, 2005 and the unit
returned to service on March 8, 2005. Unit 4 began a similar planned maintenance
outage on March 12, 2005 that is also expected to last approximately two months.
Overall prices achieved during first quarter 2005 were approximately $50 per
MWh, compared to approximately $49 per MWh in first quarter 2004. Approximately
50 per cent of the available output was sold into Ontario's wholesale spot
market in first quarter 2005 with the remainder being sold under longer term
contracts. On a per unit basis, Bruce operating expenses increased to $38 per
MWh in first quarter 2005 from $31 per MWh in first quarter 2004. This increase
is due partly to increased outage costs, primarily related to the Units 3 and 4
planned maintenance outages. The increase in operating expenses is also the
result of higher staff and lease costs in first quarter 2005, reflecting the
move to a six-unit site. In addition, the completion of the Unit 3 restart has
resulted in higher depreciation and lower capitalization of labour and other
in-house costs in first quarter 2005.
Adjustments to TCPL's interest in Bruce Power income before income taxes for the
three months ended March 31, 2005 were lower than in 2004 primarily due to the
cessation of interest capitalization upon the return to service of Unit 3 as
well as lower amortization
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of the purchase price discrepancy related to the fair value of sales contracts
in place at the time of acquisition.
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 40 per cent of planned output for the balance of
2005.
On April 15, 2005, Bruce Power experienced a transformer fire outside of the
generating facility. As a result, Unit 6 went offline and some biodegradable
mineral oil entered into Lake Huron, the clean up of which is close to complete.
Unit 6 is expected to return to service in late May and the cost to replace
the damaged transformer is not expected to be significant. Primarily as a
result of this unplanned outage, overall plant availability for Bruce Power in
2005 is expected to reduce to 83 per cent from the previously reported 85 per
cent.
In March 2005, a tentative agreement was reached with an Ontario provincial
negotiator for the potential restart of Units 1 and 2 at Bruce Power. Details
of the tentative agreement, which have been approved in principle by the Boards
of Directors of the major partners of Bruce Power, are now being considered by
the Ontario government.
Power LP Investment
Operating and other income of $9 million from Power LP in first quarter 2005 was
$1 million lower compared to $10 million in first quarter 2004. The decrease
was primarily due to TCPL's reduced ownership interest in Power LP in 2005 (30.6
per cent compared to 35.6 per cent in first quarter 2004) and the recognition in
second quarter 2004 of all previously deferred gains resulting from the removal
of the Power LP redemption obligation. Prior to the removal of the redemption
obligation, TCPL was recognizing into income the amortization of these deferred
gains over a period through to 2017. Additional earnings from Power LP's second
quarter 2004 acquisition of the Curtis Palmer and ManChief facilities partially
offset these decreases.
General, Administrative, Support Costs and Other
General, administrative, support costs and other of $25 million in first quarter
2005 were comparable to the same period in 2004.
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Power Sales Volumes and Plant Availability
Power Sales Volumes
Three months ended March 31 (unaudited)
(GWh) 2005 2004
Western operations (1) 3,198 2,876
Eastern operations (1) 1,255 1,611
Bruce Power investment (2) 2,598 2,530
Power LP investment (1) (3) 697 572
Total 7,748 7,589
--------------------
(1) ManChief and Curtis Palmer volumes are included in Power LP investment
effective April 30, 2004.
(2) Sales volumes reflect TCPL's 31.6 per cent share of Bruce Power output.
(3) TCPL operates and manages Power LP. The volumes in the table represent 100
percent of Power LP's sales volumes.
Weighted Average Plant Availability (1)
Three months ended March 31 (unaudited) 2005 2004
Western operations (2) 93 % 99 %
Eastern operations (2) 85 % 98 %
Bruce Power investment (3) 81 % 80 %
Power LP investment (2) 99 % 99 %
All plants, excluding Bruce Power investment 91 % 89 %
All plants 87 % 85 %
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(1) Plant availability represents the percentage of time in the year that the
plant is available to generate power, whether actually running or not and is
reduced by planned and unplanned outages.
(2) ManChief and Curtis Palmer are included in Power LP investment effective
April 30, 2004.
(3) Unit 3 is included effective March 1, 2004.
In late February 2005, OSP experienced an unplanned outage affecting 50 per cent
of the capacity of this facility. This outage is expected to continue into third
quarter 2005. This outage is not expected to significantly impact Eastern
Operations' operating income.
Corporate
Net expenses were $9 million and nil for the three months ended March 31, 2005
and 2004 respectively. The $9 million increase in net expenses is primarily due
to increased interest expense on debt that was issued in 2004 and the receipt of
income tax refunds and related interest in first quarter 2004. These negative
variances were partially offset by certain positive tax adjustments recorded in
2005.
Liquidity and Capital Resources
Funds Generated from Operations
Funds generated from continuing operations were $407 million for the three
months ended March 31, 2005 compared with $415 million for the same period in
2004.
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TCPL expects that its ability to generate adequate amounts of cash in the short
term and the long term, when needed, and to maintain financial capacity and
flexibility to provide for planned growth remains substantially unchanged since
December 31, 2004.
Investing Activities
In the three months ended March 31, 2005, capital expenditures totalled $108
million (2004 - $101 million) and related primarily to construction of new power
plants, and maintenance and capacity capital in the Gas Transmission business.
Financing Activities
TCPL retired $321 million of long-term debt in the three months ended March 31,
2005. In January 2005, the company issued $300 million of medium-term notes
bearing interest at 5.10 per cent due in 2017. For the three months ended March
31, 2005, outstanding notes payable increased by $244 million, while cash and
short-term investments increased by $438 million.
Dividends
On April 29, 2005, TCPL's Board of Directors declared a dividend for the quarter
ending June 30, 2005 in an aggregate amount equal to the aggregate quarterly
dividend to be paid on July 29, 2005 by TransCanada Corporation on the issued
and outstanding common shares as at the close of business on June 30, 2005. The
Board also declared regular dividends on TCPL's preferred shares.
Contractual Obligations
Power's commodity purchase obligations as disclosed in the MD&A in TCPL's 2004
Annual Report were as follows: 2005 - $429 million, 2006 - $255 million; 2007 -
$259 million; 2008 - $266 million; 2009 - $277 million and 2010+ - $2,658
million. Primarily as a result of new contracts in first quarter 2005, Power's
commodity purchase obligations are currently estimated to be as follows:
remainder of 2005 - $583 million; 2006 - $653 million; 2007 - $627 million; 2008
- $550 million; 2009 - $273 million and 2010+ - $2,648 million. There have been
no other material changes to TCPL's contractual obligations, including payments
due for the next five years and thereafter, since December 31, 2004. For
further information on these contractual obligations, refer to the MD&A in
TCPL's 2004 Annual Report.
Financial and Other Instruments
The following represents the material changes to the company's risk management
and financial instruments since December 31, 2004.
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Energy Price Risk Management
The company executes power, natural gas and heat rate derivatives in order to
manage exposure and risks associated with its overall asset portfolio. Heat
rate contracts are contracts for the sale or purchase of power that are priced
based on a natural gas index. The fair values and notional volumes of the swap,
option, future and heat rate contracts are shown in the tables below. In
accordance with the company's accounting policy, each of the derivatives in the
table below is recorded on the balance sheet at its fair value at March 31, 2005
and December 31, 2004.
Power
March 31, 2005 December 31, 2004
(unaudited)
Asset/(Liability) Accounting Fair Fair
(millions of dollars) Treatment Value Value
Power - swaps
(maturing 2005 to 2011) Hedge (35) 7
(maturing 2005) Non-hedge 2 (2)
Gas - swaps, futures and options
(maturing 2005 to 2016) Hedge (24) (39)
(maturing 2005) Non-hedge (5) (2)
Heat rate contracts
(maturing 2005 to 2006) Hedge - (1)
15
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Notional Volumes
March 31, 2005 Accounting Power (GWh) Gas (Bcf)
(unaudited) Treatment Purchases Sales Purchases Sales
Power - swaps
(maturing 2005 to 2011) Hedge 1,752 7,237 - -
(maturing 2005) Non-hedge 330 - - -
Gas - swaps, futures and options
(maturing 2005 to 2016) Hedge - - 78 74
(maturing 2005) Non-hedge - - 3 6
Heat rate contracts
(maturing 2005 to 2006) Hedge - 76 - -
Notional Volumes Accounting Power (GWh) Gas (Bcf)
December 31, 2004 Treatment Purchases Sales Purchases Sales
Power - swaps Hedge 3,314 7,029 - -
Non-hedge 438 - - -
Gas - swaps, futures and options Hedge - - 80 84
Non-hedge - - 5 8
Heat rate contracts Hedge - 229 2 -
Risk Management
With respect to continuing operations, TCPL's market, financial and counterparty
risks remain substantially unchanged since December 31, 2004. For further
information on risks, refer to the MD&A in TCPL's 2004 Annual Report.
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.
16
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Critical Accounting Policy
TCPL's critical accounting policy, which remains unchanged since December 31,
2004, is the use of regulatory accounting for its regulated operations. For
further information on this critical accounting policy, refer to the MD&A in
TCPL's 2004 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 estimate from
December 31, 2004 continues to be depreciation expense. For further information
on this critical accounting estimate, refer to the MD&A in TCPL's 2004 Annual
Report.
Accounting Change
Financial Instruments - Disclosure and Presentation
Effective January 1, 2005, the company adopted the provisions of the Canadian
Institute of Chartered Accountants' amendment to the existing Handbook Section "
Financial Instruments - Disclosure and Presentation" which provides guidance
for classifying certain financial instruments that embody obligations that may
be settled by issuance of the issuer's equity shares as debt when the instrument
does not establish an ownership relationship. In accordance with this
amendment, TCPL reclassified the non-controlling interest component of preferred
securities as long-term debt.
This accounting change was applied retroactively with restatement of prior
periods. The impact of this change on TCPL's net income in first quarter 2005
and prior periods was nil.
The impact of the accounting change on the company's consolidated balance sheet
as at December 31, 2004 is as follows.
17
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(unaudited - millions of dollars) Increase/(Decrease)
Deferred Amounts (1) 135
Preferred Securities 535
Non-Controlling Interest
Preferred securities of subsidiary (670)
Total Liabilities and Shareholders' Equity -
--------------------
(1) Regulatory deferral
Outlook
In 2005, the company expects higher net income from the Gas Transmission segment
than originally anticipated as a result of the gain related to the sale of
PipeLines LP units. Excluding this impact, the company's outlook is relatively
unchanged since December 31, 2004. For further information on outlook, refer to
the MD&A in TCPL's 2004 Annual Report.
In 2005, TCPL will continue to direct its energies towards long-term growth
opportunities that will strengthen its financial performance and create
long-term value for shareholders. The company's net income 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.
Credit ratings on TransCanada PipeLines Limited'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
Canadian Mainline
In November 2004, the Canadian Association of Petroleum Producers (CAPP) filed
an application with the NEB to review and vary its decision on the 2004 Tolls
and Tariff Application with respect to three items:
* non-renewable firm transportation (FT-NR) service;
* long-term incentive compensation; and
* regulatory and legal costs.
18
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On February 18, 2005, the NEB decided to review its decision on the toll to be
charged for FT-NR, not to review its decision on disputed regulatory and legal
costs and, at CAPP's request, deferred its consideration of a review of its
decision regarding long-term incentive compensation. On April 13, 2005, CAPP
filed notice with the NEB to withdraw the portion of its application dealing
with long-term incentive compensation. The NEB heard oral arguments in Calgary,
in late April 2005, to consider tolling issues with respect to FT-NR.
In March 2005, TCPL filed an application for approval of a negotiated settlement
with respect to 2005 Canadian Mainline tolls. The settlement established
operating, maintenance and administration (OM&A) costs at $169.5 million with
variances between actual OM&A costs in 2005 and those agreed to in the
settlement accruing to TCPL. The majority of other cost elements of the 2005
revenue requirement will be treated on a flow through basis. Further, the 2005
ROE is set at 9.46 per cent and the deemed common equity component of the
Canadian Mainline's capital structure in 2005 shall be based on the NEB's
decision on the Canadian Mainline's cost of capital for 2004, subject to the
outcome of any review applications or appeals. On April 7, 2005, the NEB
approved TCPL's application for a negotiated settlement of 2005 Canadian
Mainline tolls as filed.
Alberta System
On March 10, 2005, TCPL reached a settlement with shippers and other interested
parties with respect to the annual revenue requirements of the Alberta System
for the years 2005, 2006 and 2007. The settlement encompasses all elements of
the Alberta System revenue requirement, including OM&A costs, return on equity,
depreciation and income and municipal taxes.
In the Alberta System settlement, OM&A costs are fixed at $193 million for 2005,
$201 million for 2006, and $207 million for 2007. Any variance between actual
OM&A and those agreed to in the settlement in each year will accrue to TCPL.
The majority of other cost elements of the 2005, 2006 and 2007 revenue
requirements will be treated on a flow through basis. The return on equity
capital will be calculated annually during the term of the settlement using the
EUB formula for the purpose of establishing the annual generic rate of return
for Alberta utilities on deemed common equity of 35 per cent. For 2005, the ROE
under the EUB formula is 9.50 per cent. Depreciation costs will be determined
using the depreciation rates and methodology that the company proposed to the
EUB in its 2004 General Rate Application (GRA).
On March 21, 2005, TCPL applied to the EUB for approval of the Alberta System
settlement for 2005 to 2007. Upon EUB approval of the settlement, TCPL intends
to withdraw its motion to the Alberta Court of Appeal filed in September 2004
for leave to appeal Phase
19
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1 of the 2004 GRA with respect to the disallowance of applied-for incentive
compensation costs.
TCPL will continue to charge interim tolls for 2005 for transportation service
on the Alberta System. The interim tolls, approved by the EUB in December 2004,
will remain in effect until final tolls are established through the Phase 2
proceeding of the Alberta System's 2005 GRA. The Phase 2 proceeding will
address the allocation of costs among transportation services and rate design.
TCPL filed this application with the EUB on April 15, 2005.
Other Gas Transmission
Northern Development
In March 2005, TCPL's wholly-owned subsidiary, Foothills Pipe Lines Ltd., signed
a Traditional Knowledge Protocol (Protocol) with the Kaska Nation. The Protocol
sets out how Kaska Traditional Knowledge will be incorporated into the planning,
construction and operations of the Alaska Highway Pipeline Project.
Power
USGen New England, Inc.
On April 1, 2005, TCPL closed its acquisition of hydroelectric generation
assets, with total generating capacity of 567 megawatts (MW), from USGen for
US$505 million, subject to specified closing adjustments.
There was an existing agreement in place between the Town of Rockingham (the
Town) and USGen which provided the Town with an option to purchase the 49MW
Bellows Falls facility for US$72 million. The option was exercised in December
2004 and its rights were assigned to the Vermont Hydroelectric Power Authority
(Vermont Hydroelectric). TCPL has assumed this obligation and will, therefore,
sell the Bellows Falls facility to Vermont Hydroelectric for US$72 million.
This transaction is expected to close by the end of second quarter 2005
following receipt of regulatory approvals and the satisfaction of certain
conditions under the option agreement. When the sale of the Bellows Falls
facility is completed, TCPL will have 12 dams and 36 hydroelectric generating
units on two rivers in New England: the 433 MW Connecticut River system in New
Hampshire and Vermont and the 84 MW Deerfield River system in Massachusetts and
Vermont.
20
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Other
In April 2005, Gas Transmission Northwest Corporation provided notice to the
holders of its US$150 million 7.80 per cent Senior Unsecured Debentures
(Debentures) that it will exercise its right to redeem all of the outstanding
Debentures on June 1, 2005. Holders of the Debentures will be entitled to
US$1,069.36 per US$1,000 principal amount. This amount includes US$30.36
representing the redemption premium and US$39.00 representing accrued and unpaid
interest to the redemption date.
Share Information
As at March 31, 2005, TCPL had 483,344,109 issued and outstanding common shares.
In addition, there were 4,000,000 Series U and 4,000,000 Series Y Cumulative
First Preferred Shares issued and outstanding as at March 31, 2005.
21
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Exhibit 13.2
FIRST QUARTER REPORT 2005
Selected Quarterly Consolidated Financial Data (1)
(unaudited) 2005 2004 2003
(millions of dollars except per First Fourth Third Second First Fourth Third Second
share amounts)
Revenues 1,305 1,407 1,247 1,278 1,266 1,319 1,391 1,311
Net Income applicable to common
shares
Continuing operations 232 184 192 388 214 193 198 202
Discontinued operations - - 52 - - - 50 -
232 184 244 388 214 193 248 202
Share Statistics
Net income per share - Basic and
diluted
Continuing operations $ 0.48 $ 0.38 $ 0.40 $ 0.81 $ 0.44 $ 0.40 $ 0.41 $ 0.42
Discontinued operations - - 0.11 - - - 0.11 -
$ 0.48 $ 0.38 $ 0.51 $ 0.81 $ 0.44 $ 0.40 $ 0.52 $ 0.42
--------------------
(1) The selected quarterly consolidated financial data has been prepared in
accordance with Canadian GAAP. For a discussion on the factors affecting the
comparability of the financial data, including discontinued operations, refer to
Note 1 and Note 22 of TCPL's 2004 audited consolidated financial statements
included in TCPL's 2004 Annual Report.
Factors Impacting Quarterly Financial Information
In the Gas Transmission business, which consists primarily of the company's
investments in regulated pipelines, annual revenues and net income from
continuing operations (net earnings) fluctuate over the long term based on
regulators' decisions and negotiated settlements with shippers. Generally,
quarter over quarter revenues and net earnings during any particular fiscal year
remain relatively stable with fluctuations arising as a result of adjustments
being recorded due to regulatory decisions and negotiated settlements with
shippers and due to items outside of the normal course of operations.
In the Power business, which consists primarily of the company's investments in
electrical power generation plants, quarter over quarter revenues and net
earnings are affected by seasonal weather conditions, customer demand, market
prices, planned and unplanned plant outages as well as items outside of the
normal course of operations.
Significant items which impacted the last eight quarters' net earnings are as
follows.
* Second quarter 2003 net earnings included a $19 million positive
after-tax earnings impact of a June 2003 settlement with a former counterparty
that had previously defaulted under power forward contracts.
* Third quarter 2003 net earnings included TCPL's $11 million share
of a positive future income tax benefit adjustment recognized by TransGas.
1
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* First quarter 2004 net earnings included approximately $12 million
of income tax refunds and related interest.
* Second quarter 2004 net earnings included after-tax gains related
to Power LP of $187 million, of which $132 million were previously deferred and
were being amortized into income to 2017.
* In third quarter 2004, the EUB's decisions on the GCOC and Phase I
of the 2004 GRA resulted in lower earnings for the Alberta System compared to
the previous quarters. In addition, third quarter 2004 included a $12 million
after-tax adjustment related to the release of previously established
restructuring provisions and recognition of $8 million of non-capital loss carry
forwards.
* In fourth quarter 2004, TCPL completed the acquisition of GTN,
thereby recording $14 million of net earnings from the November 1, 2004
acquisition date. Power recorded a $16 million pre-tax positive impact of a
restructuring transaction related to power purchase contracts between OSP and
Boston Edison in Eastern Operations.
* In first quarter 2005, net earnings included a $48 million
after-tax gain related to the sale of PipeLines LP units. Power earnings
included a $10 million after-tax cost for the restructuring of natural gas
supply contracts by OSP. In addition, Bruce Power's equity income was lower
than previous quarters due to the impact of planned maintenance outages and the
increase in operating costs as a result of moving to a six-unit operation.
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
2
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or obligation to update or revise any forward-looking statements, whether as a
result of new information, future events or otherwise.
3
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Consolidated Income
Three months ended March 31 (unaudited)
(millions of dollars) 2005 2004
Revenues 1,305 1,266
Operating Expenses
Cost of sales 160 166
Other costs and expenses 424 368
Depreciation 250 232
834 766
Operating Income 471 500
Other Expenses/(Income)
Financial charges 207 207
Financial charges of joint ventures 16 14
Equity income (41) (58)
Interest income and other (24) (15)
Gain related to PipeLines LP (80) -
78 148
Income before Income Taxes and Non-Controlling Interests 393 352
Income Taxes
Current 161 103
Future (12) 23
149 126
Non-Controlling Interests 6 6
Net Income 238 220
Preferred Share Dividends 6 6
Net Income Applicable to Common Shares 232 214
See accompanying notes to the consolidated financial statements.
4
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Consolidated Cash Flows
Three months ended March 31 (unaudited)
(millions of dollars) 2005 2004
Cash Generated From Operations
Net income 238 220
Depreciation 250 232
Gain related to PipeLines LP, net of current tax expense (Note 5) (30) -
Equity income in excess of distributions received (34) (51)
Pension funding in excess of expense (7) (12)
Future income taxes (12) 23
Non-controlling interests 6 6
Other (4) (3)
Funds generated from operations 407 415
Increase in operating working capital (46) (42)
Net cash provided by continuing operations 361 373
Net cash provided by/(used in) discontinued operations 4 (2)
365 371
Investing Activities
Capital expenditures (108) (101)
Disposition of assets 151 -
Deferred amounts and other (58) (49)
Net cash used in investing activities (15) (150)
Financing Activities
Dividends (146) (140)
Advances from parent (75) -
Notes payable issued/(repaid), net 244 (229)
Long-term debt issued 300 665
Reduction of long-term debt (321) (476)
Non-recourse debt of joint ventures issued 5 6
Reduction of non-recourse debt of joint ventures (7) (9)
Common shares issued 80 -
Net cash provided by/(used in) financing activities 80 (183)
Effect of Foreign Exchange Rate Changes on Cash and 2 4
Short-Term Investments
Increase in Cash and Short-Term Investments 432 42
Cash and Short-Term Investments
Beginning of period 187 337
Cash and Short-Term Investments
End of period 619 379
Supplementary Cash Flow Information
Income taxes paid 192 161
Interest paid 190 172
See accompanying notes to the consolidated financial statements.
5
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Consolidated Balance Sheet
(millions of dollars) March 31, December 31,
2005 2004
(unaudited)
ASSETS
Current Assets
Cash and short-term investments 619 187
Accounts receivable 539 627
Inventories 170 174
Other 142 120
1,470 1,108
Long-Term Investments 833 840
Plant, Property and Equipment 18,594 18,704
Other Assets 1,526 1,459
22,423 22,111
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Notes payable 790 546
Accounts payable 1,044 1,215
Accrued interest 234 214
Current portion of long-term debt 773 766
Current portion of non-recourse debt of joint ventures 81 83
2,922 2,824
Deferred Amounts 848 783
Long-Term Debt 9,703 9,713
Future Income Taxes 491 509
Non-Recourse Debt of Joint Ventures 779 779
Preferred Securities 556 554
15,299 15,162
Non-Controlling Interests 81 76
Shareholders' Equity
Preferred shares 389 389
Common shares 4,712 4,632
Contributed surplus 271 270
Retained earnings 1,737 1,653
Foreign exchange adjustment (66) (71)
7,043 6,873
22,423 22,111
See accompanying notes to the consolidated financial statements.
6
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Consolidated Retained Earnings
Three months ended March 31 (unaudited)
(millions of dollars) 2005 2004
Balance at beginning of period 1,653 1,185
Net income 238 228
Preferred securities charges - (8)
Preferred share dividends (6) (6)
Common share dividends (148) (140)
1,737 1,259
See accompanying notes to the consolidated financial statements.
7
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Notes to Consolidated Financial Statements
(Unaudited)
1. Significant Accounting Policies
The consolidated financial statements of TransCanada PipeLines Limited (TCPL or
the company) have been prepared in accordance with Canadian generally accepted
accounting principles (GAAP). The accounting policies applied are consistent
with those outlined in TCPL's annual financial statements for the year ended
December 31, 2004 except as stated below. 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
TCPL's 2004 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.
2. Accounting Change
Financial Instruments - Disclosure and Presentation
Effective January 1, 2005, the company adopted the provisions of the Canadian
Institute of Chartered Accountants amendment to the existing Handbook Section "
Financial Instruments - Disclosure and Presentation" which provides guidance for
classifying certain financial instruments that embody obligations that may be
settled by issuance of the issuer's equity shares as debt when the instrument
does not establish an ownership relationship. In accordance with this
amendment, TCPL reclassified the non-controlling interest component of preferred
securities as long-term debt.
This accounting change was applied retroactively with restatement of prior
periods. The impact of this change on TCPL's net income in first quarter 2005
and prior periods was nil.
8
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The impact of the accounting change on the company's consolidated balance sheet
as at December 31, 2004 is as follows.
(unaudited - millions of dollars) Increase/
(Decrease)
Deferred Amounts (1) 135
Preferred Securities 535
Non-Controlling Interest
Preferred securities of subsidiary (670)
Total Liabilities and Shareholders' Equity -
--------------------
(1) Regulatory deferral
3. Segmented Information
Three months ended March 31 Gas Transmission Power Corporate Total
(unaudited - millions of dollars) 2005 2004 2005 2004 2005 2004 2005 2004
Revenues 995 949 310 317 - - 1,305 1,266
Cost of sales - - (160) (166) - - (160) (166)
Other costs and expenses (306) (285) (116) (81) (2) (2) (424) (368)
Depreciation (232) (212) (18) (20) - - (250) (232)
Operating income/(loss) 457 452 16 50 (2) (2) 471 500
Financial charges and (187) (196) (2) (2) (30) (21) (219) (219)
non-controlling interests
Financial charges of joint (14) (14) (2) - - - (16) (14)
ventures
Equity income 11 10 30 48 - - 41 58
Interest income and other 14 3 3 4 7 8 24 15
Gain related to PipeLines LP 80 - - - - - 80 -
Income taxes (150) (106) (15) (35) 16 15 (149) (126)
Net Income Applicable to Common 211 149 30 65 (9) - 232 214
Shares
Total Assets
(millions of dollars) March 31, December 31,
2005 2004
(unaudited)
Gas Transmission 18,144 18,409
Power 2,915 2,802
Corporate 1,360 893
Continuing Operations 22,419 22,104
Discontinued Operations 4 7
22,423 22,111
4. Risk Management and Financial Instruments
The following represents the material changes to the company's risk management
and financial instruments since December 31, 2004.
9
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Energy Price Risk Management
The company executes power, natural gas and heat rate derivatives for overall
management of its asset portfolio. Heat rate contracts are contracts for the
sale or purchase of power that are priced based on a natural gas index. The
fair values and notional volumes of the swap, option, future and heat rate
contracts are shown in the tables below. In accordance with the company's
accounting policy, each of the derivatives in the table below is recorded on the
balance sheet at its fair value at March 31, 2005 and December 31, 2004.
Power
March 31, 2005 December 31, 2004
(unaudited)
Asset/(Liability) Accounting Fair Fair
(millions of dollars) Treatment Value Value
Power - swaps
(maturing 2005 to 2011) Hedge (35) 7
(maturing 2005) Non-hedge 2 (2)
Gas - swaps, futures and options
(maturing 2005 to 2016) Hedge (24) (39)
(maturing 2005) Non-hedge (5) (2)
Heat rate contracts
(maturing 2005 to 2006) Hedge - (1)
10
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Notional Volumes
March 31, 2005 Accounting Power (GWh) Gas (Bcf)
(unaudited) Treatment Purchases Sales Purchases Sales
Power - swaps
(maturing 2005 to 2011) Hedge 1,752 7,237 - -
(maturing 2005) Non-hedge 330 - - -
Gas - swaps, futures and options
(maturing 2005 to 2016) Hedge - - 78 74
(maturing 2005) Non-hedge - - 3 6
Heat rate contracts
(maturing 2005 to 2006) Hedge - 76 - -
Notional Volumes
Accounting Power (GWh) Gas (Bcf)
December 31, 2004 Treatment Purchases Sales Purchases Sales
Power - swaps Hedge 3,314 7,029 - -
Non-hedge 438 - - -
Gas - swaps, futures and options Hedge - - 80 84
Non-hedge - - 5 8
Heat rate contracts Hedge - 229 2 -
5. Disposition
In March 2005, TCPL sold 3.5 million common units of TC PipeLines, LP (PipeLines
LP) for US$37.04 per unit, resulting in net proceeds to the company of
approximately $151 million and an after-tax gain of approximately $48 million.
The net gain was recorded in the Gas Transmission segment and the company
recorded a $32 million tax charge, including $50 million of current income tax
expense, on this transaction. In April 2005, underwriters purchased an
additional 74,200 common units, exercising, in part, their option to purchase up
to 525,000 additional units on the same terms and conditions as the 3.5 million
common units already sold. PipeLines LP did not receive any proceeds from the
sale of the common units. Subsequent to this transaction and the underwriter's
exercise of their option, TCPL continues to own a 13.4 per cent interest in
PipeLines LP represented by the general partner interest of 2.0 per cent as well
as an 11.4 per cent limited partner interest.
11
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6. Employee Future Benefits
The net benefit plan expense for the company's defined benefit pension plans and
other post-employment benefit plans for the three months ended March 31 is as
follows.
Three months ended March 31 Pension Benefit Plans Other Benefit Plans
(unaudited - millions of dollars) 2005 2004 2005 2004
Current service cost 7 7 - -
Interest cost 16 14 1 1
Expected return on plan assets (16) (14) - -
regulated business - - 1 1
Amortization of net actuarial loss 4 3 1 1
Amortization of past service costs 1 1 - -
Net benefit cost recognized 12 11 3 3
TCPL 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 at (403) 920-7911. The investor fax line is (403) 920-2457. Media
Relations: Hejdi Feick/Kurt Kadatz at (403) 920-7859
Visit TCPL's Internet site at: http://www.transcanada.com
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Exhibit 13.3
TRANSCANADA PIPELINES LIMITED
U.S. GAAP CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
Condensed Statement of Consolidated Income and Comprehensive Income in
Accordance with U.S. GAAP(1)
Three months ended
March 31
(millions of dollars) 2005 2004
Revenues 1,187 1,176
Cost of sales 131 143
Other costs and expenses 418 381
Depreciation 228 212
777 736
Operating income 410 440
Other (income)/expenses
Equity income(1) (88) (109)
Other expenses(2) 119 204
Income taxes 146 126
177 221
Net Income in Accordance with U.S. GAAP 233 219
Adjustments affecting comprehensive income under U.S. GAAP
Foreign currency translation adjustment, net of tax 5 3
Changes in minimum pension liability, net of tax - 25
Unrealized loss on derivatives, net of tax(3) (9) (13)
Comprehensive Income in Accordance with U.S. GAAP 229 234
Reconciliation of Net Income
Three months ended
March 31
(millions of dollars) 2005 2004
Net Income in Accordance with Canadian GAAP 238 220
U.S. GAAP adjustments
Unrealized (loss)/gain on energy contracts(4) (10) 4
Tax impact of unrealized (loss)/gain on energy contracts 4 (1)
Equity gain/(loss)(5) 2 (1)
Tax impact of equity gain/(loss) (1) -
Unrealized loss on foreign exchange and interest rate derivatives(3) - (4)
Tax impact of loss on foreign exchange and interest rate derivatives - 1
Net Income in Accordance with U.S. GAAP 233 219
--------------------------------------------------------------------------------
Condensed Statement of Consolidated Cash Flows in Accordance with U.S. GAAP(1)
Three months ended
March 31
(millions of dollars) 2005 2004
Cash Generated from Operations
Net cash provided by continuing operations 345 342
Net cash provided by/(used in) discontinued operations 4 (2)
349 340
Investing Activities
Net cash used in investing activities (10) (138)
Financing Activities
Net cash provided by/(used in) financing activities 82 (180)
Effect of Foreign Exchange Rate Changes on Cash and Short-Term Investments 2 4
Increase in Cash and Short-Term Investments 423 26
Cash and Short-Term Investments
Beginning of period 123 282
Cash and Short-Term Investments
End of period 546 308
Condensed Balance Sheet in Accordance with U.S. GAAP (1)
(millions of dollars) March 31, December 31,
2005 2004
Current assets 1,258 907
Long-term investments(5)(6) 1,856 1,887
Plant, property and equipment 16,990 17,083
Regulatory asset(7) 2,580 2,606
Other assets 1,272 1,217
23,956 23,700
Current liabilities(8) 2,769 2,653
Deferred amounts(3)(4)(6) 835 785
Long-term debt(3) 9,733 9,753
Deferred income taxes(7) 2,994 3,048
Preferred securities(9) 556 554
Non-controlling interests 81 76
Shareholders' equity 6,988 6,831
23,956 23,700
--------------------------------------------------------------------------------
Statement of Other Comprehensive Income in Accordance with U.S. GAAP
(millions of dollars) Cumulative Minimum Cash Flow Total
Translation Pension Hedges
Account Liability (SFAS No.
(SFAS No. 87) 133)
Balance at December 31, 2004 (71) (26) (4) (101)
Unrealized loss on derivatives, net of tax of $8(3) - - (9) (9)
Foreign currency translation adjustment, net of 5 - - 5
tax of $10
Balance at March 31, 2005 (66) (26) (13) (105)
Balance at December 31, 2003 (40) (98) (4) (143)
Changes in minimum pension liability, net of tax - 25 - 25
of $(13)
Unrealized gain on derivatives, net of tax of 7 - - (13) (13)
(3)
Foreign currency translation adjustment, net of 3 - - 3
tax of $6
Balance at March 31, 2004 (37) (73) (18) (128)
--------------------
(1) In accordance with U.S. GAAP, the condensed statement of
consolidated income, consolidated cash flows and balance sheet of TransCanada
PipeLines Limited (TCPL or the company) are prepared using the equity method of
accounting for joint ventures. Excluding the impact of other U.S. GAAP
adjustments, the use of the proportionate consolidation method of accounting for
joint ventures, as required under Canadian GAAP, results in the same net income
and shareholders' equity.
(2) Other expenses included an allowance for funds used during
construction of $1 million for the three months ended March 31, 2005 (March 31,
2004 - $1 million).
(3) All foreign exchange and interest rate derivatives are recorded in
the company's consolidated financial statements at fair value under Canadian
GAAP. Under the provisions of SFAS No. 133 "Accounting for Derivatives and
Hedging Activities", all derivatives are recognized as assets and liabilities on
the balance sheet and measured at fair value. For derivatives designated as
fair value hedges, changes in the fair value are recognized in earnings together
with an equal or lesser amount of changes in the fair value of the hedged item
attributable to the hedged risk. For derivatives designated as cash flow
hedges, changes in the fair value of the derivatives that are effective in
offsetting the hedged risk are recognized in other comprehensive income until
the hedged item is recognized in earnings. Any ineffective portion of the change
in fair value is recognized in earnings each period. Substantially all of the
amounts recorded in the three months ended March 31, 2005 and 2004 as
differences between U.S. and Canadian GAAP, for net income, relate to the
differences in accounting treatment with respect to the hedged items and, for
comprehensive income, relate to cash flow hedges.
(4) Substantially all of the amounts recorded in the three months ended
March 31, 2005 and 2004 as differences between U.S. and Canadian GAAP in respect
of energy contracts relate to gains and losses on derivative energy contracts
for periods before they were documented as hedges for purposes of U.S. GAAP and
to differences in accounting with respect to physical energy trading contracts
in the U.S. and Canada.
(5) Under Canadian GAAP, pre-operating costs incurred during the
commissioning phase of a new project are deferred until commercial production
levels are achieved. After such time, those costs are amortized over the
estimated life of the project. Under U.S. GAAP, such costs are expensed as
incurred. Certain start-up costs incurred by Bruce Power L.P. (an equity
investment) are required to be expensed under U.S. GAAP. Under both Canadian
GAAP and U.S. GAAP, interest is capitalized on expenditures relating to
construction of development projects actively being prepared for their intended
use. In Bruce Power, L.P. under U.S. GAAP, the carrying value of development
projects against which interest is capitalized is lower due to the expensing of
pre-operating costs.
(6) Financial Interpretation (FIN) 45 requires the recognition of a
liability for the fair value of certain guarantees that require payments
contingent on specified types of future events. The measurement standards of
FIN 45 are applicable to guarantees entered into after January 1, 2003. For
U.S. GAAP purposes, the fair value of guarantees recorded as a liability at
March 31, 2005 was $9 million (December 31, 2004 - $9 million) and relates to
the company's equity interest in Bruce Power L.P.
(7) Under U.S. GAAP, the company is required to record a deferred
income tax liability for its cost-of-service regulated businesses. As these
deferred income taxes are recoverable through future revenues, a corresponding
regulatory asset is recorded for U.S. GAAP purposes.
--------------------------------------------------------------------------------
(8) Current liabilities at March 31, 2005 include dividends payable of
$153 million (December 31, 2004 - $146 million) and current taxes payable of
$244 million (December 31, 2004 - $260 million).
(9) The fair value of the preferred securities at March 31, 2005 was
$574 million (December 31, 2004 - $572 million). The Company made preferred
securities charges payments of $12 million for the three months ended March 31,
2005 (March 31, 2004 - $12 million).
Summarized Financial Information of Long-Term Investments
The following summarized financial information of long-term investments includes
those investments that are accounted for by the equity method under U.S. GAAP
(including those that are accounted for by the proportionate consolidation
method under Canadian GAAP).
Three months ended
March 31
(millions of dollars) 2005 2004
Income
Revenues 291 275
Other costs and expenses (141) (119)
Depreciation (40) (33)
Financial charges and other (22) (14)
Proportionate share of income before income taxes of long-term investments 88 109
(millions of dollars) March 31, December 31,
2005 2004
Balance sheet
Current assets 353 361
Plant, property and equipment 2,920 3,020
Current liabilities (197) (248)
Deferred amounts (net) (222) (199)
Non-recourse debt (979) (1,030)
Deferred income taxes (19) (17)
Proportionate share of net assets of long-term investments 1,856 1,887
--------------------------------------------------------------------------------
Exhibit 31.1
Certifications
I, Harold N. Kvisle, certify that:
1. I have reviewed this quarterly report
on Form 6-K of TransCanada PipeLines Limited;
2. Based on my knowledge, this report does
not contain any untrue statement of a material fact or omit to state a material
fact necessary to make the statements made, in light of the circumstances under
which such statements were made, not misleading with respect to the period
covered by this report;
3. Based on my knowledge, the financial
statements, and other financial information included in this report, fairly
present in all material respects the financial condition, results of operations
and cash flows of the registrant as of, and for, the periods presented in this
report;
4. The registrant's other certifying
officer(s) and I are responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15
(e)) for the registrant and have:
(a) designed such disclosure controls and procedures, or caused such
disclosure controls and procedures to be designed under our supervision, to
ensure that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities,
particularly during the period in which this report is being prepared;
(b) evaluated the effectiveness of the registrant's disclosure
controls and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end of the
period covered by this report based on such evaluation; and
(c) disclosed in this report any change in the registrant's internal
control over financial reporting that occurred during the registrant's most
recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an
annual report) that has materially affected, or is reasonably likely to
materially affect, the registrant's internal control over financial reporting;
and
5. The registrant's other certifying
officer(s) and I have disclosed, based on our most recent evaluation of internal
control over financial reporting, to the registrant's auditors and the audit
committee of the registrant's board of directors (or persons performing the
equivalent functions):
(a) all significant deficiencies and material weaknesses in the design
or operation of internal control over financial reporting which are reasonably
likely to adversely affect the registrant's ability to record, process,
summarize and report financial information; and
(b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's internal control
over financial reporting.
Dated May 3, 2005
/s/ Harold N. Kvisle
Harold N. Kvisle
President and Chief Executive
Officer
--------------------------------------------------------------------------------
Exhibit 31.2
Certifications
I, Russell K. Girling, certify that:
1. I have reviewed this quarterly report
on Form 6-K of TransCanada PipeLines Limited;
2. Based on my knowledge, this report does
not contain any untrue statement of a material fact or omit to state a material
fact necessary to make the statements made, in light of the circumstances under
which such statements were made, not misleading with respect to the period
covered by this report;
3. Based on my knowledge, the financial
statements, and other financial information included in this report, fairly
present in all material respects the financial condition, results of operations
and cash flows of the registrant as of, and for, the periods presented in this
report;
4. The registrant's other certifying
officer(s) and I are responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15
(e)) for the registrant and have:
(a) designed such disclosure controls and procedures, or caused such
disclosure controls and procedures to be designed under our supervision, to
ensure that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities,
particularly during the period in which this report is being prepared;
(b) evaluated the effectiveness of the registrant's disclosure
controls and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end of the
period covered by this report based on such evaluation; and
(c) disclosed in this report any change in the registrant's internal
control over financial reporting that occurred during the registrant's most
recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an
annual report) that has materially affected, or is reasonably likely to
materially affect, the registrant's internal control over financial reporting;
and
5. The registrant's other certifying
officer(s) and I have disclosed, based on our most recent evaluation of internal
control over financial reporting, to the registrant's auditors and the audit
committee of the registrant's board of directors (or persons performing the
equivalent functions):
(a) all significant deficiencies and material weaknesses in the design
or operation of internal control over financial reporting which are reasonably
likely to adversely affect the registrant's ability to record, process,
summarize and report financial information; and
(b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's internal control
over financial reporting.
/ s / Russell K. Girling
Dated May 3, 2005 Russell K. Girling
Executive Vice-President, Corporate Development and
Chief Financial Officer
--------------------------------------------------------------------------------
Exhibit 32.1
TRANSCANADA PIPELINES LIMITED
450 - 1st Street S.W.
Calgary, Alberta, Canada
T2P 5H1
CERTIFICATION OF CHIEF EXECUTIVE OFFICER
REGARDING PERIODIC REPORT CONTAINING
FINANCIAL STATEMENTS
I, Harold N. Kvisle, the Chief Executive Officer of TransCanada PipeLines
Limited (the "Company"), in compliance with 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, hereby certify, in
connection with the Company's Quarterly Report as filed on Form 6-K for the
period ended March 31, 2005 with the Securities and Exchange Commission (the "
Report"), that:
1. the Report fully complies with the requirements of Section 13
(a) or 15(d) of the Securities Exchange Act of 1934; and
2. the information contained in the Report fairly presents, in all
material respects, the financial condition and results of operations of the
Company.
/s/ Harold N. Kvisle
Harold N. Kvisle
Chief Executive Officer
May 3, 2005
--------------------------------------------------------------------------------
Exhibit 32.2
TRANSCANADA PIPELINES LIMITED
450 - 1st Street S.W.
Calgary, Alberta, Canada
T2P 5H1
CERTIFICATION OF CHIEF FINANCIAL OFFICER
REGARDING PERIODIC REPORT CONTAINING
FINANCIAL STATEMENTS
I, Russell K. Girling, the Chief Financial Officer of TransCanada PipeLines
Limited (the "Company"), in compliance with 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, hereby certify, in
connection with the Company's Quarterly Report as filed on Form 6-K for the
period ended March 31, 2005 with the Securities and Exchange Commission (the "
Report"), that:
1. the Report fully complies with the requirements of Section 13
(a) or 15(d) of the Securities Exchange Act of 1934; and
2. the information contained in the Report fairly presents, in all
material respects, the financial condition and results of operations of the
Company.
/ s / Russell K. Girling
Russell K. Girling
Chief Financial Officer
May 3, 2005
--------------------------------------------------------------------------------
Exhibit 99.1
TransCanada PipeLines Limited
EARNINGS COVERAGE
MARCH 31, 2005
The following financial ratios have been calculated on a consolidated basis for
the respective 12 month period ended March 31, 2005 and are based on unaudited
financial information. The financial ratios have been calculated based on
financial information prepared in accordance with Canadian generally accepted
accounting principles. The following ratios have been prepared based on net
income:
March 31, 2005
Earnings coverage on long-term debt 2.86 times
Earnings coverage on long-term debt and First Preferred Shares 2.76 times
The following ratios have been prepared based on net income from continuing
operations:
March 31, 2005
Earnings coverage on long-term debt 2.78 times
Earnings coverage on long-term debt and First Preferred Shares 2.67 times
--------------------------------------------------------------------------------
Exhibit 99.2
KPMG LLP
Chartered Accountants Telephone (403) 691-8000
1200 205 - 5th Avenue SW Fax (403) 691-8008
Calgary AB T2P 4B9 Internet www.kpmg.ca
The securities regulatory authorities in each of the provinces and territories
of Canada
April 29, 2005
Dear Sirs
TransCanada PipeLines Limited (the "Company")
We refer to the short-form base shelf prospectus of the Company dated December
21, 2004 relating to the sale of up to $1,500,000,000 Medium Term Note
Debentures of the Company (the "Prospectus").
We are the auditors of the Company and under date of February 28, 2005, we
reported on the following financial statements incorporated by reference in the
Prospectus:
* Consolidated balance sheets as at December 31, 2004 and
December 31, 2003; and
* Consolidated statements of income, retained earnings and cash
flows for each of the years in the three-year period ended December 31, 2004.
Also incorporated by reference in the Prospectus are the following unaudited
interim financial statements, which have been filed with the securities
regulatory authorities:
* Consolidated balance sheet as at March 31, 2005;
* Consolidated statements of income and cash flows for the
three-month periods ended March 31, 2005 and 2004; and
* Consolidated statements of retained earnings for the
three-month periods ended March 31, 2005 and 2004.
We have not audited any financial statements of the Company as at any date or
for any period subsequent to December 31, 2004. Although we have performed an
audit for the year ended December 31, 2004, the purpose and therefore the scope
of the audit was to enable us to express our opinion on the consolidated
financial statements as at December 31, 2003 and for the year then ended, but
not on the financial statements for any interim period within that year.
Therefore, we are unable to and do not express an opinion on the above-mentioned
unaudited interim consolidated financial statements or on the financial
position, results of operations or cash flows as at any date or for any period
subsequent to December 31, 2004.
KPMG LLP, a Canadian limited liability partnership is the Canadian
member firm of KPMG International, a Swiss cooperative
--------------------------------------------------------------------------------
We have, however, performed a review of the unaudited interim consolidated
financial statements of the Company as at March 31, 2005 and for the three-month
periods ended March 31, 2005 and 2004. We performed our review in accordance
with Canadian generally accepted standards for a review of interim financial
statements by an entity's auditors. Such an interim review consists principally
of applying analytical procedures to financial data and making inquiries of, and
having discussions with, persons responsible for financial and accounting
matters. An interim review is substantially less in scope than an audit, whose
objective is the expression of an opinion regarding the financial statements. An
interim review does not provide assurance that we would become aware of any, or
all, significant matters that might be identified in an audit.
Based on our review, we are not aware of any material modification that needs to
be made for these interim consolidated financial statements to be in accordance
with Canadian generally accepted accounting principles.
This letter is provided solely for the purpose of assisting the securities
regulatory authority to which it is addressed in discharging its
responsibilities and should not be used for any other purpose. Any use that a
third party makes of this letter or any reliance or decisions based on it, are
the responsibility of such third parties. We accept no responsibility for loss
or damages, if any, suffered by any third party as a result of decisions made or
actions taken based on this letter.
Yours very truly
/s/ "KPMG LLP"
Chartered Accountants
Calgary, Canada
2
--------------------------------------------------------------------------------
This information is provided by RNS
The company news service from the London Stock Exchange
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