PART
I – FINANCIAL INFORMATION
Item
1. Financial
Statements
TC
PipeLines, LP
Consolidated
Statement of
Income
(unaudited)
|
|
Three
months ended
September
30,
|
|
Nine
months ended
September
30,
|
|
(millions
of dollars except per common unit amounts)
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity
income from investment in Great Lakes (Note 2)
|
|
|
12.0 |
|
|
|
14.2 |
|
|
|
44.4 |
|
|
|
34.3 |
|
Equity
income from investment in Northern Border (Note 3)
|
|
|
19.9 |
|
|
|
16.2 |
|
|
|
48.1 |
|
|
|
44.3 |
|
Transmission
revenues
|
|
|
8.2 |
|
|
|
6.7 |
|
|
|
23.3 |
|
|
|
20.3 |
|
Operating
expenses
|
|
|
(2.3 |
) |
|
|
(2.2 |
) |
|
|
(6.8 |
) |
|
|
(6.4 |
) |
Depreciation
|
|
|
(1.8 |
) |
|
|
(1.6 |
) |
|
|
(5.1 |
) |
|
|
(4.7 |
) |
Financial
charges, net and other
|
|
|
(7.7 |
) |
|
|
(8.7 |
) |
|
|
(22.8 |
) |
|
|
(25.5 |
) |
Net
income
|
|
|
28.3 |
|
|
|
24.6 |
|
|
|
81.1 |
|
|
|
62.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income allocation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
units
|
|
|
25.1 |
|
|
|
22.4 |
|
|
|
72.5 |
|
|
|
57.0 |
|
General
partner
|
|
|
3.2 |
|
|
|
2.2 |
|
|
|
8.6 |
|
|
|
5.3 |
|
|
|
|
28.3 |
|
|
|
24.6 |
|
|
|
81.1 |
|
|
|
62.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income per common unit (Note 6)
|
|
$ |
0.72 |
|
|
$ |
0.64 |
|
|
$ |
2.08 |
|
|
$ |
1.81 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common units
outstanding (millions)
|
|
|
34.9 |
|
|
|
34.9 |
|
|
|
34.9 |
|
|
|
31.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units outstanding, end
of the period (millions)
|
|
|
34.9 |
|
|
|
34.9 |
|
|
|
34.9 |
|
|
|
34.9 |
|
Consolidated
Statement of Comprehensive Income
(unaudited)
|
|
Three
months ended
September
30,
|
|
|
Nine
months ended
September
30,
|
|
(millions
of dollars)
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
|
28.3 |
|
|
|
24.6 |
|
|
|
81.1 |
|
|
|
62.3 |
|
Other
comprehensive loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change
associated with hedging transactions (Note 9)
|
|
|
(1.3 |
) |
|
|
(7.0 |
) |
|
|
(1.7 |
) |
|
|
(2.3 |
) |
Change
associated with hedging transactions of investees
|
|
|
- |
|
|
|
(0.5 |
) |
|
|
(0.7 |
) |
|
|
(0.9 |
) |
|
|
|
(1.3 |
) |
|
|
(7.5 |
) |
|
|
(2.4 |
) |
|
|
(3.2 |
) |
Total
comprehensive income
|
|
|
27.0 |
|
|
|
17.1 |
|
|
|
78.7 |
|
|
|
59.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See
accompanying notes to the consolidated financial
statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TC
PipeLines, LP
Consolidated
Balance Sheet
(unaudited)
|
|
|
|
|
|
|
(millions
of dollars)
|
|
September
30, 2008
|
|
|
December
31, 2007
|
|
ASSETS
|
|
|
|
|
|
|
Current
Assets
|
|
|
|
|
|
|
Cash
and short-term investments
|
|
|
11.0 |
|
|
|
7.5 |
|
Accounts
receivable and other
|
|
|
3.7 |
|
|
|
4.2 |
|
|
|
|
14.7 |
|
|
|
11.7 |
|
Investment
in Great Lakes (Note 2)
|
|
|
710.5 |
|
|
|
721.1 |
|
Investment
in Northern Border (Note 3)
|
|
|
517.2 |
|
|
|
541.9 |
|
Plant,
property and equipment (net of $66.8 accumulated depreciation, 2007 -
$61.7)
|
|
|
135.6 |
|
|
|
134.1 |
|
Goodwill
|
|
|
81.7 |
|
|
|
81.7 |
|
Other
assets
|
|
|
1.6 |
|
|
|
2.1 |
|
|
|
|
1,461.3 |
|
|
|
1,492.6 |
|
|
|
|
|
|
|
|
|
|
LIABILITIES
AND PARTNERS' EQUITY
|
|
|
|
|
|
|
|
|
Current
Liabilities
|
|
|
|
|
|
|
|
|
Bank
indebtedness
|
|
|
- |
|
|
|
1.4 |
|
Accounts
payable
|
|
|
2.2 |
|
|
|
4.8 |
|
Accrued
interest
|
|
|
3.5 |
|
|
|
3.0 |
|
Current
portion of long-term debt (Note 5)
|
|
|
4.5 |
|
|
|
4.6 |
|
Other
current liabilities
|
|
|
0.5 |
|
|
|
- |
|
|
|
|
10.7 |
|
|
|
13.8 |
|
Other
long-term liabilities
|
|
|
11.0 |
|
|
|
9.9 |
|
Long-term
debt (Note 5)
|
|
|
541.6 |
|
|
|
568.8 |
|
|
|
|
563.3 |
|
|
|
592.5 |
|
Partners'
Equity
|
|
|
|
|
|
|
|
|
Common
units
|
|
|
892.6 |
|
|
|
892.3 |
|
General
partner
|
|
|
19.1 |
|
|
|
19.1 |
|
Accumulated
other comprehensive loss
|
|
|
(13.7 |
) |
|
|
(11.3 |
) |
|
|
|
898.0 |
|
|
|
900.1 |
|
|
|
|
1,461.3 |
|
|
|
1,492.6 |
|
|
|
|
|
Subsequent
events (Note 12)
|
|
|
|
|
|
|
|
See
accompanying notes to the consolidated financial
statements.
|
|
|
TC
PipeLines, LP
Consolidated
Statement of Cash Flows
(unaudited)
|
|
Nine
months ended September 30,
|
|
(millions
of dollars)
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
|
|
CASH
GENERATED FROM OPERATIONS
|
|
|
|
|
|
|
Net
income
|
|
|
81.1 |
|
|
|
62.3 |
|
Depreciation
|
|
|
5.1 |
|
|
|
4.7 |
|
Amortization
of other assets
|
|
|
0.4 |
|
|
|
0.3 |
|
Non-controlling
interests
|
|
|
- |
|
|
|
0.2 |
|
Increase
in long-term liabilities
|
|
|
0.1 |
|
|
|
- |
|
Equity
allowance for funds used during construction
|
|
|
(0.2 |
) |
|
|
- |
|
Increase
in operating working capital (Note 10)
|
|
|
(0.2 |
) |
|
|
(0.7 |
) |
|
|
|
86.3 |
|
|
|
66.8 |
|
|
|
|
|
|
|
|
|
|
INVESTING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Return
of capital from Great Lakes (Note 2)
|
|
|
10.6 |
|
|
|
6.7 |
|
Return
of capital from Northern Border (Note 3)
|
|
|
23.9 |
|
|
|
18.2 |
|
Investment
in Great Lakes (Note 2)
|
|
|
- |
|
|
|
(733.0 |
) |
Investment
in Northern Border (Note 3)
|
|
|
- |
|
|
|
(7.5 |
) |
Capital
expenditures
|
|
|
(6.4 |
) |
|
|
(4.4 |
) |
Other
assets
|
|
|
- |
|
|
|
(1.1 |
) |
(Increase)/decrease
in investing working capital (Note 10)
|
|
|
(2.8 |
) |
|
|
1.2 |
|
|
|
|
25.3 |
|
|
|
(719.9 |
) |
|
|
|
|
|
|
|
|
|
FINANCING
ACTIVITIES
|
|
|
|
|
|
|
|
|
Distributions
paid
|
|
|
(80.8 |
) |
|
|
(61.3 |
) |
Equity
issuances, net
|
|
|
- |
|
|
|
607.0 |
|
Long-term
debt issued
|
|
|
4.0 |
|
|
|
152.5 |
|
Long-term
debt repaid (Note 5)
|
|
|
(31.3 |
) |
|
|
(34.9 |
) |
|
|
|
(108.1 |
) |
|
|
663.3 |
|
|
|
|
|
|
|
|
|
|
Increase
in cash and short-term investments
|
|
|
3.5 |
|
|
|
10.2 |
|
Cash
and short-term investments, beginning of period
|
|
|
7.5 |
|
|
|
4.6 |
|
|
|
|
|
|
|
|
|
|
Cash
and short-term investments, end of period
|
|
|
11.0 |
|
|
|
14.8 |
|
|
|
|
|
|
|
|
|
|
Interest
payments made
|
|
|
17.9 |
|
|
|
23.9 |
|
|
|
|
|
|
|
|
|
|
See
accompanying notes to the consolidated
financial statements.
|
|
|
|
|
|
|
|
|
TC
PipeLines, LP
Consolidated
Statement of Changes in Partners’ Equity
(unaudited)
|
|
Common
Units
|
|
|
General
Partner
|
|
|
Accumulated
Other Comprehensive Loss (1)
|
|
Partners'
Equity
|
|
|
|
(millions
|
|
(millions
|
|
|
(millions
|
|
|
(millions
|
|
|
(millions
|
|
(millions
|
|
|
|
of
units)
|
|
of
dollars)
|
|
|
of
dollars)
|
|
|
of
dollars)
|
|
|
of
units)
|
|
of
dollars)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Partners'
equity at December 31, 2007
|
|
|
34.9 |
|
|
|
892.3 |
|
|
|
19.1 |
|
|
|
(11.3 |
) |
|
|
34.9 |
|
|
|
900.1 |
|
Net
income
|
|
|
- |
|
|
|
72.5 |
|
|
|
8.6 |
|
|
|
- |
|
|
|
- |
|
|
|
81.1 |
|
Distributions
paid
|
|
|
- |
|
|
|
(72.2 |
) |
|
|
(8.6 |
) |
|
|
- |
|
|
|
- |
|
|
|
(80.8 |
) |
Other
comprehensive loss
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(2.4 |
) |
|
|
- |
|
|
|
(2.4 |
) |
Partners'
equity at September 30, 2008
|
|
|
34.9 |
|
|
|
892.6 |
|
|
|
19.1 |
|
|
|
(13.7 |
) |
|
|
34.9 |
|
|
|
898.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
TC PipeLines, LP
uses derivatives to assist in managing its exposure to interest rate risk.
Based on interest rates at September 30, 2008, the amount of losses
related to cash flow hedges reported in accumulated other comprehensive
income that will be reclassified to net income in the next 12 months is
$3.8 million, which will be offset by a reduction to interest expense of a
similar amount. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See
accompanying notes to the consolidated financial
statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TC
PipeLines, LP
Notes
to Consolidated Financial Statements
Note 1 |
Organization and Significant
Accounting Policies |
TC
PipeLines, LP and its subsidiaries are collectively referred to herein as “TC
PipeLines” or “the Partnership”. In this report, references to “we”, “us” or
“our” refer to TC PipeLines or the Partnership.
The
preparation of financial statements in conformity with United States of America
(U.S.) generally accepted accounting principles (GAAP) requires management to
make estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities as at the date
of the financial statements and the reported amounts of revenues and expenses
during the reporting period. Although management believes these estimates are
reasonable, actual results could differ from these estimates. In the opinion of
management, these consolidated financial statements have been properly prepared
within reasonable limits of materiality and include all adjustments (consisting
of normal recurring accruals) necessary for a fair presentation of the financial
results for the interim periods presented.
The
results of operations for the three and nine months ended September 30, 2008 and
2007 are not necessarily indicative of the results that may be expected for a
full fiscal year. The unaudited interim financial statements should be read in
conjunction with the financial statements and notes thereto included in our
Annual Report on Form 10-K for the year ended December 31, 2007. Our significant
accounting policies are consistent with those disclosed in Note 2 of the
financial statements in our annual report on Form 10-K for the year ended
December 31, 2007. Certain comparative figures have been reclassified to conform
to the current period’s presentation.
Note 2 |
Investment in Great
Lakes |
On
February 22, 2007, we acquired a 46.45 per cent partner interest in Great Lakes
Gas Transmission Limited Partnership (Great Lakes). On the same day, a
wholly-owned subsidiary of TransCanada Corporation (TransCanada) acquired 100
per cent ownership of the operator of Great Lakes. Great Lakes is regulated by
the Federal Energy Regulatory Commission (FERC).
We use
the equity method of accounting for our interest in Great Lakes. Great Lakes had
no undistributed earnings for either the nine months ended September 30, 2008 or
the period February 23, 2007 to September 30, 2007.
The
following tables contain summarized financial information for Great
Lakes:
Summarized
Consolidated Great Lakes Income Statement
(unaudited)
|
|
Three
months ended
September
30,
|
|
|
Nine
months ended
September
30,
|
|
|
For
the period
February 23
to September
30,
|
|
(millions
of dollars)
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
Transmission
revenues
|
|
|
66.7 |
|
|
|
65.6 |
|
|
|
213.9 |
|
|
|
162.2 |
|
Operating
expenses
|
|
|
(17.1 |
) |
|
|
(12.6 |
) |
|
|
(45.9 |
) |
|
|
(34.0 |
) |
Depreciation
|
|
|
(14.7 |
) |
|
|
(14.5 |
) |
|
|
(43.9 |
) |
|
|
(34.9 |
) |
Financial
charges, net and other
|
|
|
(8.0 |
) |
|
|
(8.1 |
) |
|
|
(24.4 |
) |
|
|
(19.5 |
) |
Michigan
business tax
|
|
|
(1.2 |
) |
|
|
- |
|
|
|
(4.2 |
) |
|
|
- |
|
Net
income
|
|
|
25.7 |
|
|
|
30.4 |
|
|
|
95.5 |
|
|
|
73.8 |
|
Summarized
Consolidated Great Lakes Balance Sheet
|
|
|
|
|
|
|
(unaudited)
|
|
September
30,
|
|
|
December
31,
|
|
(millions
of dollars)
|
|
2008
|
|
|
2007
|
|
Assets
|
|
|
|
|
|
|
Cash
and short-term investments
|
|
|
1.1 |
|
|
|
32.0 |
|
Other
current assets
|
|
|
100.6 |
|
|
|
55.5 |
|
Plant,
property and equipment, net
|
|
|
931.9 |
|
|
|
969.2 |
|
|
|
|
1,033.6 |
|
|
|
1,056.7 |
|
Liabilities
and Partners' Equity
|
|
|
|
|
|
|
|
|
Current
liabilities
|
|
|
49.0 |
|
|
|
50.7 |
|
Deferred
credits
|
|
|
1.7 |
|
|
|
0.4 |
|
Long-term
debt, including current maturities
|
|
|
440.0 |
|
|
|
440.0 |
|
Partners'
capital
|
|
|
542.9 |
|
|
|
565.6 |
|
|
|
|
1,033.6 |
|
|
|
1,056.7 |
|
Note 3 |
Investment in Northern
Border |
We own a
50 per cent general partner interest in Northern Border Pipeline Company
(Northern Border). Effective April 1, 2007, TransCanada Northern Border Inc.
(TCNB), a wholly-owned subsidiary of TransCanada, became the operator of
Northern Border. Northern Border is regulated by the FERC.
We use
the equity method of accounting for our interest in Northern Border. Northern
Border had no undistributed earnings for the nine months ended September 30,
2008 and 2007.
The
following tables contain summarized financial information for Northern
Border:
Summarized
Northern Border Income Statement
(unaudited)
|
|
Three
months ended
September
30,
|
|
|
Nine
months ended
September
30,
|
|
(millions of dollars)
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
Transmission
revenues
|
|
|
67.7 |
|
|
|
79.6 |
|
|
|
212.8 |
|
|
|
228.0 |
|
Operating
expenses
|
|
|
(19.3 |
) |
|
|
(21.6 |
) |
|
|
(57.5 |
) |
|
|
(61.7 |
) |
Depreciation
|
|
|
(15.3 |
) |
|
|
(15.1 |
) |
|
|
(45.8 |
) |
|
|
(45.6 |
) |
Financial
charges, net and other
|
|
|
7.1 |
|
|
|
(10.2 |
) |
|
|
(12.1 |
) |
|
|
(30.9 |
) |
Net
income
|
|
|
40.2 |
|
|
|
32.7 |
|
|
|
97.4 |
|
|
|
89.8 |
|
Summarized
Northern Border Balance Sheet
|
|
|
|
|
|
|
(unaudited)
|
|
September
30,
|
|
|
December
31,
|
|
(millions
of dollars)
|
|
2008
|
|
|
2007
|
|
Assets
|
|
|
|
|
|
|
Cash
and short-term investments
|
|
|
18.6 |
|
|
|
22.9 |
|
Other
current assets
|
|
|
31.1 |
|
|
|
39.8 |
|
Plant,
property and equipment, net
|
|
|
1,398.3 |
|
|
|
1,428.3 |
|
Other
assets
|
|
|
25.5 |
|
|
|
23.9 |
|
|
|
|
1,473.5 |
|
|
|
1,514.9 |
|
Liabilities
and Partners' Equity
|
|
|
|
|
|
|
|
|
Current
liabilities
|
|
|
53.0 |
|
|
|
53.4 |
|
Deferred
credits and other
|
|
|
9.2 |
|
|
|
8.1 |
|
Long-term
debt, including current maturities
|
|
|
621.4 |
|
|
|
615.3 |
|
Partners'
equity
|
|
|
|
|
|
|
|
|
Partners'
capital
|
|
|
793.8 |
|
|
|
840.5 |
|
Accumulated
other comprehensive loss
|
|
|
(3.9 |
) |
|
|
(2.4 |
) |
|
|
|
1,473.5 |
|
|
|
1,514.9 |
|
Note 4 |
Investment in
Tuscarora |
As of
December 31, 2007, we acquired the remaining two per cent general partner
interest in Tuscarora Gas Transmission Company (Tuscarora), thereby making it a
wholly-owned subsidiary. Tuscarora is operated by TCNB and is regulated by the
FERC.
We use
the consolidation method of accounting for our ownership of
Tuscarora.
The
following tables contain summarized financial information for
Tuscarora:
Summarized
Tuscarora Income Statement
(unaudited)
|
|
Three
months ended
September
30,
|
|
|
Nine
months ended
September
30,
|
|
(millions
of dollars)
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
Transmission
revenues
|
|
|
8.2 |
|
|
|
6.7 |
|
|
|
23.3 |
|
|
|
20.3 |
|
Operating
expenses
|
|
|
(1.4 |
) |
|
|
(1.2 |
) |
|
|
(3.7 |
) |
|
|
(3.7 |
) |
Depreciation
|
|
|
(1.8 |
) |
|
|
(1.6 |
) |
|
|
(5.1 |
) |
|
|
(4.7 |
) |
Financial
charges, net and other
|
|
|
(1.1 |
) |
|
|
(1.0 |
) |
|
|
(3.1 |
) |
|
|
(3.4 |
) |
Net
income
|
|
|
3.9 |
|
|
|
2.9 |
|
|
|
11.4 |
|
|
|
8.5 |
|
Summarized
Tuscarora Balance Sheet
(unaudited)
|
|
September
30,
|
|
|
December
31,
|
|
(millions
of dollars)
|
|
2008
|
|
|
2007
|
|
Assets
|
|
|
|
|
|
|
Cash
and short-term investments
|
|
|
- |
|
|
|
6.1 |
|
Other
current assets
|
|
|
13.6 |
|
|
|
2.6 |
|
Plant,
property and equipment, net
|
|
|
135.6 |
|
|
|
134.1 |
|
Other
assets
|
|
|
0.3 |
|
|
|
0.6 |
|
|
|
|
149.5 |
|
|
|
143.4 |
|
Liabilities
and Partners' Equity
|
|
|
|
|
|
|
|
|
Current
liabilities
|
|
|
3.1 |
|
|
|
6.1 |
|
Long-term
debt, including current maturities
|
|
|
64.1 |
|
|
|
66.4 |
|
Partners'
capital
|
|
|
82.3 |
|
|
|
70.9 |
|
|
|
|
149.5 |
|
|
|
143.4 |
|
Summarized
Tuscarora Cash Flow Statement
(unaudited)
|
|
Three
months ended
September
30,
|
|
|
Nine
months ended
September
30,
|
|
(millions
of dollars)
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
Cash
flows provided by operating activities
|
|
|
7.2 |
|
|
|
4.6 |
|
|
|
17.3 |
|
|
|
13.5 |
|
Cash
flows (used in)/provided by investing activities
|
|
|
(1.3 |
) |
|
|
0.6 |
|
|
|
(9.2 |
) |
|
|
(3.1 |
) |
Cash
flows used in financing activities
|
|
|
(5.8 |
) |
|
|
- |
|
|
|
(14.2 |
) |
|
|
(2.4 |
) |
Increase/(decrease)
in cash and short-term investments
|
|
|
- |
|
|
|
5.2 |
|
|
|
(6.1 |
) |
|
|
8.0 |
|
Cash
and short-term investments, beginning of period
|
|
|
- |
|
|
|
5.7 |
|
|
|
6.1 |
|
|
|
2.9 |
|
Cash
and short-term investments, end of period
|
|
|
- |
|
|
|
10.9 |
|
|
|
- |
|
|
|
10.9 |
|
Note 5 |
Credit Facility and Long-Term
Debt |
(unaudited)
|
|
September
30,
|
|
|
December
31,
|
|
(millions
of dollars)
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
|
|
Senior
Credit Facility
|
|
|
482.0 |
|
|
|
507.0 |
|
7.13%
Series A Senior Notes due 2010
|
|
|
52.9 |
|
|
|
54.5 |
|
7.99%
Series B Senior Notes due 2010
|
|
|
5.3 |
|
|
|
5.5 |
|
6.89%
Series C Senior Notes due 2012
|
|
|
5.9 |
|
|
|
6.4 |
|
|
|
|
546.1 |
|
|
|
573.4 |
|
The
Senior Credit Facility consists of a $475.0 million senior term loan and a
$250.0 million senior revolving credit facility. At September 30, 2008, $7.0
million was outstanding under our senior revolving credit facility, leaving
$243.0 million available for future borrowings. The interest rate on the Senior
Credit Facility averaged 3.31 per cent for the three months ended September 30,
2008 (2007 – 5.97 per cent), while for the nine months ended September 30, 2008
the interest rate on the Senior Credit Facility averaged 3.93 per cent (2007 –
6.02 per cent). After hedging activity, the interest rate incurred on the Senior
Credit Facility averaged 5.23 per cent for the three months ended September 30,
2008 (2007 – 5.70 per cent) and 5.18 per cent for the nine months ended
September 30, 2008 (2007 – 5.52 per cent). Prior to hedging activities, the
interest rate was 3.36 per cent at September 30, 2008 (December 31, 2007 – 5.62
per cent). At September 30, 2008, we were in compliance with our financial
covenants.
Annual
maturities are as follows: 2008 - $2.3 million; 2009 - $4.4 million; 2010 -
$53.5 million; 2011 - $482.8 million; and, thereafter - $3.1
million.
Note 6 |
Net Income per Common
Unit |
Net
income per common unit is computed by dividing net income, after deduction of
the general partner’s allocation, by the weighted average number of common units
outstanding. The general partner’s allocation is equal to an amount based upon
the general partner’s two per cent interest, plus an amount equal to incentive
distributions. Incentive distributions are received by the general partner if
quarterly cash distributions on the common units exceed levels specified in the
partnership agreement. Net income per common unit was determined as
follows:
(unaudited)
|
|
Three
months ended
September
30,
|
|
|
Nine
months ended
September
30,
|
|
(millions
of dollars except per unit) |
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
Net
income
|
|
|
28.3 |
|
|
|
24.6 |
|
|
|
81.1 |
|
|
|
62.3 |
|
Net
income allocated to general partner
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General
partner interest
|
|
|
(0.6 |
) |
|
|
(0.4 |
) |
|
|
(1.6 |
) |
|
|
(1.2 |
) |
Incentive
distribution income allocation
|
|
|
(2.6 |
) |
|
|
(1.8 |
) |
|
|
(7.0 |
) |
|
|
(4.1 |
) |
|
|
|
(3.2 |
) |
|
|
(2.2 |
) |
|
|
(8.6 |
) |
|
|
(5.3 |
) |
Net
income allocable to common units
|
|
|
25.1 |
|
|
|
22.4 |
|
|
|
72.5 |
|
|
|
57.0 |
|
Weighted
average common units outstanding (millions)
|
|
|
34.9 |
|
|
|
34.9 |
|
|
|
34.9 |
|
|
|
31.5 |
|
Net
income per common unit
|
|
$ |
0.72 |
|
|
$ |
0.64 |
|
|
$ |
2.08 |
|
|
$ |
1.81 |
|
Note 7 |
Cash
Distributions |
For the
three and nine months ended September 30, 2008, we distributed $0.705 and $2.07
per common unit (2007 – $0.655 and $1.905 per common unit). The distributions
for the three and nine months ended September 30, 2008 included incentive
distributions to the general partner of $2.6 million and $7.0 million (2007 -
$1.8 million and $4.1 million).
Note 8 |
Related Party
Transactions |
The
Partnership does not have any employees. The management and operating functions
are provided by the general partner. The general partner does not receive a
management fee in connection with its management of the Partnership. The
Partnership reimburses the general partner for all costs of services provided,
including the costs of employee, officer and director compensation and benefits,
and all other expenses necessary or appropriate to the conduct of the business
of, and allocable to, the Partnership. Such costs include (i) overhead costs
(such as office space and equipment) and (ii) out-of-pocket expenses related to
the provision of such services. The Partnership Agreement provides that the
general partner will determine the costs that are allocable to the Partnership
in any reasonable manner determined by the general partner in its sole
discretion. Total costs charged to the Partnership by the general partner were
$0.5 million and $1.6 million for the three and nine months ended September 30,
2008 (2007 - $0.5 million and $1.4 million).
TCNB
became the operator of Northern Border effective April 1, 2007. The operator of
Great Lakes became a wholly-owned subsidiary of TransCanada through
TransCanada’s acquisition of Great Lakes Gas Transmission Company on February
22, 2007. TCNB also became the operator of Tuscarora, as part of the December
19, 2006 acquisition of an additional 49 per cent general partner interest in
Tuscarora. TransCanada and its affiliates provide capital and operating services
to Great Lakes, Northern Border and Tuscarora (together, “our pipeline
systems”). TransCanada and its affiliates incur costs on behalf of our pipeline
systems, including, but not limited to, employee salary and benefit costs,
property and liability insurance costs, and transition costs. Total costs
charged to our pipeline systems during the three and nine months ended September
30, 2008 and 2007 by TransCanada and its affiliates and amounts owed to
TransCanada and its affiliates at September 30, 2008 and December 31, 2007 are
summarized in the following tables:
(unaudited)
|
|
Three
months ended
September
30,
|
|
|
Nine
months ended
September
30,
|
|
(millions
of dollars)
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs
charged by TransCanada and its affiliates:
|
|
|
|
|
|
|
|
|
|
|
Great
Lakes
|
|
|
8.2 |
|
|
|
5.2 |
|
|
|
23.4 |
|
|
|
22.2 |
|
Northern
Border
|
|
|
7.5 |
|
|
|
7.4 |
|
|
|
23.5 |
|
|
|
14.9 |
|
Tuscarora
|
|
|
0.9 |
|
|
|
0.8 |
|
|
|
2.9 |
|
|
|
1.7 |
|
Impact
on the Partnership's net income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Great
Lakes
|
|
|
3.6 |
|
|
|
2.4 |
|
|
|
10.1 |
|
|
|
10.3 |
|
Northern
Border
|
|
|
3.2 |
|
|
|
3.7 |
|
|
|
9.6 |
|
|
|
7.5 |
|
Tuscarora
|
|
|
0.7 |
|
|
|
0.8 |
|
|
|
2.0 |
|
|
|
1.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
The amounts disclosed for Great Lakes are for the period February 23 to
September 30, 2007. The amounts disclosed for Northern Border are for
the period April 1 to September 30, 2007.
|
|
|
|
|
|
|
|
|
|
(unaudited)
|
|
September
30,
|
|
|
December
31,
|
(millions
of dollars)
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
|
|
Amount
owed to TransCanada and its affiliates:
|
|
|
|
|
Great
Lakes
|
|
|
8.1 |
|
|
|
1.9 |
Northern
Border
|
|
|
5.1 |
|
|
|
3.0 |
Tuscarora
|
|
|
0.5 |
|
|
|
3.5 |
Great
Lakes earns transportation revenues from TransCanada and its affiliates under
fixed price contracts with remaining terms ranging from one to ten years. Great
Lakes earned $40.5 million of transportation revenues under these contracts for
the three months ended September 30, 2008 (2007 - $32.4 million). This amount
represents 61 per cent of total revenues earned by Great Lakes for the three
months ended September 30, 2008 (2007 - 50 per cent). $18.8 million of this
transportation revenue is included in our equity income from Great Lakes for the
three months ended September 30, 2008 (2007 - $15.1 million).
Great
Lakes earned $108.7 million of transportation revenues from TransCanada and its
affiliates for the nine months ended September 30, 2008 (February 23, 2007 to
September 30, 2007 - $81.5 million). This amount represents 51 per cent of total
revenues earned by Great Lakes for the nine months ended September 30, 2008
(February 23, 2007 to September 30, 2007 - 50 per cent). $50.5 million of this
transportation revenue is included in our equity income from Great Lakes for the
nine months ended September 30, 2008 (February 23, 2007 to September 30, 2007 -
$37.9 million). At September 30, 2008, $13.4 million is included in Great Lakes’
receivables in regards to the transportation contracts with TransCanada and its
affiliates (December 31, 2007 - $10.0 million).
In August
2008, Northern Border sold its wholly-owned subsidiary, Bison Pipeline LLC, to
TransCanada for $20.0 million. In connection with this transaction, Northern
Border recorded a gain on sale of $16.1 million, of which the Partnership’s
share is $8.1 million. The proposed 297-mile, 24-inch diameter Bison pipeline
system would extend from natural gas gathering facilities located in the Powder
River Basin in Wyoming to a point of interconnection with the Northern Border
pipeline system in Morton County, North Dakota.
Northern
Border’s Des Plaines Project consists of the construction, ownership and
operation of interconnect facilities, including a 1,600 horsepower compressor
facility near Joliet, Illinois. In June 2008, in connection with the Des Plaines
Project, Northern Border and ANR Pipeline Company (ANR), a wholly-owned
subsidiary of TransCanada, have entered into an Interconnect Agreement, which
provides that Northern Border will reimburse ANR for the cost of the
interconnect facilities to be owned by ANR. In June, Northern Border paid ANR
$0.5 million and it is estimated that additional costs to complete the
interconnect will be $0.1 million. Northern Border will be responsible for the
final costs to construct the interconnect and any difference between the final
actual costs and the estimated amounts paid will be remitted by or refunded to
Northern Border.
Note 9 |
Derivative Financial
Instruments |
The
interest rate swaps and options are structured such that the cash flows match
those of the Senior Credit Facility. The notional amount hedged was $475.0
million at September 30, 2008 (December 31, 2007 - $400.0 million). At September
30, 2008, the fair value of the interest rate swaps and options accounted for as
hedges was negative $11.5 million (December 31, 2007 – negative $9.8 million).
Effective January 1, 2008, we adopted the provisions of Statement of Financial
Accounting Standards (SFAS) No. 157, Fair Value Measurements (SFAS
157). Under SFAS 157, these financial assets and liabilities that are
recorded at fair value on a recurring basis are categorized into one of three
categories based upon a fair value hierarchy. We have classified all of our
derivative financial instruments as level II where the fair value is determined
by using valuation techniques that refer to observable market data or estimated
market prices. During the
three and nine months ended September 30, 2008, we recorded interest expense of
$2.4 million and $4.7 million, respectively, in regards to the interest rate
swaps and options. We recorded interest income of $0.4 million and $0.8 million
for the three and nine months ended September 30, 2007, respectively, in regards
to the interest rate swaps and options.
Note 10 |
Changes in Working
Capital |
(unaudited)
|
|
Nine
months ended September 30,
|
|
(millions
of dollars)
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
|
|
Decrease/(increase)
in accounts receivable and other
|
|
|
0.5 |
|
|
|
(2.4 |
) |
Decrease
in bank indebtedness
|
|
|
(1.4 |
) |
|
|
- |
|
Decrease
in accounts payable
|
|
|
(2.6 |
) |
|
|
(0.3 |
) |
Increase
in accrued interest
|
|
|
0.5 |
|
|
|
3.2 |
|
|
|
|
(3.0 |
) |
|
|
0.5 |
|
Note 11 |
Accounting
Pronouncements |
In May
2008, the Financial Accounting Standards Board (FASB) issued SFAS No. 162, The Hierarchy of Generally Accepted
Accounting Principles (SFAS No. 162) which codifies the sources of
accounting principles and the related framework to be utilized in preparing
financial statements in conformity with GAAP. The requirements of this standard
are not expected to have a material impact on our results of operations or
financial position.
In
March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative
Instruments and Hedging Activities (SFAS No. 161) as an amendment to SFAS
No. 133, Accounting for
Derivative Instruments and Hedging Activities.
SFAS No.
161 requires that objectives for using derivative instruments be disclosed in
terms of underlying risk and accounting designation. SFAS No. 161 is effective
for our fiscal year beginning January 1, 2009, and we are currently evaluating
its applicability to our results of operations and financial
position.
Note 12 |
Subsequent
Events |
On
October 17, 2008, the Board of Directors of the general partner declared the
Partnership’s third quarter 2008 cash distribution in the amount of $0.705 per
common unit, payable on November 14, 2008, to unitholders of record on October
31, 2008. The cash distribution represents an annual cash distribution of $2.82
per common unit.
Item
2. Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
The
following discusses the results of operations and liquidity and capital
resources of TC PipeLines, LP, along with those of Great Lakes Gas Transmission
Limited Partnership (Great Lakes), Northern Border Pipeline Company (Northern
Border) and Tuscarora Gas Transmission Company (Tuscarora), (together “our
pipeline systems”), as a result of the Partnership’s ownership
interests.
FORWARD-LOOKING
STATEMENTS
The
statements in this report that are not historical information, including
statements concerning plans and objectives of management for future operations,
economic performance or related assumptions, are forward-looking statements
within the meaning of Section 27A of the Securities Act of 1933 and
Section 21E of the Exchange Act. Forward-looking statements may include
words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,”
“believe,” “forecast” and other words and terms of similar meaning. The absence
of these words, however, does not mean that the statements are not
forward-looking.
These
statements reflect our current views with respect to future events, based on
what we believe are reasonable assumptions. Certain factors that could cause
actual results to differ materially from those contemplated in the
forward-looking statements include:
·
|
the
ability of Great Lakes and Northern Border to continue to make
distributions at their current
levels;
|
·
|
the
impact of unsold capacity on Great Lakes and Northern Border being greater
or less than expected;
|
·
|
competitive
conditions in our industry and the ability of our pipeline systems to
market pipeline capacity on favorable terms, which is affected
by:
|
o
|
future
demand for and prices of natural
gas;
|
o
|
competitive
conditions in the overall natural gas and electricity
markets;
|
o
|
availability
of supplies of Canadian and United States (U.S.) natural
gas;
|
o
|
the
oversupply of natural gas in the Mid-continent
market;
|
o
|
availability
of additional storage capacity and current storage
levels;
|
o
|
competitive
developments by Canadian and U.S. natural gas transmission companies,
including the construction of the Eastern segment of the Rockies Express
Pipeline (REX East) to Clarington, Ohio;
and
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o
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development
of newly discovered natural gas plays such as the Horn River and Montney
shale gas plays in Western Canada, the Louisiana Haynesville shale gas
play, and the Marcellus shale gas play in West Virginia, Pennsylvania, and
New York.
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·
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the
Alberta (Canada) government’s decision to implement a new royalty regime
effective January 2009 may affect the amount of exploration and
drilling in the Western Canada Sedimentary Basin
(WCSB);
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·
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the
decision by TransCanada to advance the Pathfinder Pipeline Project or the
Bison Pipeline Project and the regulatory, financing and construction
risks related to construction of interstate natural gas
pipelines;
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·
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the
successful completion, timing, cost, scope and future financial
performance of our pipeline systems’ expansion projects could differ
materially from our expectations due to availability of contractors or
equipment, weather, difficulties or delays in obtaining regulatory
approvals or denied applications, land owner opposition, the lack of
adequate materials, labor difficulties or shortages, expansion costs that
are higher than anticipated and numerous other factors beyond our
control;
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·
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performance
of contractual obligations by customers of our pipeline
systems;
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·
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the
imposition of state income taxes on
partnerships;
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·
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operating
hazards, natural disasters, weather-related delays, casualty losses and
other matters beyond our control;
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·
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the
impact of current and future laws, rulings and governmental regulations,
particularly Federal Energy Regulatory Commission (FERC) regulations, on
us and our pipeline systems;
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·
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our
ability to control operating costs;
and
|
·
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prevailing
economic conditions, including the current uncertainty in the global
economic markets, that impact the capital and equity markets and our
ability to access these markets.
|
Other
factors described elsewhere in this document, or factors that are unknown or
unpredictable, could also have material adverse effects on future results.
Please also read Item 1A. “Risk Factors” in our annual report on Form 10-K for
the year ended December 31, 2007 and Item 1A. “Risk Factors” of this report. All
forward-looking statements attributable to us or persons acting on our behalf
are expressly qualified in their entirety by these factors. The forward-looking
statements and information is made only as of the date of the filing of this
report, and except as required by applicable law, we undertake no obligation to
update these forward-looking statements and information to reflect new
information, subsequent events or otherwise.
The
following discussion and analysis should be read in conjunction with our 2007
Annual Report on Form 10-K and the unaudited financial statements and notes
thereto included in Item 1. “Financial Statements” of this Quarterly Report on
Form 10-Q. All amounts are stated in U.S. dollars.
PARTNERSHIP
OVERVIEW
TC
PipeLines, LP was formed in 1998 as a Delaware limited partnership by
TransCanada PipeLines Limited, a wholly-owned subsidiary of TransCanada
Corporation (collectively referred to herein as TransCanada), to acquire, own
and participate in the management of energy infrastructure assets in North
America. Our strategic focus is on delivering stable, sustainable cash
distributions to our unitholders and finding opportunities to increase cash
distributions while maintaining a low risk profile.
TC
PipeLines, LP and its subsidiaries are collectively referred to herein as “TC
PipeLines” or “the Partnership.” In this report, references to “we”, “us” or
“our” collectively refer to TC PipeLines or the Partnership. The general partner
of the Partnership is TC PipeLines GP, Inc., a wholly-owned subsidiary of
TransCanada.
We own a
46.45 per cent partner interest in Great Lakes, which we acquired on February
22, 2007 from El Paso Corporation. The other 53.55 per cent general partner
interest in Great Lakes is held by TransCanada.
We own a
50 per cent general partner interest in Northern Border, while the other 50 per
cent interest is held by ONEOK Partners, L.P., a publicly traded limited
partnership that is controlled by ONEOK, Inc.
As of
December 31, 2007, we acquired the remaining two per cent general partner
interest in Tuscarora, thereby making it a wholly-owned subsidiary.
Our
partner interests in Great Lakes, Northern Border and Tuscarora represent our
only material assets at September 30, 2008. As a result, we are dependent upon
our pipeline systems for all of our available cash. Our pipeline systems derive
their operating revenue from transportation of natural gas.
Great
Lakes Overview
Great
Lakes is a Delaware limited partnership formed in 1990. Great Lakes was
originally constructed as an operational loop of the TransCanada Mainline
Northern Ontario system. Great Lakes receives natural gas from TransCanada at
the Canadian border near Emerson, Manitoba and extends across Minnesota,
Northern Wisconsin and Michigan, and redelivers gas to TransCanada at the
Canadian border at Sault Ste. Marie, Michigan and St. Clair,
Michigan.
Northern
Border Overview
Northern
Border is a Texas general partnership formed in 1978. Northern Border transports
natural gas from the Canadian border near Port of Morgan, Montana to a terminus
near North Hayden, Indiana. Additionally, Northern Border transports natural gas
produced in the Williston Basin of Montana and North Dakota and the Powder River
Basin of Wyoming and Montana and synthetic gas produced at the Dakota
Gasification plant in North Dakota.
Tuscarora
Overview
Tuscarora
is a Nevada general partnership formed in 1993. Tuscarora originates at an
interconnection point with existing facilities of Gas Transmission Northwest
Corporation, a wholly-owned subsidiary of TransCanada, near Malin, Oregon and
runs southeast through Northeastern California and Northwestern Nevada.
Tuscarora’s pipeline system terminates near Wadsworth, Nevada. Along its route,
deliveries are made in Oregon, Northern California and Northwestern
Nevada.
FACTORS
THAT IMPACT THE BUSINESS OF OUR PIPELINE SYSTEMS
Key
factors that impact the business of our pipeline systems are the supply of and
demand for natural gas in the markets in which our pipeline systems operate; the
customers of our pipeline systems and the mix of services they require;
competition; and government regulation of natural gas pipelines.
Supply
and Demand of Natural Gas
Our
pipeline systems depend upon the WCSB for the majority of the natural gas that
they transport. Overall flows out of the WCSB were lower for the nine months
ended September 30, 2008 as compared to the same period last year, due mainly to
a decrease in production, and an increase in Canadian demand. WCSB exports are
expected to be lower for the remainder of the year. Factors which may mitigate
declines related to WCSB production in the future include strengthening gas
prices, decreases in oil prices as they affect demand from Alberta oil sands
operations, continued clarification of the Alberta Royalty Regime to take effect
January 1, 2009 as it affects natural gas production, and announcements
regarding potential natural gas supply discoveries in the Horn River and Montney
shale gas plays in Western Canada. Reduced supplies available for Canadian
export affects all U.S. pipelines that import natural gas from Canada, but the
impact on our pipeline systems will depend upon competitive factors and
prevailing market conditions in each of the markets that our pipeline systems
serve. Flows on Great Lakes’ pipeline system in the third quarter of 2008 were
consistent with flows in the third quarter of 2007 due to annual contracts and
reduced storage inventories which resulted in strong demand for transportation
to Michigan and Ontario storage locations. As expected, flows on Northern
Border’s pipeline system in the third quarter of 2008 were lower than the third
quarter of 2007.
The
Rockies Express Pipeline is a proposed 1,679-mile natural gas pipeline system
from Rio Blanco County, Colorado, to Monroe County, Ohio. The Western segment of
the Rockies Express Pipeline (REX West) from Weld County, Colorado to Audrain
County, Missouri went into full service in May 2008. REX West has had a minimal
impact on Great Lakes; however, it has caused excess natural gas supply from the
Rockies Basin to flow into the Mid-Continent market, which is the market served
by Northern Border. Consequently, there is less demand for WCSB supply in the
Mid-Continent market which has had a negative impact on Northern Border’s flows
and sales of available capacity in the second and third quarters of 2008. It is
anticipated that increased winter demand will dampen the impact of REX West
deliveries into the Mid-Continent that has increased supply in Northern Border’s
market region.
REX East
is planned to extend from Audrain County, Missouri to Clarington, located in
Monroe County, Ohio. Once in-service, REX East should improve the competitive
position of Canadian supply with gas sourced from other supply basins, including
the Rockies Basin, into the Mid-Continent, which may potentially mitigate some of the excess supply in the Mid-Continent market. REX East
will compete with Great Lakes in some markets, but will also potentially create
demand for Great Lakes’ transportation of natural gas from REX East seeking
access to and from storage locations in Michigan. It is now anticipated that the
partial in-service and full in-service of REX East will occur in the second and
fourth quarters of 2009, respectively. Although there can be no assurance on the
timing or impact of REX East, we believe that any positive impact on the market
Northern Border serves will not occur until 2010.
There are
many proposed natural gas pipeline projects that, if built, would impact the
markets served by our pipeline systems. Two proposed projects, the Pathfinder
Pipeline Project (Pathfinder Project) and the Bison Pipeline Project (Bison
Project), if built, would diversify Northern Border’s natural gas supply sources
and provide another transportation source for shippers to export natural gas
supply from the Rockies Basin. Please see the Recent Developments disclosure in
this section for information on the Bison Project and the Pathfinder
Project.
Reduced
storage inventories in Eastern Canada and the U.S. supported demand for Great
Lakes’ transportation, as customers utilized Great Lakes’ transportation to
access and fill storage locations adjacent to its pipeline in the last
quarter.
Great
Lakes’ future transportation values have continued to increase throughout this
year, partially due to the increase in TransCanada Mainline tolls, and partially
because of strong spread values between Alberta and Dawn, Ontario. As a result,
Great Lakes sold new and renewed long and short haul contracts at maximum tariff
rates for the next two years. However, now that Michigan and Ontario storage
fill is approaching capacity, as expected for this time of year, daily and short
term transportation values are decreasing.
Discoveries
of new gas fields, such as the Horn River Basin and Montney gas plays in Western
Canada may increase the amount of Canadian natural gas available for export.
Recently, TransCanada gauged interest for new natural gas transportation service
connecting the Horn River and Montney areas to its Alberta System. TransCanada
received requests for gas transmission service exceeding one billion cubic feet
per day (Bcf/d) for each area by 2012. Following this, TransCanada launched two
binding open seasons seeking requests for firm transportation service from
customers for the Groundbirch Project (a pipeline project designed to connect
the Montney area of North East British Columbia to TransCanada’s Alberta System)
and the Horn River Project (a pipeline project designed to connect the Horn
River area of North East British Columbia to TransCanada’s Alberta system). The
Groundbirch Project has an estimated in-service date of late 2010, while the
Horn River Project has an estimate in-service date of early 2011. These gas
plays, as well as the development of the Louisiana Haynesville shale gas play
and the discovery of the Marcellus shale gas play in West Virginia,
Pennsylvania, and New York in the U.S. will affect competitive factors and
market conditions in the natural gas industry.
Contracting
Great
Lakes – Great Lakes’ average contracted capacity for the quarter ended September
30, 2008 was 98 per cent of its design capacity (2007 – 98 per cent). For the
nine months ended September 30, 2008, Great Lakes’ average contracted capacity
was 104 per cent of its design capacity (period of March 1, 2007 to September
30, 2007 - 100 per cent). At September 30, 2008, 103 per cent of capacity was
contracted on a firm basis for the remainder of the year and the weighted
average remaining life of firm transportation contracts was 2.1
years.
In the
third quarter of 2008, Great Lakes sold all of its available long haul capacity
beginning November 1, 2008 for one year at maximum rates, sold available annual
short haul capacity in Michigan at maximum rates for one to two year terms, and
sold its available winter seasonal long haul capacity at maximum
rates.
Northern
Border – Northern Border’s average contracted capacity for the quarter ended
September 30, 2008 was 79 per cent of its design capacity (2007 - 102 per cent).
For the nine months ended September 30, 2008, Northern Border’s average
contracted capacity was 86 per cent of its design capacity (2007 - 96 per cent).
At September 30, 2008, approximately 78 per cent of Northern Border’s design
capacity was contracted on a firm basis for the remainder of the year and the
weighted average remaining contract life of firm transportation contracts was
2.0 years.
At
January 1, 2009, Northern Border’s total amount of available transportation
capacity is expected to be approximately 800 million cubic feet per day
(MMcf/d). Northern Border’s capacity to Chicago remains attractive and continues
to be fully contracted and legacy contracts set to expire in the near term have
been renewed. Additionally, related to a proposed expansion project, Northern
Border renewed approximately 350 MMcf/d at maximum and discounted rates, for
terms ranging from five to twelve years for various transportation paths to
Chicago. See additional information below in Recent Developments –
Chicago IV Project for more information.
Prevailing
market conditions and increasing competitive factors in North America, including
REX West, have caused Northern Border to experience a reduction in its revenues
due to lower capacity sales and greater discounting of its rates. These factors,
as well as expirations of certain long term contracts, will continue to impact
Northern Border’s ability to market its available capacity into 2009. Northern
Border expects to continue to discount transportation capacity as needed to
optimize revenue.
Northern
Border has executed long-term contracts of approximately 400 MMcf/d sold at a
discounted rate from Port of Morgan, Montana to Ventura, Iowa contingent upon
either the Bison Project or Pathfinder Project going forward. These
contracts would be effective at the successful project’s in-service date
projected for late 2010.
Tuscarora
- Tuscarora’s average contracted capacity for the quarter ended September 30,
2008 was 98 per cent of its design capacity (2007 – 95 per cent). For the
nine months ended September 30, 2008, Tuscarora’s average contracted capacity
was 98 per cent of its design capacity (2007 – 96 per cent). At September
30, 2008, approximately 99 per cent of
Tuscarora’s design capacity was contracted on a firm basis for the remainder of
the year and the weighted average remaining contract life of firm transportation
contracts was 12.0 years.
RECENT
DEVELOPMENTS
Northern
Border
Bison
Project – On September
3, 2008, Northern Border announced the sale of its wholly-owned subsidiary,
Bison Pipeline LLC, to TransCanada Pipeline USA Ltd., a wholly-owned subsidiary
of TransCanada for $20.0 million. Distributions paid by Northern Border to its
partners in the third quarter included a special distribution in the amount of
$16.4 million, of which the Partnership’s share was $8.2 million. As a part of
the transaction, TransCanada has assumed the obligations of Northern Border
related to the Bison Project, and is continuing to solicit commercial support
for the Bison Project.
The
assets and obligations of Bison Pipeline LLC included executed precedent
agreements subject to certain shipper contingencies, as well as regulatory,
environmental and engineering activities completed to date on the Bison Project.
Shippers on the Bison Project have executed contracts for capacity on the
Northern Border system from Port of Morgan, Montana, to Ventura, Iowa, subject
to the in-service date of the Bison Project. Project subscription that is
subject to the upstream capacity condition is approximately 400
MMcf/d.
The
proposed 297-mile, 24-inch diameter Bison pipeline system would extend from
natural gas gathering facilities located in the Powder River Basin in Wyoming to
a point of interconnection with the Northern Border pipeline system in Morton
County, North Dakota. The initial capacity of the Bison Project is anticipated
to be approximately 400 MMcf/d. The projected in-service date is late
2010.
The
proposed Pathfinder Project is an approximately 673-mile, 36-inch diameter
interstate pipeline that would transport natural gas northeast from Meeker,
Colorado, through Montana to the Northern Border pipeline system in North Dakota
for delivery into the Ventura and Chicago-area markets. The capacity is between
1.2 to 1.6 Bcf/d. In September 2008, Enterprise Product Partners L.P. terminated
their previously-announced commitment to become a 50 per cent partner in
Pathfinder with a 500 MMcf/d shipping commitment. TransCanada is continuing to
work with prospective Pathfinder shippers to advance this project.
The
success of either the Bison or Pathfinder Projects is dependent upon many
factors, and there is no certainty that either of these projects will be
constructed. For further information regarding the risks related to the
construction projects, please refer to the Risk Factors sections in our 2007
Annual Report on Form 10-K and in this report.
Proposed
Expansion Project (Chicago IV) – Northern Border conducted a binding open season
seeking interest in an expansion project from Harper, Iowa to Manhattan,
Illinois and received binding shipper commitments. The proposed expansion
capacity was subject to a one-time adjustment right to reduce the Chicago IV
commitments resulting from the right of first refusal (ROFR) process in current
shipper contracts. During a ROFR process, its bidders are able to obtain
existing capacity with similar terms. If the Chicago IV bidders reduce their
commitments, it could eliminate the need for an expansion project. Northern
Border renewed approximately 350 MMcf/d at maximum and discount rates, for terms
ranging from 5 to 12 years for various transportation paths to
Chicago.
Des
Plaines Project – In February 2008, Northern Border filed with the FERC to
construct, own and operate interconnect facilities, including a 1,600 horsepower
compressor facility near Joliet, Illinois. It is estimated that the Des Plaines
Project will cost approximately $18 million and will be financed by a
combination of debt and equity. In June 2008, the FERC issued its environmental
assessment report for the Des Plaines Project and no comments were filed during
the comment period. A certificate order by FERC authorizing construction of the
Des Plaines Project was received on July 25, 2008. Northern Border commenced
construction on the Des Plaines Project on September 8, 2008, and it is now
expected the facilities will be placed into service by early 2009.
Tuscarora
Compressor
Station Expansion Project – Tuscarora’s compressor station expansion project to
support Sierra Pacific Power Company’s Tracy Combined Cycle Power Plant went
into service on April 1, 2008, with a final cost within the original cost
estimate. The new contract for 40,000 Dth/d for a term of 22-1/2 years will
generate approximately $5.8 million of annual revenue.
REGULATORY
DEVELOPMENTS
Composition of Proxy Groups for
Rates of Return Determinations – On July 19, 2007, the FERC issued a
policy statement proposing to update its standards regarding the composition of
proxy groups for determining the appropriate returns on equity (ROE) for natural
gas and oil pipelines, which is used by pipelines to establish rates for
services. On April 17, 2008, the FERC issued a policy statement (2008 Policy
Statement) that allows master limited partnerships (MLPs) to be included in a
proxy group used to determine a pipeline’s ROE. The 2008 Policy Statement is
effective immediately and provides that there should be no cap on the level of
distributions included in the current Discounted Cash Flow (DCF) methodology for
MLPs, but there should be an adjustment to the long-term growth rate used to
calculate DCF for an MLP (halving the long-term GDP factor which has a one-third
weighting in the total growth rate computation in the DCF
methodology).
The
impact of applying this new policy to our pipeline systems will not be known
until one of our pipeline systems files a rate case.
Promotion of a More Efficient
Capacity Release Market Docket No. RM08-1 – On June 19, 2008, the FERC
issued a Final Rule to modify capacity release regulations (Capacity Release
Final Rule). The Capacity Release Final Rule, in addition to other items, allows
market-based pricing for short-term capacity releases by shippers through a
permanent lifting of the maximum rate cap on short-term capacity releases (of
one year or less terms). The Capacity Release Final Rule was effective July 30,
2008.
While
implementation of the Capacity Release Final Rule is not expected to have a
significant impact on our pipeline systems, the Interstate Natural Gas
Association of America (INGAA), of which our pipeline systems are members, filed
on July 21, 2008 a request for rehearing of the Capacity Release Final Rule,
contending that as the FERC removed the rate cap for short-term released
capacity, it should also remove the rate cap for short-term pipeline capacity.
INGAA notes that short-term released capacity and short-term pipeline capacity
compete in the same market, and argues that removing the rate cap for short-term
released capacity and maintaining the cap for short-term pipeline capacity
results in a bifurcated and distorted short-term capacity market. On August 15,
2008, the FERC agreed to further consider the issues raised in the rehearing
request. A FERC Order is pending on this matter.
Homeland Security – The
Department of Homeland Security Appropriations Act of 2007 required the
Transportation Security Administration (TSA) to issue regulations establishing
risk-based performance standards for the security of chemical and industrial
facilities, including oil and gas facilities that were deemed to present high
levels of security risk. The TSA will conduct a critical facility identification
process, which will include our pipeline systems, anticipated in 2009 or 2010.
The TSA has also released a draft of the Pipeline Security Guidelines, which is
likely to become regulation in 2009 or 2010. These guidelines distinguish
between baseline security requirements for all pipeline facilities and enhanced
measures for identified critical facilities. Based on the draft
guidelines it is not anticipated that if our pipeline systems are deemed to be
critical facilities that there would be a significant additional costs related
to compliance.
RESULTS
OF OPERATIONS OF TC PIPELINES
Critical
Accounting Policies and Estimates
The
preparation of financial statements in accordance with Generally Accepted
Accounting Principles (GAAP) requires us to make estimates and assumptions with
respect to values or conditions which cannot be known with certainty, that
affect the reported amount of assets and liabilities and the disclosure of
contingent assets and liabilities at the date of the financial statements. Such
estimates and assumptions also affect the reported amounts of revenue and
expenses during the reporting period. Although we believe these estimates and
assumptions are reasonable, actual results could differ. There were no
significant changes to our critical accounting policies and estimates during the
nine months ended September 30, 2008.
Information
about our critical accounting estimates is included under Item 7, “Management’s
Discussion and Analysis of Financial Condition and Results of Operations,” in
our Annual Report on Form 10-K for the year ended December 31,
2007.
Recent
Accounting Pronouncements
In May
2008, the Financial Accounting Standards Board (FASB) issued SFAS No. 162, The Hierarchy of Generally Accepted
Accounting Principles (SFAS No. 162) which codifies the sources of
accounting principles and the related framework to be utilized in preparing
financial statements in conformity with GAAP. The requirements of this standard
are not expected to have a material impact on our results of operations or
financial position.
In
March 2008, the FASB issued Statement of Financial Accounting Standards
(SFAS) No. 161, Disclosures about Derivative
Instruments and Hedging Activities (SFAS No. 161) as an amendment to SFAS
No. 133, Accounting for
Derivative Instruments and Hedging Activities. SFAS No. 161 requires that
objectives for using derivative instruments be disclosed in terms of underlying
risk and accounting designation. SFAS No. 161 is effective for our fiscal year
beginning January 1, 2009, and we are currently evaluating its applicability to
our results of operations and financial position.
Net
Income
To
supplement our financial statements, we have presented a comparison of the
earnings contribution components from each of our investments. We have presented
net income in this format in order to enhance investors’ understanding of the
way management analyzes our financial performance. We believe this summary
provides a more meaningful comparison of our net income to prior periods, as we
account for our partially owned pipeline systems using the equity method. The
presentation of this additional information is not meant to be considered in
isolation or as a substitute for results prepared in accordance with
GAAP.
The
shaded areas in the tables below disclose the results from Great Lakes and
Northern Border, representing 100 per cent of each entity's operations for
the given period.
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(unaudited)
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For
the three months ended September 30, 2008
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For
the nine months ended September 30, 2008
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(millions
of dollars)
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PipeLP
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TGTC(1)
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Other
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GLGT(2)
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NBPC(3)
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PipeLP
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TGTC(1)
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Other
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GLGT(2)
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NBPC(3)
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Transmission
revenues
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|
|
8.2 |
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8.2 |
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- |
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66.7 |
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67.7 |
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23.3 |
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23.3 |
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- |
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213.9 |
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212.8 |
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Operating
expenses
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(2.3 |
) |
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(1.4 |
) |
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(0.9 |
) |
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(17.1 |
) |
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(19.3 |
) |
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(6.8 |
) |
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(3.7 |
) |
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(3.1 |
) |
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(45.9 |
) |
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(57.5 |
) |
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5.9 |
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6.8 |
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(0.9 |
) |
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49.6 |
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48.4 |
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16.5 |
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19.6 |
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(3.1 |
) |
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168.0 |
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155.3 |
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Depreciation
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(1.8 |
) |
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(1.8 |
) |
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- |
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(14.7 |
) |
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(15.3 |
) |
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(5.1 |
) |
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(5.1 |
) |
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- |
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(43.9 |
) |
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(45.8 |
) |
Financial
charges, net and other
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(7.7 |
) |
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(1.1 |
) |
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(6.6 |
) |
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(8.0 |
) |
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7.1 |
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(22.8 |
) |
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(3.1 |
) |
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(19.7 |
) |
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(24.4 |
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(12.1 |
) |
Michigan
business tax
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- |
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- |
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- |
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(1.2 |
) |
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- |
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- |
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- |
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- |
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(4.2 |
) |
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- |
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25.7 |
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40.2 |
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95.5 |
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97.4 |
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Equity
income
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31.9 |
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- |
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- |
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12.0 |
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19.9 |
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92.5 |
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- |
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- |
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44.4 |
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48.1 |
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Net
income
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28.3 |
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3.9 |
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(7.5 |
) |
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12.0 |
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19.9 |
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81.1 |
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11.4 |
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(22.8 |
) |
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44.4 |
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48.1 |
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(unaudited)
|
|
For
the three months ended September 30, 2007
|
|
|
For
the nine months ended September 30, 2007
|
|
(millions
of dollars)
|
|
PipeLP
|
|
|
TGTC(1)
|
|
Other
|
|
|
GLGT(2)
|
|
|
NBPC(3)
|
|
PipeLP
|
|
|
TGTC(1)
|
|
Other
|
|
|
GLGT(2)
|
|
|
NBPC(3)
|
|
Transmission
revenues
|
|
|
6.7 |
|
|
|
6.7 |
|
|
|
- |
|
|
|
65.6 |
|
|
|
79.6 |
|
|
|
20.3 |
|
|
|
20.3 |
|
|
|
- |
|
|
|
162.2 |
|
|
|
228.0 |
|
Operating
expenses
|
|
|
(2.2 |
) |
|
|
(1.2 |
) |
|
|
(1.0 |
) |
|
|
(12.6 |
) |
|
|
(21.6 |
) |
|
|
(6.4 |
) |
|
|
(3.7 |
) |
|
|
(2.7 |
) |
|
|
(34.0 |
) |
|
|
(61.7 |
) |
|
|
|
4.5 |
|
|
|
5.5 |
|
|
|
(1.0 |
) |
|
|
53.0 |
|
|
|
58.0 |
|
|
|
13.9 |
|
|
|
16.6 |
|
|
|
(2.7 |
) |
|
|
128.2 |
|
|
|
166.3 |
|
Depreciation
|
|
|
(1.6 |
) |
|
|
(1.6 |
) |
|
|
- |
|
|
|
(14.5 |
) |
|
|
(15.1 |
) |
|
|
(4.7 |
) |
|
|
(4.7 |
) |
|
|
- |
|
|
|
(34.9 |
) |
|
|
(45.6 |
) |
Financial
charges, net and other
|
|
|
(8.7 |
) |
|
|
(1.0 |
) |
|
|
(7.7 |
) |
|
|
(8.1 |
) |
|
|
(10.2 |
) |
|
|
(25.5 |
) |
|
|
(3.4 |
) |
|
|
(22.1 |
) |
|
|
(19.5 |
) |
|
|
(30.9 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
30.4 |
|
|
|
32.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
73.8 |
|
|
|
89.8 |
|
Equity
income
|
|
|
30.4 |
|
|
|
- |
|
|
|
- |
|
|
|
14.2 |
|
|
|
16.2 |
|
|
|
78.6 |
|
|
|
- |
|
|
|
- |
|
|
|
34.3 |
|
|
|
44.3 |
|
Net
income
|
|
|
24.6 |
|
|
|
2.9 |
|
|
|
(8.7 |
) |
|
|
14.2 |
|
|
|
16.2 |
|
|
|
62.3 |
|
|
|
8.5 |
|
|
|
(24.8 |
) |
|
|
34.3 |
|
|
|
44.3 |
|
(1) The
Partnership owns a 100 per cent general partner interest in Tuscarora Gas
Transmission Company (Tuscarora or TGTC) following the acquisition of an
additional two per cent interest on December 31, 2007.
(2) The
Partnership acquired a 46.45 per cent partner interest in Great Lakes Gas
Transmission Limited Partnership (Great Lakes or GLGT) on February 22,
2007.
(3) The
Partnership owns a 50 per cent general partner interest in Northern Border
Pipeline Company (Northern Border or NBPC). Equity income from Northern Border
includes amortization of a $10.0 million transaction fee paid to the operator of
Northern Border at the time of the additional 20 per cent acquisition in April
2006.
Third
Quarter 2008 compared with Third Quarter 2007
Net
income increased $3.7 million, or 15 per cent, to $28.3 million in the third
quarter of 2008, compared to $24.6 million in the third quarter of 2007. This
increase was primarily due to higher equity income from Northern Border,
increased Tuscarora transmission revenues and lower financial charges, net and
other, partially offset by decreased equity income from Great
Lakes.
Equity
income from Great Lakes was $12.0 million in the third quarter of 2008, a
decrease of $2.2 million or 15 per cent, compared to $14.2 million for the same
period last year. The decrease in equity income was primarily due to increased
operating expenses and Michigan business tax (a partnership level tax that was
instituted in 2008), partially offset by increased transmission revenues. At
Great Lakes’ level, operating expenses increased $4.5 million for the three
months ended September 30, 2008 compared to the same period last year primarily
due to higher taxes other than income, costs related to system integration
expenditures and increased pipeline maintenance costs. Michigan business tax of
$1.2 million was recorded for the three months ended September 30, 2008. Great
Lakes’ transmission revenues increased $1.1 million for the three months ended
September 30, 2008 compared to the same period last year due primarily to higher
short-term revenues from increased sales of daily transport
capacity.
Equity
income from Northern Border was $19.9 million in the third quarter of 2008, an
increase of $3.7 million or 23 per cent, compared to $16.2 million in the same
period last year. This is primarily due to a $16.1 million gain on sale of Bison
Pipeline LLC and decreased operating expenses, partially offset by lower
transmission revenues. At Northern Border’s level, operating expenses decreased
$2.3 million for the three months ended September 30, 2008 compared to the same
period last year primarily due to decreased maintenance costs, decreased
electric compressor charges related to lower capacity utilization and decreased
taxes other than income. Northern Border’s transmission revenues decreased $11.9
million, or 15 per cent, for the three months ended September 30, 2008 compared
to the same period last year due primarily to a decrease in system utilization
mainly related to natural gas supply from the Rockies Basin into the
Mid-Continent market from the in-service of REX West.
Tuscarora’s
net income was $3.9 million in the third quarter of 2008, an increase of $1.0
million or 34 per cent, compared to $2.9 million in the same period last year.
The increase in net income is primarily due to increased transmission revenues
resulting from a new firm transportation service contract which supported the
Likely compressor station expansion project that went into service on April 1,
2008.
Financial
charges, net and other were $7.7 million in the third quarter of 2008, a
decrease of $1.0 million or 11 per cent, compared to $8.7 million in the same
period last year. This decrease relates primarily to lower interest rates and
lower average debt outstanding, partially offset by losses on interest rate
derivatives over the same period in 2007.
Nine
Months Ended September 30, 2008 compared with Nine Months Ended September 30,
2007
Net
income increased $18.8 million, or 30 per cent, to $81.1 million for the nine
months ended September 30, 2008, compared to $62.3 million in the same period of
2007. The increase in net income was primarily due to increased equity income
from Great Lakes and Northern Border, higher Tuscarora transmission revenues and
lower financial charges, net and other.
Equity
income from Great Lakes was $44.4 million for the nine months ended September
30, 2008, an increase of $10.1 million or 29 per cent, compared to $34.3 million
for the period February 23 to September 30, 2007. The increase in equity income
was primarily due to a full first quarter of income contribution in 2008 as
compared to 37 days in the first quarter of 2007. In addition, Great Lakes’
transmission revenues increased primarily due to increased sales of short term
transport capacity, partially offset by costs related to system integration
expenditures and increased pipe integrity costs. In the nine months ended
September 30, 2008, Great Lakes recorded Michigan business tax of $4.2 million,
which is a new partnership level tax that was instituted in 2008.
Equity
income from Northern Border was $48.1 million for the nine months ended
September 30, 2008, an increase of $3.8 million or 9 per cent, compared to $44.3
million in the same period of 2007. The increase in equity income is primarily
due to a $16.1 million gain on sale of Bison Pipeline LLC, and decreased
operating expenses, partially offset by lower transmission revenues. At Northern
Border’s level, operating expenses decreased by $4.2 million in the nine months
ended September 30, 2008 compared to the same period last year. This decrease in
operating expenses is primarily due to decreased taxes other than income and a
$2.3 million transition related charge in 2007 related to the reimbursement for
shared equipment and furnishings, partially offset by increased general and
administrative expenses and electric compressor charges. Northern Border’s
transmission revenues decreased by $15.2 million in the nine months ended
September 30, 2008 compared to the same period in 2007. This decrease was
primarily due to a decrease in contracted capacity mainly related to natural gas
supply from the Rockies Basin into the Mid-Continent market from the in-service
of REX West.
Tuscarora’s
net income was $11.4 million for the nine months ended September 30, 2008, an
increase of $2.9 million or 34 per cent, compared to $8.5 million in the same
period of 2007. The increase in net income is primarily due to increased
Tuscarora transmission revenues resulting from a new firm transportation service
contract which supported the Likely compressor station expansion that went into
service on April 1, 2008.
Financial
charges, net and other were $22.8 million for the nine months ended September
30, 2008, a decrease of $2.7 million, or 11 per cent, compared to $25.5 million
for the same period of 2007. This decrease relates primarily to lower interest
rates and lower average debt outstanding, partially offset by losses on interest
rate derivatives over the same period in 2007.
Partnership
Cash Flows
The
Partnership uses the non-GAAP financial measures ‘Partnership cash flows’ and
‘Partnership cash flows allocated to common units’ as financial performance
measures. As the Partnership’s financial performance underpins the
availability of cash flows to fund the cash distributions that the Partnership
pays to its unitholders, the Partnership believes these are key measures of the
available cash flows to its unitholders. The following Partnership cash
flows information is presented to enhance investors’ understanding of the way
that management analyzes the Partnership’s financial
performance. Partnership cash flows and Partnership cash flows allocated to
common units are provided as a supplement to financial results and are not meant
to be considered in isolation or as substitutes for financial results prepared
in accordance with GAAP.
(unaudited)
|
|
Three
months ended
September
30,
|
|
|
Nine
months ended
September
30,
|
|
(millions
of dollars except per common unit amounts)
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
Net
Income
|
|
|
28.3 |
|
|
|
24.6 |
|
|
|
81.1 |
|
|
|
62.3 |
|
Add:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
flows provided by Tuscarora's operating activities
|
|
|
7.2 |
|
|
|
4.6 |
|
|
|
17.3 |
|
|
|
13.5 |
|
Cash
distributions from Great Lakes
|
|
|
19.3 |
|
|
|
17.4 |
|
|
|
55.0 |
|
|
|
41.0 |
|
Cash
distributions from Northern Border
|
|
|
22.6 |
|
|
|
14.8 |
|
|
|
72.0 |
|
|
|
62.5 |
|
|
|
|
49.1 |
|
|
|
36.8 |
|
|
|
144.3 |
|
|
|
117.0 |
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tuscarora's
net income
|
|
|
(3.9 |
) |
|
|
(2.9 |
) |
|
|
(11.4 |
) |
|
|
(8.5 |
) |
Equity
income from investment in Great Lakes
|
|
|
(12.0 |
) |
|
|
(14.2 |
) |
|
|
(44.4 |
) |
|
|
(34.3 |
) |
Equity
income from investment in Northern Border
|
|
|
(19.9 |
) |
|
|
(16.2 |
) |
|
|
(48.1 |
) |
|
|
(44.3 |
) |
|
|
|
(35.8 |
) |
|
|
(33.3 |
) |
|
|
(103.9 |
) |
|
|
(87.1 |
) |
Partnership
cash flows
|
|
|
41.6 |
|
|
|
28.1 |
|
|
|
121.5 |
|
|
|
92.2 |
|
Partnership
cash flows allocated to general partner (1)
|
|
|
(3.2 |
) |
|
|
(2.3 |
) |
|
|
(8.6 |
) |
|
|
(5.3 |
) |
Partnership
cash flows allocated to common units
|
|
|
38.4 |
|
|
|
25.8 |
|
|
|
112.9 |
|
|
|
86.9 |
|
Cash
distributions declared
|
|
|
(27.8 |
) |
|
|
(25.4 |
) |
|
|
(83.0 |
) |
|
|
(75.4 |
) |
Cash
distributions declared per common unit (2)
|
|
$ |
0.705 |
|
|
$ |
0.660 |
|
|
$ |
2.110 |
|
|
$ |
1.965 |
|
Cash
distributions paid
|
|
|
(27.8 |
) |
|
|
(25.1 |
) |
|
|
(80.8 |
) |
|
|
(61.3 |
) |
Cash
distributions paid per common unit (2)
|
|
$ |
0.705 |
|
|
$ |
0.655 |
|
|
$ |
2.070 |
|
|
$ |
1.905 |
|
Weighted
average common units outstanding (millions)
|
|
|
34.9 |
|
|
|
34.9 |
|
|
|
34.9 |
|
|
|
31.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Partnership cash flows allocated to general partner represents the cash
distributions paid to the general partner with respect to its two per cent
interest plus an amount equal to incentive distributions.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2)
Cash distributions declared per common unit and cash distributions paid
per common unit are computed by dividing cash distributions, after the
deduction of the general partner's allocation, by the number of common
units outstanding. The general partner's allocation is computed based upon
the general partner's two per cent interest plus an amount equal to
incentive distributions.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Third
Quarter 2008 compared with Third Quarter 2007
Partnership
cash flows increased $13.5 million, or 48 per cent, to $41.6 million for the
third quarter of 2008, compared to $28.1 million for the same period last year.
This increase was primarily due to higher cash distributions received from Great
Lakes and Northern Border, increased cash flows provided by Tuscarora’s
operating activities and lower costs at the Partnership level. Cash
distributions from Great Lakes and Northern Border increased by $9.7 million in
total for the three months ended September 30, 2008 compared with the same
period last year. This increase in cash distributions was primarily due to the
special distribution of $8.2 million received from Northern Border in relation
to the gain on sale of Bison Pipeline LLC. Cash flows provided by Tuscarora’s
operating activities increased by $2.6 million for the quarter ended September
30, 2008 compared with the same period last year primarily due to higher
transmission revenues resulting from the Likely compressor station expansion
project that went into service on April 1, 2008.
Costs at the Partnership level decreased by $1.2 million for the quarter
ended September 30, 2008 compared with the same period last year primarily due
to lower interest rates and lower average debt outstanding, partially offset by
losses on interest rate derivatives over the same period in 2007.
During
the three months ended September 30, 2008, Tuscarora made capital expenditures
of $1.0 million related to the compressor station expansion project in Likely,
California compared to $0.9 million for the same period last year. In the third
quarter of 2007, a net $1.8 million was received related to the Great Lakes
acquisition closing adjustments.
The
Partnership paid distributions of $27.8 million in the third quarter of 2008, an
increase of $2.7 million, or 11 per cent, compared to $25.1 million for the same
period in the prior year due to increases in quarterly per common unit
distribution amounts. We repaid a net $3.0 million of the outstanding balance on
our debt during the third quarter of 2008 compared to a net issuance of debt of
$1.0 million during the same period last year.
Nine
Months Ended September 30, 2008 compared with Nine Months Ended September 30,
2007
Partnership
cash flows increased $29.3 million, or 32 per cent, to $121.5 million for the
nine months ended September 30, 2008, compared to $92.2 million for the same
period last year. This increase was primarily a result of increased cash
distributions from Great Lakes and Northern Border, increased cash flows
provided by Tuscarora’s operating activities and decreased costs at the
Partnership level.
Cash
distributions from Great Lakes were $55.0 million for the nine months ended
September 30, 2008, an increase of $14.0 million compared to $41.0 million for
the same period last year. The increase in cash distributions from Great Lakes
is due primarily to a full nine months of ownership in 2008 compared to the
period of February 23 to September 30 for 2007. Cash distributions from Northern
Border increased $9.5 million for the nine months ended September 30, 2008
compared to the same period in the prior year due primarily to the special
distribution of $8.2 million received from Northern Border in relation to the
gain on sale of Bison Pipeline LLC. Cash flows provided by Tuscarora’s operating
activities increased $3.8 million for the nine months ended September 30, 2008
compared to the same period in the prior year primarily due to the financial
results from the Likely compressor station expansion project that went into
service on April 1, 2008. Costs at the Partnership level decreased by $2.0
million for the nine months ended September 30, 2008 compared with the same
period last year primarily due to lower average debt outstanding and lower
interest rates, partially offset by losses on interest rate derivatives and
increased general and administrative costs.
During
the nine months ended September 30, 2008, Tuscarora made capital expenditures of
$6.4 million related to the compressor station expansion project in Likely,
California compared to $4.4 million for the same period last year. In February
2007, the Partnership acquired a 46.45 per cent interest in Great Lakes from El
Paso Corporation for $733.0 million in cash. In April 2007, the Partnership made
a contribution of $7.5 million to Northern Border, representing the
Partnership’s 50 per cent share of a $15.0 million cash call issued by Northern
Border.
The
Partnership paid distributions of $80.8 million for the nine months ended
September 30, 2008, an increase of $19.5 million, or 32 per cent, compared to
$61.3 million for the same period in the prior year due to the increase in the
number of common units outstanding, in addition to increases in quarterly per
common unit distribution amounts. We repaid a net $27.3 million of the
outstanding balance on our debt during the nine months ended September 30, 2008.
In 2007, net equity issuances provided $607.0 million, including the general
partner’s contribution to maintain its two per cent interest, to acquire Great
Lakes. The Partnership funded the balance of the acquisition cost with a draw on
its senior credit facility.
LIQUIDITY
AND CAPITAL RESOURCES OF TC PIPELINES
Overview
Our
principal sources of liquidity include distributions received from our
investments in Great Lakes and Northern Border, operating cash flows from
Tuscarora and our bank credit facility. The Partnership funds its operating
expenses, debt service and cash distributions primarily with operating cash
flow. Long-term capital needs may be met through the issuance of long-term debt
and/or equity.
The
Partnership’s Debt and Credit Facility
The
following table summarizes our debt and credit facility outstanding as of
September 30, 2008:
|
|
Payments
Due by Period
|
|
(unaudited)
(millions
of dollars)
|
|
Total
|
|
|
Less
Than 1 Year
|
|
|
Long-term
Portion
|
|
|
|
|
|
|
|
|
|
|
|
Senior
Credit Facility
|
|
|
482.0 |
|
|
|
- |
|
|
|
482.0 |
|
7.13%
Series A Senior Notes due 2010
|
|
|
52.9 |
|
|
|
3.2 |
|
|
|
49.7 |
|
7.99%
Series B Senior Notes due 2010
|
|
|
5.3 |
|
|
|
0.5 |
|
|
|
4.8 |
|
6.89%
Series C Senior Notes due 2012
|
|
|
5.9 |
|
|
|
0.8 |
|
|
|
5.1 |
|
Total
|
|
|
546.1 |
|
|
|
4.5 |
|
|
|
541.6 |
|
The
Senior Credit Facility consists of a $475.0 million senior term loan and a
$250.0 million senior revolving credit facility. The interest rate on the Senior
Credit Facility averaged 3.31 per cent for the three months ended September 30,
2008 (2007 – 5.97 per cent), while for the nine months ended September 30, 2008
the interest rate on the Senior Credit Facility averaged 3.93 per cent (2007 –
6.02 per cent). After hedging activity, the interest rate incurred on the Senior
Credit Facility averaged 5.23 per cent for the three months ended September 30,
2008 (2007 – 5.70 per cent) and 5.18 per cent for the nine months ended
September 30, 2008 (2007 – 5.52 per cent). Prior to hedging activities, the
interest rate was 3.36 per cent at September 30, 2008 (December 31, 2007 – 5.62
per cent). At September 30, 2008, we were in compliance with our financial
covenants.
In spite
of the current volatility in the capital markets, neither the Partnership nor
its pipeline systems have experienced significant impacts to liquidity or access
to the credit markets, although continued volatility in the capital markets may
increase costs associated with borrowing.
The
Partnership views its core banking group as high quality and has a
well-established relationship with these institutions. As of November 3,
2008, the Partnership had no outstanding borrowings under the $250.0 million
revolving portion of the Senior Credit Facility. The Partnership has an existing
$250.0 million debt and equity shelf expiring December 1, 2008 which it expects
to renew in the fourth quarter 2008. This will supplement the $250.0
million of capacity available under the Partnership’s existing revolving credit
and term loan facility which expires on December 12, 2011.
Interest
Rate Swaps and Options
We use
derivatives to assist in managing our exposure to interest rate risk. The
interest rate swaps and options are structured such that the cash flows match
those of the Senior Credit Facility. The notional amount hedged was $475.0
million at September 30, 2008 (December 31, 2007 - $400.0 million). At September
30, 2008, the fair value of the interest rate swaps and options accounted for as
hedges was negative $11.5 million (December 31, 2007 – negative $9.8 million).
Effective January 1, 2008, we adopted the provisions of Statement of Financial
Accounting Standards (SFAS) No. 157, Fair Value Measurements (SFAS
157). Under SFAS 157, these financial assets and liabilities that are
recorded at fair value on a recurring basis are categorized into one of three
categories based upon a fair value hierarchy. We have classified all our
derivative financial instruments as level II where the fair value is determined
by using valuation techniques that refer to observable market data or estimated
market prices. During the
three and nine months ended September 30, 2008, we recorded interest expense of
$2.4 million and $4.7 million, respectively, in regards to the interest rate
swaps and options. We recorded interest income of $0.4 million and
$0.8 million for the three and nine months ended September 30, 2007,
respectively, in regards to the interest rate swaps and options.
2008
Third Quarter Cash Distribution
On
October 17, 2008, the Board of Directors of the general partner declared the
Partnership’s 2008 third quarter cash distribution. The third quarter cash
distribution will be paid on November 14, 2008 to unitholders of record as of
October 31, 2008, totaling $27.8 million and will be paid in the following
manner: $24.6 million to common unitholders (including $1.4 million to the
general partner as holder of 2,035,106 common units and $6.1 million to TransCan
Northern Ltd. as holder of 8,678,045 common units), $2.6 million to the general
partner as holder of the incentive distribution rights, and $0.6 million to the
general partner in respect of its two per cent general partner
interest.
2009
Capital Requirements
Northern
Border’s distribution policy adopted in 2006 defines minimum equity to total
capitalization to be used by the Management Committee to establish the timing
and amount of required equity contributions. In accordance with this policy and
in anticipation of the equity financing of Northern Border's Des Plaines
Project, Northern Border currently estimates an equity contribution of
approximately $85 million in the upcoming year, of which the Partnership's share
would be approximately $43 million. The Partnership expects to finance
this equity contribution with a combination of debt and operating cash
flows.
LIQUIDITY
AND CAPITAL RESOURCES OF OUR PIPELINE SYSTEMS
Overview
Our
pipeline systems’ principal source of liquidity is cash generated from operating
activities and bank credit facilities. Our pipeline systems fund their operating
expenses, debt service and cash distributions to partners primarily with
operating cash flow.
Capital
expenditures are funded by a variety of sources, including cash generated from
operating activities, borrowings under bank credit facilities, issuance of
senior notes or equity contributions from our pipeline systems’ partners. The
ability of our pipeline systems to access capital markets for debt under
reasonable terms depends on their financial condition, credit ratings and market
conditions.
Our
pipeline systems believe that their ability to obtain financing at reasonable
rates and their history of consistent cash flow from operating activities
provide a solid foundation to meet their future liquidity and capital resource
requirements. The Partnership’s pipeline systems monitor the creditworthiness of
their customers and have credit provisions included in their tariffs, which
allow them to request credit support as circumstances
dictate. Additionally, Northern Border has established relationships
with high-quality banks, which are involved in its revolving credit facility and
provide liquidity for Northern Border’s operating needs.
Debt
of Great Lakes
The
following table summarizes Great Lakes’ debt outstanding as of September 30,
2008:
|
|
Payments
Due by Period
|
|
(unaudited)
(millions
of dollars)
|
|
Total
|
|
|
Less
than 1 year
|
|
|
Long-term
Portion
|
|
|
|
|
|
|
|
|
|
|
|
8.74%
series Senior Notes due 2008 to 2011
|
|
|
40.0 |
|
|
|
10.0 |
|
|
|
30.0 |
|
6.73%
series Senior Notes due 2009 to 2018
|
|
|
90.0 |
|
|
|
9.0 |
|
|
|
81.0 |
|
9.09%
series Senior Notes due 2012 to 2021
|
|
|
100.0 |
|
|
|
- |
|
|
|
100.0 |
|
6.95%
series Senior Notes due 2019 to 2028
|
|
|
110.0 |
|
|
|
- |
|
|
|
110.0 |
|
8.08%
series Senior Notes due 2021 to 2030
|
|
|
100.0 |
|
|
|
- |
|
|
|
100.0 |
|
Total
|
|
|
440.0 |
|
|
|
19.0 |
|
|
|
421.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Great
Lakes is required to comply with certain financial, operational and legal
covenants. Under the most restrictive covenants in the Senior Note
Agreements, approximately $237.0 million of Great Lakes’ partners’ capital was
restricted as to distributions as of September 30, 2008. At September 30, 2008,
Great Lakes was in compliance with all of its financial covenants.
Debt,
Credit Facility and Contractual Obligations of Northern Border
The
following table summarizes Northern Border’s debt and credit facility
outstanding as of September 30, 2008:
|
|
Payments
Due by Period
|
|
(unaudited)
(millions
of dollars)
|
|
Total
|
|
|
Less
than 1 year
|
|
|
Long-term
Portion
|
|
|
|
|
|
|
|
|
|
|
|
7.75%
senior notes due 2009
|
|
|
200.0 |
|
|
|
200.0 |
|
|
|
- |
|
7.50%
senior notes due 2021
|
|
|
250.0 |
|
|
|
- |
|
|
|
250.0 |
|
$250
million credit agreement due 2012(a)
|
|
|
172.0 |
|
|
|
- |
|
|
|
172.0 |
|
Total
|
|
|
622.0 |
|
|
|
200.0 |
|
|
|
422.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
Northern Border is required to pay a facility fee of 0.05% on the
principal commitment amount of its credit agreement.
|
|
Revolving
Credit Agreement
As of
September 30, 2008, Northern Border had outstanding borrowings of $172.0 million
under its $250 million revolving credit agreement and was in compliance with the
covenants of the agreement. The weighted average interest rate related to the
borrowings on the credit agreement was 2.99 per cent at September 30,
2008.
Senior
Notes due 2009
On
September 1, 2009, the $200.0 million 7.75 per cent senior notes will mature. As
market conditions dictate, Northern Border will finance the repayment by use of
fixed-rate debt, variable-rate debt or a combination of fixed-rate and
variable-rate debt.
Interest Rate
Collar Agreement
At
September 30, 2008, Northern Border’s balance sheet reflected an unrealized loss
of approximately $2.2 million with a corresponding increase to accumulated other
comprehensive loss related to the changes in fair value of its zero cost
interest rate collar agreement (the “Collar Agreement”) since inception. During
the three and nine months ended September 30, 2008, Northern Border recorded
interest expense of $0.5 million and $1.3 million, respectively, under the
Collar Agreement. Hedge ineffectiveness had no impact on income for the three
and nine months ended September 30, 2008.
Contractual
Obligations
Northern
Border has commitments totaling approximately $2.2 million in relation to the
Des Plaines Project at September 30, 2008, with total expected costs to be
approximately $18 million. Half of the project costs will be financed under
Northern Border’s credit facility and the other half by equity contributions
from its partners. See section entitled “Recent Developments” in Item 2.
“Management’s Discussion and Analysis of Financial Condition and Results of
Operations” for further discussion of this project.
RELATED
PARTY TRANSACTIONS
Great
Lakes earns transportation revenues from TransCanada and its affiliates under
fixed price contracts with remaining terms ranging from one to ten years. Great
Lakes earned $40.5 million of transportation revenues under these contracts for
the three months ended September 30, 2008 (2007 - $32.4 million). This amount
represents 61 per cent of total revenues earned by Great Lakes for the three
months ended September 30, 2008 (2007 - 50 per cent). $18.8 million of this
transportation revenue is included in our equity income from Great Lakes for the
three months ended September 30, 2008 (2007 - $15.1 million).
Great
Lakes earned $108.7 million of transportation revenues from TransCanada and its
affiliates for the nine months ended September 30, 2008 (February 23, 2007 to
September 30, 2007 - $81.5 million). This amount represents 51 per cent of total
revenues earned by Great Lakes for the nine months ended September 30, 2008
(February 23, 2007 to September 30, 2007 - 50 per cent). $50.5 million of this
transportation revenue is included in our equity income from Great Lakes for the
nine months ended September 30, 2008 (February 23, 2007 to September 30, 2007 -
$37.9 million). At September 30, 2008, $13.4 million is included in Great Lakes’
receivables in regards to the transportation contracts with TransCanada and its
affiliates (December 31, 2007 - $10.0 million).
Please
read Note 8 within Item 1. “Financial Statements” for additional information
regarding related party transactions.
Item
3. Quantitative
and Qualitative Disclosures About Market Risk
OVERVIEW
Our
exposure to market risk discussed below includes forward-looking statements and
represents an estimate of possible changes in future earnings that would occur
assuming hypothetical future movements in interest rates. Our views on market
risk are not necessarily indicative of actual results that may occur and do not
represent the maximum possible gains and losses that may occur, since actual
gains and losses will differ from those estimated, based on actual fluctuations
in interest rates and the timing of transactions.
We are
exposed to market risk due to interest rate fluctuations. Market risk is the
risk of loss arising from adverse changes in market rates. We utilize financial
instruments to manage the risks of certain identifiable or anticipated
transactions to achieve a more predictable cash flow. Our risk management
function follows established policies and procedures to monitor interest rates
to ensure our hedging activities mitigate market risks. We do not use financial
instruments for trading purposes.
In
accordance with SFAS No. 133, Accounting for Derivative
Instruments and Hedging Activities we record financial instruments on the
balance sheet as assets and liabilities based on fair value. We estimate the
fair value of financial instruments using available market information and
appropriate valuation techniques. Changes in financial instruments’ fair value
are recognized in earnings unless the instrument qualifies as a hedge under SFAS
No. 133 and meets specific hedge accounting criteria. Qualifying financial
instruments’ gains and losses may offset the hedged items’ related results in
earnings for a fair value hedge or be deferred in accumulated other
comprehensive income for a cash flow hedge.
INTEREST
RATE RISK
Our
interest rate exposure results from our Senior Credit Facility, which is subject
to variability in London Interbank Offered Rate (LIBOR) interest rates. We
regularly assess the impact of interest rate fluctuations on future cash flows
and evaluate hedging opportunities to mitigate our interest rate risk. The
notional amount hedged at September 30, 2008 was $475.0 million. The interest
rate swaps and options are structured such that the cash flows match those of
the Senior Credit Facility. The fair value of interest rate derivatives has been
calculated using period-end market rates. At September 30, 2008, the fair value
of our interest rate swaps and options accounted for as hedges was negative
$11.5 million.
At
September 30, 2008, we had $482.0 million outstanding on our Senior Credit
Facility. Utilizing the conditions of the interest rate swaps and options, if
LIBOR interest rates hypothetically increased by one per cent (100 basis points)
compared to the rates in effect as of September 30, 2008, our annual interest
expense would have increased and our net income would have decreased by $0.1
million; and if LIBOR interest rates hypothetically decreased by one per cent
(100 basis points) compared to the rates in effect as of September 30, 2008, our
annual interest expense would have decreased and our net income would have
increased by $0.1 million. This amount has been determined by considering the
impact of the hypothetical interest rates on variable rate borrowings
outstanding as of September 30, 2008.
Northern
Border utilizes both fixed-rate and variable-rate debt and is exposed to market
risk due to the floating interest rates on its credit facility. Northern Border
regularly assesses the impact of interest rate fluctuations on future cash flows
and evaluates hedging opportunities to mitigate its interest rate risk. As of
September 30, 2008, 72 per cent of Northern Border’s outstanding debt was at
fixed rates. Northern Border utilizes its Collar Agreement to limit the
variability of the interest rate on $140.0 million of variable-rate
borrowings.
Utilizing
the conditions of the Collar Agreement, if interest rates hypothetically
increased one per cent (100 basis points) compared with rates in effect as of
September 30, 2008, Northern Border’s annual interest expense would increase and
its net income would decrease by approximately $0.3 million; and if interest
rates hypothetically decreased one per cent (100 basis points) compared with
rates in effect as of September 30, 2008, Northern Border’s annual interest
expense would decrease and its net income would increase by approximately $0.3
million.
Great
Lakes and Tuscarora utilize fixed-rate debt; therefore, they are not exposed to
market risk due to floating interest rates.
OTHER
RISKS
The
Partnership is influenced by the same factors that influence our pipeline
systems. None of our pipeline systems own any of the natural gas they transport;
therefore, they do not assume any of the related natural gas commodity price
risk.
The state
of Minnesota currently requires Great Lakes to pay use tax on the value of the
shipper provided compressor fuel burned in its Minnesota compressor
engines. Great Lakes is subject to primarily commodity price volatility and
some volume volatility in determining the amount of use tax owed. If
natural gas prices changed by $1 per million British thermal units, Great Lakes’
annual use tax expense would change by approximately $0.7 million.
The
Partnership does not have any material foreign currency exchange
risks.
Item
4. Controls
and Procedures
EVALUATION
OF DISCLOSURE CONTROLS AND PROCEDURES
Based on
their evaluation of the Partnership’s disclosure controls and procedures as of
the end of the period covered by this quarterly report, the principal executive
officer and principal financial officer of the general partner of the
Partnership have concluded that the Partnership’s disclosure controls and
procedures were effective in ensuring that the information required to be
disclosed by the Partnership in the reports that it files or submits under the
Securities Exchange Act of 1934 is recorded, processed, summarized and reported
within the time periods specified in the Securities and Exchange Commission’s
(SEC’s) rules and forms and that information required to be disclosed by the
Partnership in the reports that the Partnership files or submits under the
Exchange Act is accumulated and communicated to the management of the general
partner of the Partnership, including the principal executive officer and
principal financial officer, as appropriate to allow timely decisions regarding
required disclosure.
Changes
in Internal Control over Financial Reporting
During
the quarter ended September 30, 2008, there has been no change in the
Partnership’s internal control over financial reporting that has materially
affected or is reasonably likely to materially affect our internal control over
financial reporting.
PART
II – OTHER INFORMATION
Item
1A. Risk
Factors
Our
business is subject to the risks described below and the risk factors disclosed
in Part I, Item 1A. “Risk Factors,” in our Annual Report on Form 10-K for the
year ended December 31, 2007.
The
following new risk factor should be read in conjunction with the risk factors
disclosed in Part I, Item 1A. “Risk Factors,” in our Annual Report on Form 10-K
for the year ended December 31, 2007:
The
current capital and credit market conditions may adversely affect the
Partnership or our pipeline systems’ access to capital and cost of
capital.
Access to
capital markets is important to the Partnership to enable it to execute its
business strategies, which include seeking opportunities to undertake accretive
acquisitions and organic growth projects, and maximize the value of our existing
portfolio of pipeline systems. Access to capital markets is important to
our pipeline systems’ ability to operate and Northern Border expects to
refinance $200 million of Senior Notes in 2009. In October 2008, the general
economic and capital market conditions in the United States and other parts of
the world have deteriorated significantly and have adversely affected access to
capital and increased the cost of capital. If these conditions continue or
become worse, the Partnership’s and our pipeline systems’ future cost of debt
and equity capital, and future access to capital markets could be adversely
affected.
The
following updated risk factors should be read in conjunction with the risk
factors disclosed in Part I, Item 1A. “Risk Factors,” in our Annual Report on
Form 10-K for the year ended December 31, 2007:
The
long-term financial conditions of our pipeline systems are dependent on the
continued availability of Western Canadian natural gas for import into the U.S.
and the market demand for these volumes. Competition from pipelines that deliver
natural gas from other supply sources to our pipeline systems’ market areas
could cause our pipeline systems to discount their rates or otherwise experience
a reduction in their revenues.
The
development of additional natural gas reserves requires significant capital
expenditures by others for exploration and development drilling and the
installation of production, gathering, storage, transportation and other
facilities that permit natural gas to be produced and delivered to pipelines
that interconnect with our pipeline systems. High exploration and production
costs, low prices for natural gas, regulatory limitations such as royalty
frameworks, or the lack of available capital for these projects could adversely
affect the development of additional reserves in Western Canada and the
production in the WCSB.
Volumes
available for export out of the WCSB depend in part on the internal demand for
Canadian natural gas which may increase as a result of increased demand for
electricity generation and other industrial requirements, including the
development of oil sands projects, which may require substantial amounts of
natural gas. This higher internal demand may reduce the amount of gas available
for import into the U.S. In the longer term, a portion of the Alberta hub gas
supply may come from proposed gas pipelines from the North Slope of Alaska and
the Mackenzie Delta of Canada and from the continued growth of coal bed methane
projects. Cancellation or delays in the construction of such pipelines or such
projects could adversely affect the volumes available for export in the long
term.
If the
availability of Alberta hub natural gas was to decline, existing shippers on our
pipeline systems may be unlikely to extend their contracts and our pipeline
systems may be unable to find replacement shippers for lost capacity.
Furthermore, additional natural gas reserves may not be developed in commercial
quantities and in sufficient amounts to fill the capacities of each of our
pipeline systems.
In
addition, existing customers may not extend their contracts if the cost of
delivered natural gas from other producing regions into the markets served by
our pipeline systems is lower than the cost of natural gas delivered by our
pipeline systems. Our pipeline systems face increased competition from other
pipelines that provide access for our shippers to capacity from the U.S. Rocky
Mountain Region. The Rockies Express Pipeline owned by Rockies Express Pipeline
LLC is being constructed in two phases and the planned terminus is in
Clarington, Ohio. REX West is completed and is currently delivering gas to
interconnects in the Midwestern region. The full in-service of REX West in May
2008 has resulted in significant downward pressure on natural gas prices in the
Mid-continent Region, and is having a negative impact on demand for Northern
Border’s transport and may have an impact on Great Lakes in the
future.
REX East
is planned to extend from Audrain County, Missouri to Clarington in Monroe
County, Ohio. Once in-service, REX East should improve the competitive position
of Canadian supply with Mid-Continent sourced gas, potentially mitigating some
of the excess supply in the Mid-Continent market. REX East will compete in some
of Great Lakes’ markets, but will also potentially create demand for Great
Lakes’ transportation of natural gas from REX East seeking access to and from
storage locations in Michigan. It is now anticipated that the partial in-service
and full in-service of REX East will occur in the second and fourth quarters of
2009, respectively. Although
there can be no assurance on the timing or impact of REX East, we believe that
any positive impact on the market Northern Border serves will not occur
until 2010.
An
increase in competition in the key markets served by our pipeline systems could
arise from new ventures or expanded operations from existing competitors. Our
financial performance depends to a large extent on the capacity contracted on
our pipeline systems. Decreases in the volumes transported by our pipeline
systems, whether caused by supply or demand factors in the markets these
pipeline systems serve, competition or otherwise, can directly and adversely
affect our revenues and results of operations.
Our
pipeline systems may undertake expansion and build projects which involve
significant risks that could adversely affect our business. Additionally, the
Bison Project and the Pathfinder Project have inherently similar risks that may
impact their success and therefore the potential volumes to be delivered to
Northern Border.
Our
pipeline systems have expansion and new build projects planned or underway,
including Northern Border’s $18 million Des Plaines Project. Additionally,
expansion and new build projects, such as the Bison and/or Pathfinder Projects
that would potentially deliver gas to Northern Border, are subject to a variety
of factors outside their control, such as weather, natural disasters, delays in
obtaining key materials and difficulties in obtaining permits and rights-of-way
or other regulatory approvals, as well as the performance by third party
contractors may result in increased costs or delays in construction. Cost
overruns or delays in completing a project could result in reduced
transportation rates and liquidated damages to customers, as well as lost
revenue opportunities. In addition, we cannot be certain that, if completed,
these projects will perform in accordance with our expectations. Each of these
risks could have a material adverse effect on our results of operations and cash
flows.
If
our pipeline systems were to become subject to a material amount of entity level
taxation for state tax purposes, then our pipeline systems’ operating cash flow
and cash available for distribution to us and for other business needs would be
reduced.
Our
pipeline systems are partnerships or tax flow through entities, and as such they
generally have not been subject to income tax at the entity level. Several
states have either adopted or are evaluating a variety of ways to subject
partnerships to entity level taxation. For example, in the nine months ended
September 30, 2008, Great Lakes recorded a Michigan business tax of $4.2 million
relating to a new partnership level tax, of which the Partnership’s share of the
tax was $2.0 million. Imposition of such taxes on our pipeline systems will
reduce the cash available for distribution to us and for other business needs by
our pipeline systems.
Unitholders
will likely be subject to state and local taxes as a result of an investment in
units.
In
addition to federal income taxes, unitholders will likely be subject to other
taxes, including state and local taxes, unincorporated business taxes and
estate, inheritance or intangible taxes that are imposed by the various
jurisdictions in which we do business or own property. We may be required to
withhold income taxes with respect to income allocable or distributions made to
our unitholders. In addition, unitholders may be required to file state and
local income tax returns and pay state and local income taxes in some or all of
the jurisdictions in which we do business or own property and may be subject to
penalties for failure to comply with those requirements. It is the unitholders’
responsibility to file all required United States federal, state and local tax
returns. Counsel has not rendered an opinion on the state or local tax
consequences of an investment in us.
Item
6. Exhibits
No. Description
10.1
|
Membership
Interest Purchase Agreement as of August 28, 2008, by and between Northern
Border Pipeline Company and TransCanada Pipeline USA
Ltd.
|
10.2
|
First
Amendment to Amended and Restated Revolving Credit Agreement dated as of
July 31, 2008 between Northern Border Pipeline Company and the lenders
named therein.
|
31.1
|
Certification
of Principal Executive Officer pursuant to Section 302 of the
Sarbanes-Oxley Act
of 2002.
|
31.2
|
Certification
of Principal Financial Officer pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
|
32.1
|
Certification
of Principal Executive Officer pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
|
32.2
|
Certification
of Principal Financial Officer pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
|
SIGNATURES
Pursuant
to the requirements of the Securities and Exchange Act of 1934, the Registrant
has duly caused this report to be signed on its behalf by the undersigned
thereunto duly authorized.
|
TC
PipeLines, LP
|
|
(a
Delaware Limited Partnership)
|
|
By:
|
TC
PipeLines GP, Inc., its general partner
|
Date:
|
November
3, 2008
|
By:
|
/s/ Russell
K. Girling
Russell
K. Girling
Chairman,
Chief Executive Officer and Director
TC
PipeLines GP, Inc. (Principal Executive Officer)
|
Date:
|
November
3, 2008
|
By:
|
/s/ Amy W.
Leong
Amy
W. Leong
Controller
TC
PipeLines GP, Inc. (Principal Financial
Officer)
|