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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended SEPTEMBER 30, 2004
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from _______ to ________.
Commission File Number 1-12202
NORTHERN BORDER PARTNERS, L.P.
(Exact name of registrant as specified in its charter)
Delaware 93-1120873
- -------------------------------- --------------------------------
(State or other jurisdiction of (I.R.S. Employer Identification
incorporation or organization) Number)
13710 FNB Parkway
Omaha, Nebraska 68154-5200
- -------------------------------- --------------------------------
(Address of principal executive (Zip code)
offices)
(402) 492-7300
----------------------------------------------------
(Registrant's telephone number, including area code)
Not applicable
- --------------------------------------------------------------------------------
(Former name, address and former fiscal year, if changed since last report)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act). Yes [X] No [ ]
The number of common units outstanding as of November 1, 2004 was
46,397,214.
1 of 37
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
TABLE OF CONTENTS
Page No.
-------
PART I. FINANCIAL INFORMATION
ITEM 1. Financial Statements
Consolidated Statement of Income - Three Months Ended September 30,
2004 and 2003 and Nine Months Ended September 30, 2004 and 2003 3
Consolidated Statement of Comprehensive Income - Three Months Ended
September 30, 2004 and 2003 and Nine Months Ended September 30, 2004
and 2003 4
Consolidated Balance Sheet - September 30, 2004 and December 31, 2003 5
Consolidated Statement of Cash Flows - Nine Months Ended September
30, 2004 and 2003 6
Consolidated Statement of Changes in Partners' Equity - Nine Months
Ended September 30, 2004 7
Notes to Consolidated Financial Statements 8
ITEM 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations 14
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk 34
ITEM 4. Controls and Procedures 35
PART II. OTHER INFORMATION
ITEM 1. Legal Proceedings 36
ITEM 6. Exhibits 36
2
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF INCOME
(IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)
(UNAUDITED)
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
-------------------------- --------------------------
2004 2003 2004 2003
----------- ----------- ----------- -----------
OPERATING REVENUES $ 148,148 $ 138,008 $ 436,499 $ 410,545
----------- ----------- ----------- -----------
OPERATING EXPENSES
Product purchases 26,084 20,409 70,965 60,740
Operations and maintenance 27,246 30,682 85,896 89,115
Depreciation and amortization,
including impairment charges
of $219,080 in 2003 21,438 239,049 64,474 278,586
Taxes other than income 9,634 8,632 27,430 26,927
----------- ----------- ----------- -----------
Operating expenses 84,402 298,772 248,765 455,368
----------- ----------- ----------- -----------
OPERATING INCOME (LOSS) 63,746 (160,764) 187,734 (44,823)
----------- ----------- ----------- -----------
INTEREST EXPENSE 19,263 19,221 56,365 60,229
----------- ----------- ----------- -----------
OTHER INCOME (EXPENSE)
Equity earnings in
unconsolidated affiliates 3,914 4,485 13,879 16,408
Other income 1,017 4,329 2,875 5,724
Other expense (2,052) (174) (2,663) (1,177)
----------- ----------- ----------- -----------
Other income, net 2,879 8,640 14,091 20,955
----------- ----------- ----------- -----------
MINORITY INTERESTS IN NET INCOME 11,274 11,159 36,190 33,464
----------- ----------- ----------- -----------
INCOME (LOSS) FROM CONTINUING
OPERATIONS BEFORE INCOME TAXES 36,088 (182,504) 109,270 (117,561)
INCOME TAXES 1,376 1,068 4,678 5,099
----------- ----------- ----------- -----------
INCOME (LOSS) FROM CONTINUING
OPERATIONS 34,712 (183,572) 104,592 (122,660)
DISCONTINUED OPERATIONS, NET OF TAX -- (107) -- 4,369
CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE, NET OF TAX -- -- -- (643)
----------- ----------- ----------- -----------
NET INCOME (LOSS) TO PARTNERS $ 34,712 $ (183,679) $ 104,592 $ (118,934)
=========== =========== =========== ===========
CALCULATION OF LIMITED PARTNERS'
INTEREST IN NET INCOME (LOSS):
Net income (loss) to partners $ 34,712 $ (183,679) $ 104,592 $ (118,934)
Less: general partners' interest
in net income (loss) 2,685 (1,684) 8,062 3,369
----------- ----------- ----------- -----------
Limited partners' interest in
net income (loss) $ 32,027 $ (181,995) $ 96,530 $ (122,303)
=========== =========== =========== ===========
LIMITED PARTNERS' PER UNIT NET
INCOME (LOSS):
Income (loss) from continuing
operations $ 0.69 $ (3.92) $ 2.08 $ (2.80)
Discontinued operations, net of tax -- -- -- 0.09
Cumulative effect of change in
accounting principle, net of tax -- -- -- (0.01)
----------- ----------- ----------- -----------
Net income (loss) $ 0.69 $ (3.92) $ 2.08 $ (2.72)
=========== =========== =========== ===========
NUMBER OF UNITS USED IN COMPUTATION 46,397 46,397 46,397 45,027
=========== =========== =========== ===========
The accompanying notes are an integral part of these consolidated financial
statements.
3
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
(IN THOUSANDS)
(UNAUDITED)
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
----------------------- ------------------------
2004 2003 2004 2003
---------- ---------- ---------- ----------
Net income (loss) to partners $ 34,712 $ (183,679) $ 104,592 $ (118,934)
Other comprehensive income:
Change associated with current
period hedging transactions 446 3,214 1,636 (2,011)
Change associated with
current period foreign
currency translation 477 (146) (256) 1,654
---------- ---------- ---------- ----------
Total comprehensive income (loss) $ 35,635 $ (180,611) $ 105,972 $ (119,291)
========== ========== ========== ==========
The accompanying notes are an integral part of these consolidated financial
statements.
4
PART I. FINANCIAL INFORMATION (CONTINUED)
ITEM 1. FINANCIAL STATEMENTS (CONTINUED)
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(IN THOUSANDS)
(UNAUDITED)
SEPTEMBER 30, DECEMBER 31,
2004 2003
------------- -------------
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 40,279 $ 35,895
Accounts receivable, net of allowance for
doubtful accounts of $10,597 and $12,444 at
September 30, 2004 and December 31, 2003,
respectively 72,404 61,503
Materials and supplies, at cost 6,366 7,826
Prepaid expenses 6,334 6,726
Other 1,780 2,245
------------- -------------
Total current assets 127,163 114,195
------------- -------------
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment 2,924,680 2,912,055
Less: Accumulated provision for
depreciation and amortization 982,311 919,951
------------- -------------
Property, plant and equipment, net 1,942,369 1,992,104
------------- -------------
INVESTMENTS AND OTHER ASSETS
Investment in unconsolidated affiliates 272,255 268,166
Goodwill 152,782 152,782
Derivative financial instruments 14,629 19,553
Other 27,766 23,783
------------- -------------
Total investments and other assets 467,432 464,284
------------- -------------
Total assets $ 2,536,964 $ 2,570,583
============= =============
LIABILITIES AND PARTNERS' EQUITY
CURRENT LIABILITIES
Current maturities of long-term debt $ 17,898 $ 7,740
Accounts payable 49,681 46,532
Accrued taxes other than income 32,362 33,708
Accrued interest 19,584 13,206
Derivative financial instruments 3,037 5,736
------------- -------------
Total current liabilities 122,562 106,922
------------- -------------
LONG-TERM DEBT, NET OF CURRENT MATURITIES 1,345,290 1,408,246
------------- -------------
MINORITY INTERESTS IN PARTNERS' EQUITY 268,773 240,731
------------- -------------
RESERVES AND DEFERRED CREDITS
Deferred income taxes 5,466 2,898
Other 8,046 11,213
------------- -------------
Total reserves and deferred credits 13,512 14,111
------------- -------------
COMMITMENTS AND CONTINGENCIES (Note 5)
PARTNERS' EQUITY
General partners 15,600 15,902
Common units (46,397,214 units issued and
outstanding at September 30, 2004
and December 31, 2003) 764,371 779,195
Accumulated other comprehensive income 6,856 5,476
------------- -------------
Total partners' equity 786,827 800,573
------------- -------------
Total liabilities and partners' equity $ 2,536,964 $ 2,570,583
============= =============
The accompanying notes are an integral part of these consolidated financial
statements.
5
PART I. FINANCIAL INFORMATION (CONTINUED)
ITEM 1. FINANCIAL STATEMENTS (CONTINUED)
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
(IN THOUSANDS)
(UNAUDITED)
NINE MONTHS ENDED
SEPTEMBER 30,
--------------------------
2004 2003
----------- -----------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) to partners $ 104,592 $ (118,934)
----------- -----------
Adjustments to reconcile net income (loss) to partners
to net cash provided by operating activities:
Depreciation and amortization, including impairment
charges of $219,080 in 2003 64,753 279,544
Minority interests in net income 36,190 33,464
Provision for regulatory refunds -- 261
Regulatory refunds paid -- (10,261)
Other reserves and deferred credits (3,165) 1,670
Cumulative effect of change in accounting principle -- 643
Equity earnings in unconsolidated affiliates (13,879) (16,519)
Distributions received from unconsolidated affiliates 10,565 16,025
Changes in components of working capital,
net of the effect of the acquired businesses 2,522 (9,180)
Non-cash gains from derivative financial instruments (275) (254)
Gain on sale of gathering and processing assets (3,427) (4,872)
Other (5,914) (2,335)
----------- -----------
Total adjustments 87,370 288,186
----------- -----------
Net cash provided by operating activities 191,962 169,252
----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in unconsolidated affiliates -- (3,510)
Acquisitions of businesses -- (119,331)
Sale of gathering and processing assets 1,655 40,250
Capital expenditures for property, plant
and equipment (17,933) (14,971)
----------- -----------
Net cash used in investing activities (16,278) (97,562)
----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Cash distributions to Unitholders and
General Partners (119,718) (115,267)
Distributions to Minority Interests (46,799) (33,907)
Contributions from Minority Interests 39,000 --
Issuance of partnership interests, net -- 102,408
Issuance of debt 100,000 270,000
Retirement of debt (143,783) (313,229)
Proceeds upon termination of derivatives -- 12,250
----------- -----------
Net cash used in financing activities (171,300) (77,745)
----------- -----------
NET CHANGE IN CASH AND CASH EQUIVALENTS 4,384 (6,055)
Cash and cash equivalents-beginning of period 35,895 34,689
----------- -----------
Cash and cash equivalents-end of period $ 40,279 $ 28,634
=========== ===========
Supplemental Disclosures of Cash Flow Information:
Cash paid for:
Interest (net of amount capitalized) $ 53,323 $ 61,921
=========== ===========
Changes in components of working capital:
Accounts receivable $ (4,260) $ 967
Materials and supplies, prepaid expenses and other 975 (1,114)
Accounts payable 2,220 (11,047)
Accrued taxes other than income (1,346) 553
Accrued interest 4,933 1,461
----------- -----------
Total $ 2,522 $ (9,180)
=========== ===========
The accompanying notes are an integral part of these consolidated financial
statements.
6
PART I. FINANCIAL INFORMATION (CONTINUED)
ITEM 1. FINANCIAL STATEMENTS (CONTINUED)
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY
(IN THOUSANDS)
(UNAUDITED)
ACCUMULATED
OTHER TOTAL
GENERAL COMMON COMPREHENSIVE PARTNERS'
PARTNERS UNITS INCOME EQUITY
------------- ------------- ------------- -------------
Balance at December 31, 2003 $ 15,902 $ 779,195 $ 5,476 $ 800,573
Net income to partners 8,062 96,530 -- 104,592
Change associated with current
period hedging transactions -- -- 1,636 1,636
Change associated with current
period foreign currency translation -- -- (256) (256)
Distributions to partners (8,364) (111,354) -- (119,718)
------------- ------------- ------------- -------------
Balance at September 30, 2004 $ 15,600 $ 764,371 $ 6,856 $ 786,827
============= ============= ============= =============
The accompanying notes are an integral part of these consolidated financial
statements.
7
PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 1. FINANCIAL STATEMENTS - (CONTINUED)
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. BASIS OF PRESENTATION
The consolidated financial statements included herein have been prepared
by Northern Border Partners, L.P. (the "Partnership") without audit pursuant to
the rules and regulations of the Securities and Exchange Commission. The
consolidated financial statements reflect all normal and recurring adjustments
that are, in the opinion of management, necessary for a fair presentation of the
financial results for the interim periods. Certain information and notes
normally included in financial statements prepared in accordance with accounting
principles generally accepted in the United States of America ("GAAP") have been
condensed or omitted pursuant to such rules and regulations. However, the
Partnership believes that the disclosures are adequate to make the information
presented not misleading. These consolidated financial statements should be read
in conjunction with the consolidated financial statements and the notes thereto
included in the Partnership's Annual Report on Form 10-K for the year ended
December 31, 2003.
The preparation of financial statements in conformity with GAAP requires
management to make assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those estimates.
The Partnership owns a 70% general partner interest in Northern Border
Pipeline Company. Crestone Energy Ventures, L.L.C.; Bear Paw Energy, L.L.C.;
Border Midstream Services, Ltd.; Midwestern Gas Transmission Company; Viking Gas
Transmission Company; and Black Mesa Pipeline, Inc. are wholly owned
subsidiaries of the Partnership. The Partnership also owns a 49% common
membership interest and a 100% preferred A share interest in Bighorn Gas
Gathering, L.L.C.; a 33% interest in Fort Union Gas Gathering, L.L.C.; a 35%
interest in Lost Creek Gathering, L.L.C.; a 36% interest in the Gregg Lake/Obed
Pipeline; and a 33% interest in Guardian Pipeline, L.L.C.
2. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
The Partnership uses financial instruments in the management of its
interest rate and commodity price exposure. A control environment has been
established which includes policies and procedures for risk assessment and the
approval, reporting and monitoring of financial instrument activities. The
Partnership does not use these instruments for trading purposes.
The Partnership records in accumulated other comprehensive income amounts
related to terminated interest rate swap agreements for cash flow hedges with
such amounts amortized to interest expense over the term of the hedged debt.
During the three months and nine months ended September 30, 2004, the
Partnership amortized approximately $0.5 million and $1.6 million, respectively,
related to the terminated interest rate swap agreements, as a reduction to
interest expense from accumulated other comprehensive income and expects to
amortize a comparable amount in the fourth quarter of 2004.
8
PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 1. FINANCIAL STATEMENTS - (CONTINUED)
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Northern Border Pipeline has outstanding interest rate swap agreements
with notional amounts totaling $225 million that expire in May 2007. Under the
interest rate swap agreements, Northern Border Pipeline makes payments to
counterparties at variable rates based on the London Interbank Offered Rate and
in return receives payments based on a 6.25% fixed rate. At September 30, 2004,
the average effective interest rate on Northern Border Pipeline's interest rate
swap agreements was 2.46%.
The Partnership has outstanding interest rate swap agreements with
notional amounts totaling $150 million that expire in March 2011. Under the
interest rate swap agreements, the Partnership makes payments to counterparties
at variable rates based on the London Interbank Offered Rate and in return
receives payments based on a 7.10% fixed rate. At September 30, 2004, the
average effective interest rate on the Partnership's interest rate swap
agreements was 4.61%.
Both the Partnership's and Northern Border Pipeline's interest rate swap
agreements have been designated as fair value hedges as they were entered into
to hedge the fluctuations in the market value of the senior notes issued by the
Partnership in 2001 and by Northern Border Pipeline in 2002. The accompanying
consolidated balance sheet at September 30, 2004, reflects derivative financial
instrument assets of approximately $14.6 million with a corresponding increase
in long-term debt related to the Partnership's and Northern Border Pipeline's
fair value hedges.
The Partnership records in long-term debt amounts received or paid related
to terminated or amended interest rate swap agreements for fair value hedges
with such amounts amortized to interest expense over the remaining life of the
interest rate swap agreement. The Partnership amortized approximately $0.8
million and $2.5 million as a reduction to interest expense in the three months
and nine months ended September 30, 2004, respectively, and expects to amortize
a comparable amount in the fourth quarter of 2004.
Bear Paw Energy periodically enters into commodity derivatives contracts.
Bear Paw Energy primarily utilizes price swaps and collars, which have been
designated as cash flow hedges, to hedge its exposure to gas and natural gas
liquid price volatility. During the three months and nine months ended September
30, 2004, Bear Paw Energy recognized losses of $2.8 million and $6.2 million,
respectively, from the settlement of derivative contracts. At September 30,
2004, Bear Paw Energy reflected a non-cash loss of approximately $3.0 million in
derivative financial instruments with a corresponding reduction of $2.8 million
in accumulated other comprehensive income. For the fourth quarter of 2004, if
prices remain at current levels, Bear Paw Energy expects to reclassify
approximately $2.8 million from accumulated other comprehensive income as a
reduction to operating revenues. However, this reduction would be offset with
increased operating revenues due to the higher prices assumed.
9
PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 1. FINANCIAL STATEMENTS - (CONTINUED)
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
3. BUSINESS SEGMENT INFORMATION
The Partnership's business is divided into three reportable segments,
defined as components of the enterprise about which financial information is
available and evaluated regularly by the Partnership's executive management and
the Partnership Policy Committee in deciding how to allocate resources to an
individual segment and in assessing performance of the segment.
The Partnership's reportable segments are strategic business units that
offer different services. Each is managed separately because each business
requires different marketing strategies. The Partnership evaluates performance
based on EBITDA, earnings before interest, taxes, depreciation and amortization
less the allowance for equity funds used during construction ("AFUDC").
Management uses EBITDA to compare the financial performance of its segments and
to internally manage those business segments and believes that EBITDA is a good
indicator of each segment's performance. EBITDA should not be considered an
alternative to, or more meaningful than, net income or cash flow as determined
in accordance with GAAP. EBITDA calculations may vary from company to company,
so the Partnership's computation of EBITDA may not be comparable to a similarly
titled measure of another company. The following table shows a reconciliation of
net income (loss) to EBITDA:
RECONCILIATION OF NET INCOME (LOSS) TO EBITDA
Natural
Interstate Gas
Natural Gathering
Gas and Coal
(In thousands) Pipelines Processing Slurry Other(a) Total
- --------------------- ------------ ------------- ------------ ------------- ------------
THREE MONTHS ENDED
SEPTEMBER 30, 2004
Net income (loss) $ 30,639 $ 14,531 $ 900 ($ 11,358) $ 34,712
Minority interest 11,274 -- -- -- 11,274
Interest expense, net 10,688 85 -- 8,490 19,263
Depreciation and
amortization 16,826 3,850 858 -- 21,534
Income tax 1,088 105 183 -- 1,376
AFUDC (27) -- -- -- (27)
------------ ------------- ------------ ------------- ------------
EBITDA $ 70,488 $ 18,571 $ 1,941 ($ 2,868) $ 88,132
============ ============= ============ ============= ============
THREE MONTHS ENDED
SEPTEMBER 30, 2003
Net income (loss) $ 30,154 ($ 206,695) $ 1,534 ($ 8,672) ($ 183,679)
Minority interest 11,159 -- -- -- 11,159
Interest expense, net 11,679 140 10 7,392 19,221
Depreciation and
amortization (b) 16,457 222,222 462 12 239,153
Income tax 746 -- 323 16 1,085
AFUDC (88) -- -- -- (88)
------------ ------------- ------------ ------------- ------------
EBITDA $ 70,107 $ 15,667 $ 2,329 ($ 1,252) $ 86,851
============ ============= ============ ============= ============
10
PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 1. FINANCIAL STATEMENTS - (CONTINUED)
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
RECONCILIATION OF NET INCOME (LOSS) TO EBITDA
Natural
Interstate Gas
Natural Gathering
Gas and Coal
(In thousands) Pipelines Processing Slurry Other(a) Total
- ---------------------- ------------ ------------- ------------ ------------- -------------
NINE MONTHS ENDED
SEPTEMBER 30, 2004
Net income (loss) $ 98,084 $ 34,162 $ 2,439 ($ 30,093) $ 104,592
Minority interest 36,190 -- -- -- 36,190
Interest expense, net 32,132 299 11 23,923 56,365
Depreciation and
amortization 50,310 11,449 2,994 -- 64,753
Income tax 3,725 598 355 -- 4,678
AFUDC (84) -- -- -- (84)
------------ ------------- ------------ ------------- -------------
EBITDA $ 220,357 $ 46,508 $ 5,799 ($ 6,170) $ 266,494
============ ============= ============ ============= =============
NINE MONTHS ENDED
SEPTEMBER 30, 2003
Net income (loss) $ 89,583 ($ 187,564) $ 2,817 ($ 23,770) ($ 118,934)
Cumulative effect of
change in accounting
principle, net of tax -- -- 434 209 643
Minority interest 33,464 -- -- -- 33,464
Interest expense, net 36,475 483 26 23,245 60,229
Depreciation and
amortization (b) 49,142 228,455 1,263 684 279,544
Income tax 4,259 -- 840 (639) 4,460
AFUDC (238) -- -- -- (238)
------------ ------------- ------------ ------------- -------------
EBITDA $ 212,685 $ 41,374 $ 5,380 $ (271) $ 259,168
============ ============= ============ ============= =============
BUSINESS SEGMENT DATA
Natural
Interstate Gas
Natural Gathering
Gas and Coal
(In thousands) Pipelines Processing Slurry Other(a) Total
- ----------------------- ------------ ------------ ------------ ------------ ------------
THREE MONTHS ENDED
SEPTEMBER 30, 2004
Revenues from
external customers $ 95,007 $ 47,600 $ 5,541 $ -- $ 148,148
Operating income (loss) 53,532 11,190 1,063 (2,039) 63,746
THREE MONTHS ENDED
SEPTEMBER 30, 2003
Revenues from
external customers $ 93,465 $ 39,033 $ 5,510 $ -- $ 138,008
Operating income (loss) 52,911 (214,210) 1,813 (1,278) (160,764)
11
PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 1. FINANCIAL STATEMENTS - (CONTINUED)
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
BUSINESS SEGMENT DATA
Natural
Interstate Gas
Natural Gathering
Gas and Coal
(In thousands) Pipelines Processing Slurry Other(a) Total
- ----------------------- ------------ ------------ ------------ ------------ ------------
NINE MONTHS ENDED
SEPTEMBER 30, 2004
Revenues from
external customers $ 287,150 $ 133,028 $ 16,321 $ -- $ 436,499
Operating income (loss) 168,773 21,983 2,779 (5,801) 187,734
NINE MONTHS ENDED
SEPTEMBER 30, 2003
Revenues from
external customers $ 279,073 $ 115,442 $ 16,030 $ -- $ 410,545
Operating income (loss) 161,604 (205,787) 4,079 (4,719) (44,823)
Total assets by segment are as follows:
September 30, December 31,
(In thousands) 2004 2003
- ------------------------------------ ------------- -------------
Interstate Natural Gas Pipelines $ 1,934,078 $ 1,970,807
Natural Gas Gathering and Processing 567,921 565,465
Coal Slurry 19,982 21,319
Other (a) 14,983 12,992
------------- -------------
Total Assets $ 2,536,964 $ 2,570,583
============= =============
(a) Includes other items not allocable to segments.
(b) Natural gas gathering and processing results includes goodwill and asset
impairment charges of $219,080.
4. NET INCOME PER UNIT
Net income per unit is computed by dividing net income, after deduction of
the general partners' allocation, by the weighted average number of outstanding
common units. The general partners' allocation is equal to an amount based upon
their collective 2% general partner interest adjusted for incentive
distributions. The distribution to partners amount shown on the accompanying
consolidated statement of changes in partners' equity includes incentive
distributions to the general partners of approximately $6.0 million.
On October 19, 2004, the Partnership declared a cash distribution of $0.80
per unit ($3.20 per unit on an annualized basis) for the quarter ended September
30, 2004. The distribution is payable on November 12, 2004, to unitholders of
record at October 29, 2004.
12
PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 1. FINANCIAL STATEMENTS - (CONCLUDED)
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
5. COMMITMENTS AND CONTINGENCIES
On July 31, 2001, the Assiniboine and Sioux Tribes of the Fort Peck Indian
Reservation ("Tribes") filed a lawsuit in Tribal Court against Northern Border
Pipeline to collect more than $3 million in back taxes, together with interest
and penalties. The lawsuit related to a utilities tax on certain of Northern
Border Pipeline's properties within the Fort Peck Indian Reservation. The Tribes
and Northern Border Pipeline, through a mediation process, held settlement
discussions and reached a settlement on pipeline right-of-way lease and taxation
issues documented through an Option Agreement and Expanded Facilities Lease
("Agreement"). Through the terms of the Agreement, the settlement grants to
Northern Border Pipeline, among other things: (i) an option to renew the
pipeline right-of-way lease upon agreed terms and conditions on or before April
1, 2011 for a term of 25 years with a renewal right for an additional 25 years;
(ii) a right to use additional tribal lands for expanded facilities; and (iii)
release and satisfaction of all tribal taxes against Northern Border Pipeline.
Upon execution of the Agreement, in consideration of this option and other
benefits, Northern Border Pipeline paid a lump sum amount of $7.4 million and
will make additional annual option payments of approximately $1.5 million
thereafter through March 31, 2011. Of the amount paid in 2004, $1.0 million was
determined to be a settlement of previously accrued property taxes. The
remainder has been recorded in other assets on the consolidated balance sheet.
Northern Border Pipeline intends to seek regulatory recovery of the costs
resulting from the settlement.
Various legal actions that have arisen in the ordinary course of business
are pending. The Partnership believes that the resolution of these issues will
not have a material adverse impact on the Partnership's results of operations or
financial position.
6. ACCOUNTING PRONOUNCEMENTS
In December 2003, the Financial Accounting Standards Board issued
Interpretation No. ("FIN") 46 (revised December 2003), "Consolidation of
Variable Interest Entities," which addresses how a business enterprise should
evaluate whether it has a controlling financial interest in an entity through
means other than voting rights and accordingly should consolidate the entity;
such entities are known as variable interest entities. The Partnership adopted
FIN 46 as of January 1, 2004. In connection with the adoption of FIN 46, the
Partnership evaluated its investments in Bighorn Gas Gathering, Fort Union Gas
Gathering, Lost Creek Gathering and Guardian Pipeline and determined that these
entities are appropriately accounted for as equity method investments. The
adoption of FIN 46 did not have an effect on the Partnership's financial
position, results of operations or cash flows.
13
PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
Management's discussion and analysis of financial condition and results of
operations is based on the Consolidated Financial Statements of Northern Border
Partners, L.P. (the "Partnership"). The Consolidated Financial Statements are
prepared in accordance with accounting principles generally accepted in the
United States of America. You should read the following discussion and analysis
in conjunction with the Consolidated Financial Statements included elsewhere in
this report.
OVERVIEW
The Partnership's businesses fall into three major business segments:
- the interstate natural gas pipeline segment, which comprises
approximately 77% of the Partnership's assets;
- the natural gas gathering and processing segment, which comprises
approximately 22% of the Partnership's assets; and
- the coal slurry pipeline segment, which comprises approximately 1%
of the Partnership's assets.
There are several major business drivers that have an impact on the
Partnership's business. These factors are discussed in the "Management's
Discussion and Analysis of Financial Condition and Results of Operations -
Overview" in the Partnership's Annual Report on Form 10-K for the year ended
December 31, 2003.
Interstate Natural Gas Pipelines
The interstate natural gas pipelines segment includes the operations of
Northern Border Pipeline Company, Midwestern Gas Transmission Company, Viking
Gas Transmission Company and a one-third interest in Guardian Pipeline, L.L.C.
As reported previously, firm transportation contracts covering 778
million cubic feet per day ("MMcf/d"), were scheduled to expire late in 2004. By
the end of the second quarter, Northern Border Pipeline successfully extended
contracts for approximately 18% of that capacity with existing shippers at
maximum transportation rates for terms of at least one year. During the third
quarter, Northern Border Pipeline recontracted all but approximately 1% of its
capacity at maximum rates for terms of five to six months. With contracts
scheduled to expire through May 2005, approximately 800 MMcf/d or 30% of
capacity will become available on the pipeline system from Port of Morgan,
Montana to the Ventura, Iowa delivery point. The Partnership believes Northern
Border Pipeline will continue to provide economic value for gas flows from
Western Canada over the long-term and, therefore, will maintain its relatively
high utilization levels. However, in any given month, current conditions of
weather and storage in supply and market areas may affect the utilization level.
Northern Border Pipeline's objective is to recontract the remaining
pipeline capacity at maximum transportation rates for the longest terms
possible. Because the forward natural gas basis differentials between Western
Canada and Northern Border Pipeline's market centers continue to be less than
the total transportation cost at maximum tariff rates, Northern Border Pipeline
may again sell a significant portion of this capacity on a short-term basis. In
14
PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (CONTINUED)
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
addition, this could result in lower revenues in some months if the forward
basis differentials do not support maximum rates. The Partnership believes a
reduction in expected 2005 net income and cash flow for Northern Border Pipeline
of $5 million to $10 million is possible. The impact on net income and cash flow
may vary outside this range depending on actual natural gas basis differentials
experienced during the year.
On September 23, 2004, Northern Border Pipeline announced it had received
commitments from shippers sufficient to support a proposed expansion of the
pipeline system into the Chicago market area. The "Chicago Expansion III"
project, with an estimated 130 MMcf/d of capacity, would involve construction of
a new compressor station and minor modifications to other compressor stations,
and is estimated to cost approximately $20 million. The projected in-service
date is April 1, 2006. Approval of this project by the Federal Energy Regulatory
Commission ("FERC") is required and Northern Border Pipeline anticipates filing
a certificate application with the FERC in January 2005.
On Midwestern Gas Transmission, the Partnership announced on August 17,
2004 that it had finalized the necessary contractual commitment to proceed with
the Eastern Extension Project, which involves the construction of approximately
30 miles of 16-inch diameter pipeline, with a capacity of approximately 120
MMcf/d, from Portland, Tennessee to planned interconnects with Columbia Gulf
Transmission Company and East Tennessee Pipeline Company. The project is
supported by a precedent agreement with Piedmont Natural Gas Company, a local
distribution company, for approximately 120 MMcf/d for a term of 15 years.
Pending the receipt of regulatory and other required approvals, the proposed
in-service date for the project is November 2006 and project costs are estimated
at approximately $22 million to $25 million.
During 2004, Viking Gas Transmission extended contracts with existing
shippers for terms ranging from 3 to 5 years. These contracts account for 49
MMcf/d of capacity on Viking and results in Viking being 100% contracted until
November 2005. Viking's challenge is the continued recontracting after October
2005 at existing contract levels and transportation rates at the Marshfield,
Wisconsin delivery point as a result of the FERC approval of ANR Pipeline
Company's North Leg Project, which is expected to lessen ANR's pipeline system
dependence on deliveries from Viking at Marshfield. This project could cause
greater price competition between Canadian gas transported on Viking to ANR
versus other supply sources. ANR's project is scheduled to go into service in
2005. Additionally, the Partnership expects other projects may be proposed to
further compete for these markets.
Natural Gas Gathering and Processing
The natural gas gathering and processing segment includes the operations
of Bear Paw Energy, L.L.C. and Crestone Energy Ventures, L.L.C. in the United
States, as well as the operations of Border Midstream Services, Ltd., the
Partnership's Canadian company that owns an interest in gathering assets in
Alberta, Canada. In addition, the Partnership's equity interests in Bighorn Gas
Gathering, L.L.C., Fort Union Gas Gathering, L.L.C. and Lost Creek Gathering,
L.L.C. are included in this segment.
15
PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (CONTINUED)
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
As a result of strong drilling and development by Bear Paw Energy's
customers in the Williston Basin, Bear Paw Energy has selectively expanded its
facilities and expects moderate growth in this area. The 5 MMcf/d expansion of
the Marmarth plant has been in full operation for two quarters. The project
enables the plant to produce a higher grade of product by controlling the
maximum ethane-propane mixture. Also, Bear Paw Energy has begun construction
activities to expand the northwest portion of its system to accommodate
additional volumes in the Bakken Oil Play. It is anticipated that an additional
3.5 MMcf/d will be processed by the Grasslands plant in the first quarter of
2005.
In the Partnership's wholly-owned gathering assets in the Powder River
Basin, gathering volumes in the third quarter of 2004 have increased 11% and 6%
over volumes gathered in the first quarter 2004 and second quarter,
respectively. For 2004, with the modest growth in drilling activity and with the
smaller than anticipated well production declines, the Partnership now expects
2004 average daily volumes gathered on its wholly-owned assets to remain flat to
2003. Efforts continue in the renegotiations of certain contracts to mitigate
volumetric risk and to reduce operation and maintenance expenses. Redeployment
and disposition of unused compression is continuing to be pursued and has
resulted in a third quarter 2004 gain on sale of $0.7 million. Certain
non-strategic Powder River assets were also sold during the third quarter 2004
for $7.0 million, which resulted in a gain on sale of $2.5 million.
Crestone Energy Ventures holds a 49% common membership interest and a 100%
preferred "A" share interest in Bighorn Gas Gathering. Crestone Energy Ventures
had been engaged in arbitration regarding the determination of 2001 system well
connections and corresponding Preferred "A" payments. The arbitration hearing
has been concluded, with the decision having no effect on the Partnership's 2004
financial results.
Border Midstream Services owns an undivided minority interest in the Gregg
Lake/Obed Pipeline located in Alberta, Canada. Central Alberta Midstream is the
holder of the remaining undivided interest and the operator of the pipeline. In
July 2004, Border Midstream Services was informed by Central Alberta Midstream
that the payout based upon the original construction costs of the Gregg Lake
portion of the pipeline had occurred. As a result, Border Midstream Services now
receives 36% of the distributions, which is equal to its ownership interest in
the entire Gregg Lake/Obed Pipeline. Border Midstream Services had previously
received 63% of the cash distributions. This reduction in distributions is
expected to be approximately $0.5 million per quarter. In October, Central
Alberta Midstream charged Border Midstream Services for additional adjustments
related to when the payout date of the original construction costs had occurred
and operating fee equalizations for the period 2000-2003. To date, Border
Midstream Services has not received sufficient information to support the
adjustments. However, the impact of any adjustment is not expected to be
material to the Partnership's results of operations or cash flows.
16
PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (CONTINUED)
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
Coal Slurry Pipeline
This segment includes Black Mesa Pipeline Company. As previously reported,
a new water source is one of several issues that must be resolved regarding the
future of the Mohave Generating Station and the Black Mesa pipeline. A
memorandum of understanding regarding the evaluation of a new water source has
been negotiated by the parties. A new water source has been identified and work
is underway to complete the necessary environmental and technical studies. The
California Public Utility Commission ("CPUC") held hearings to discuss the
issues surrounding the future of the Mohave Generating Station and the Black
Mesa pipeline. On October 20, 2004, the Administrative Law Judge ("ALJ") issued
a draft order in this matter. As proposed, the decision authorizes Southern
California Edison ("SCE"), who is a 56% owner of the Mohave Generating Station,
among other things, to make the necessary and appropriate expenditures for
critical path investments, including the new aquifer study and feasibility
studies for alternatives to the continuation of the coal-fired plant, and
directs the parties to continue working on resolution of the essential water and
coal issues. The next step is for the CPUC to approve, in whole or in part the
draft order, which is expected to take at least two to three months. Should the
order and resolution of the issues result in a decision to move forward, it
appears likely that there will be a temporary shutdown of the Mohave Generating
Station and the Black Mesa pipeline from 2006-2009. The Partnership anticipates
that the capital expenditures for the Black Mesa refurbishment project will be
in the range of $175 million to $200 million, which will be supported by
revenues from a new transportation contract. Under certain circumstances upon
the renewal of the transportation contract, the Partnership has a contingent
obligation to issue common units to prior owners of interest in Black Mesa
Pipeline. If this obligation is triggered, approximately 70,000 to 75,000 common
units would be issued. If efforts to resolve the issues surrounding the Mohave
Generating Station are not successful and it is permanently closed, it would
benecessary to shut down the Black Mesa pipeline in 2006.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
Certain amounts included in or affecting the Partnership's Consolidated
Financial Statements and related disclosures must be estimated, requiring it to
make certain assumptions with respect to values or conditions that cannot be
known with certainty at the time the financial statements are prepared. The
preparation of financial statements in conformity with accounting principles
generally accepted in the United States of America requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those estimates.
Key estimates used by the Partnership's management include the economic useful
lives of its assets used to determine depreciation and amortization, the fair
values used to determine possible asset impairment charges, the fair values used
to record derivative assets and liabilities, expense accruals, and the fair
values of assets acquired. Any effects on the Partnership's business, financial
position or results of operations resulting from revisions to these estimates
are recorded in the period in which the facts that give rise to the revision
become known.
17
PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (CONTINUED)
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
The Partnership's significant accounting policies are summarized in Note 2
- - Notes to Consolidated Financial Statements included in the Partnership's
Annual Report on Form 10-K for the year ended December 31, 2003. Certain of the
Partnership's accounting policies are of more significance in its financial
statement preparation process than others.
The interstate natural gas pipelines' accounting policies conform to
Statement of Financial Accounting Standards ("SFAS") No. 71, "Accounting for the
Effects of Certain Types of Regulation." Accordingly, certain assets that result
from the regulated ratemaking process are recorded that would not be recorded
under accounting principles generally accepted in the United States of America
for nonregulated entities. The Partnership continually assesses whether the
future recovery of the regulatory assets is probable by considering such factors
as regulatory changes and the impact of competition. If future recovery ceases
to be probable, the Partnership would be required to write-off the regulatory
assets at that time. At September 30, 2004, the Partnership has recorded
regulatory assets of $8.0 million, which are being recovered from the pipelines'
shippers over varying periods of time.
The Partnership's long-lived assets are stated at original cost. The
Partnership must use estimates in determining the economic useful lives of those
assets. Useful lives are based on historical experience and are adjusted when
changes in planned use, technological advances or other factors show that a
different life would be more appropriate. The depreciation rate used for utility
property is an integral part of the interstate pipelines' FERC tariffs. Any
revisions to the estimated economic useful lives of the Partnership's assets
will change its depreciation and amortization expense prospectively. For utility
property, no retirement gain or loss is included in income except in the case of
retirements or sales of entire operating units. The original cost of utility
property retired is charged to accumulated depreciation and amortization, net of
salvage and cost of removal.
The Partnership reviews long-lived assets for impairment in accordance
with SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived
Assets." Long-lived assets are reviewed for impairment whenever events or
changes in circumstances indicate that the carrying amount of an asset may not
be recoverable. Recoverability of the carrying amount of assets is measured by a
comparison of the carrying amount of the asset to future net cash flows expected
to be generated by the asset. Estimates of future net cash flows include
anticipated future revenues, expected future operating costs and other
estimates. If such assets are considered to be impaired, the impairment to be
recognized is measured by the amount by which the carrying amount of the assets
exceeds the fair value of the assets.
The Partnership accounts for its goodwill in accordance with SFAS No. 142,
"Goodwill and Other Intangible Assets." The Partnership has selected the fourth
quarter for the performance of its annual impairment testing.
The Partnership's accounting for financial instruments is in accordance
with SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities," which requires that every derivative instrument be recorded on the
balance sheet as either an asset or liability measured at its fair value. The
18
PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (CONTINUED)
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
statement requires that changes in the derivative's fair value be recognized
currently in earnings unless specific hedge accounting criteria are met. Special
accounting for qualifying hedges allows a derivative's gains and losses to
offset related results on the hedged item in the income statement. At September
30, 2004, the consolidated balance sheet included assets from derivative
financial instruments of $14.6 million and liabilities from derivative financial
instruments of $3.0 million.
For the interstate natural gas pipelines, operating revenues are derived
from agreements for the receipt and delivery of gas at points along the pipeline
system as specified in each shipper's individual transportation contract.
Revenues are recognized based upon contracted capacity and actual volumes
transported under transportation service agreements. For the gas gathering and
processing businesses, operating revenue is recorded when gas is processed in or
transported through company facilities. For the coal slurry pipeline, operating
revenue is recognized based on a contracted demand payment, actual tons
transported and for direct reimbursement of certain other expenses.
RESULTS OF OPERATIONS
The Partnership's income from continuing operations was $34.7 million in
the third quarter of 2004 or $0.69 per unit as compared to a loss from
continuing operations of ($183.6) million in the third quarter of 2003 or
$(3.92) per unit. The loss in 2003 was a result of impairment charges totaling
$219.1 million for the Partnership's natural gas gathering and processing
business segment. Excluding the impairment charges, income from continuing
operations decreased $0.8 million in 2004 as compared to 2003.
The Partnership's income from continuing operations was $104.6 million in
the nine months ended September 30, 2004, or $2.08 per unit as compared to a
loss from continuing operations of $(122.7) million in the nine months ended
September 30, 2003, or $(2.80) per unit. The loss in 2003 was a result of
impairment charges totaling $219.1 million for the Partnership's natural gas
gathering and processing business segment. Excluding the impairment charges,
income from continuing operations increased $8.2 million in 2004 as compared to
2003. The $8.2 million increase is primarily due to an $8.5 million increase in
income from the interstate natural gas pipelines segment.
In June 2003, the Partnership sold its Gladys and Mazeppa processing
plants located in Alberta, Canada. The operating results for these plants and
their sale are classified as discontinued operations. The Partnership's
consolidated income statement reflects discontinued operations of $4.4 million
in the nine months ended September 30, 2003, which include an after-tax gain of
$4.9 million on the sale of the Gladys and Mazeppa processing plants. The
Partnership's consolidated income statement for the nine months ended September
30, 2003, also reflects a reduction to net income of $0.6 million due to a
cumulative effect of change in accounting principle, which resulted from
adopting SFAS No. 143, "Accounting for Asset Retirement Obligations."
19
PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (CONTINUED)
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
The following table summarizes financial and other information by business
segment for the three and nine months ended September 30, 2004 and 2003 (in
thousands):
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------------- --------------------------
2004 2003 2004 2003
----------- ----------- ----------- -----------
Operating revenues:
Interstate Natural Gas Pipelines $ 95,007 $ 93,465 $ 287,150 $ 279,073
Natural Gas Gathering and Processing 47,600 39,033 133,028 115,442
Coal Slurry 5,541 5,510 16,321 16,030
----------- ----------- ----------- -----------
Total operating revenues 148,148 138,008 436,499 410,545
----------- ----------- ----------- -----------
Operating income (loss):
Interstate Natural Gas Pipelines 53,532 52,911 168,773 161,604
Natural Gas Gathering and Processing 11,190 (214,210) 21,983 (205,787)
Coal Slurry 1,063 1,813 2,779 4,079
Other (2,039) (1,278) (5,801) (4,719)
----------- ----------- ----------- -----------
Total operating income (loss) 63,746 (160,764) 187,734 (44,823)
----------- ----------- ----------- -----------
Income (loss) from continuing operations:
Interstate Natural Gas Pipelines 30,639 30,154 98,084 89,583
Natural Gas Gathering and Processing 14,531 (206,695) 34,162 (187,564)
Coal Slurry 900 1,534 2,439 3,251
Other (11,358) (8,565) (30,093) (27,930)
----------- ----------- ----------- -----------
Total income (loss) from
continuing operations 34,712 (183,572) 104,592 (122,660)
----------- ----------- ----------- -----------
Discontinued operations, net of tax -- (107) -- 4,369
Cumulative effect of change in
accounting principle, net of tax -- -- -- (643)
----------- ----------- ----------- -----------
Net income (loss) $ 34,712 $ (183,679) $ 104,592 $ (118,934)
=========== =========== =========== ===========
Operating data (1):
Interstate Natural Gas Pipelines:
Million cubic feet of gas delivered 271,929 266,287 847,505 822,176
Average daily throughput (MMcf/d) 3,029 2,965 3,167 3,123
Natural Gas Gathering and Processing:
Gathering (MMcf/d) 1,220 1,058 1,163 1,106
Processing (MMcf/d) 56 54 54 51
Coal Slurry:
Thousands of tons of coal shipped 1,217 1,298 3,346 3,155
(1) Operating data includes 100% of the volumes for joint venture
and equity investments as well as for wholly owned subsidiaries.
Following is a detailed analysis of the results of operations for each of
the Partnership's operating segments.
20
PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (CONTINUED)
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
THIRD QUARTER 2004 COMPARED WITH THIRD QUARTER 2003
INTERSTATE NATURAL GAS PIPELINES
The interstate natural gas pipelines segment reported income of $30.6
million in the third quarter of 2004 as compared to $30.2 million in the third
quarter of 2003. Income for the interstate natural gas pipelines segment
reflects a $0.3 million increase in Northern Border Pipeline's income. The
increase in Northern Border Pipeline's income was primarily due to a $0.9
million decrease in interest expense (a $0.6 million impact on continuing
operations after minority interest).
Operating revenues were $95.0 million in the third quarter of 2004 as
compared to $93.5 million in 2003. The increase in operating revenues in 2004
over 2003 resulted from a $1.2 million increase in Midwestern Gas Transmission's
revenues and a $0.4 million increase in Northern Border Pipeline's revenues.
Midwestern Gas Transmission's revenue increased primarily due to operational
sales of gas. Under a condition of Northern Border Pipeline's previous rate case
settlement, it was required to share interruptible transportation and new
services revenues with its shippers. This condition expired in October 2003 and
allowed Northern Border Pipeline to realize an additional $0.5 million of
revenue during the third quarter of 2004.
Operations and maintenance expense was $15.9 million in the third quarter
of 2004 as compared to $15.6 million in 2003. During the third quarter of 2004,
Northern Border Pipeline recorded $0.6 million of expense for the option to
renew a pipeline right-of-way lease with the Fort Peck Indian Reservation (see
Note 5 - Notes to Consolidated Financial Statements). Additionally in 2004,
Northern Border Pipeline recorded $0.4 million of costs incurred as part of its
comprehensive effort to ensure compliance with Section 404 of the Sarbanes Oxley
Act of 2002. Offsetting these increases was a reduction in benefit costs for
Northern Border Pipeline of $0.6 million.
Interest expense was $10.7 million in the third quarter of 2004 as
compared to $11.7 million in 2003. The decrease in interest expense in 2004 from
2003 was primarily due to a decrease in average debt outstanding for Northern
Border Pipeline partially offset by an increase in average interest rates.
Other expense was $0.8 million in the third quarter of 2004 as compared to
$0.1 million in 2003. The increase was primarily due to $0.6 million of reserves
established for costs associated with a potential future capital project.
NATURAL GAS GATHERING AND PROCESSING
The natural gas gathering and processing segment reported income of $14.5
million in the third quarter of 2004 as compared to a loss of $(206.7) million
in 2003. The segment recorded impairment charges of $219.1 million in the third
quarter of 2003. Excluding the effect of the impairment charges, the segment's
income from continuing operations increased $2.1 million between 2003 and 2004.
The increase is primarily due to higher natural gas and natural gas liquids
prices, increased gathering and processing volumes in the Williston Basin and
lower operations and maintenance expense partially offset by lower average
gathering rates in the Powder River Basin and higher depreciation expense.
21
PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (CONTINUED)
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
Operating revenues were $47.6 million in the third quarter of 2004 as
compared to $39.0 million in 2003. The increase in revenues reflects an increase
in realized prices for natural gas and natural gas liquids and increased
gathering and processing volumes in the Williston Basin partially offset by
lower average gathering rates in the Powder River Basin.
Product purchases were $26.1 million in the third quarter of 2004 as
compared to $20.4 million in 2003. Under certain gathering and processing
agreements in the Williston Basin, Bear Paw Energy purchases raw natural gas
from producers at a price tied to a percentage of the price for which it sells
extracted natural gas and natural gas liquids. Total revenues from the sale of
these products are included in operating revenues. Amounts paid to the producers
to purchase their raw natural gas are reflected in product purchases. The
increase in 2004 over 2003 is primarily due to an increase in natural gas and
natural gas liquid prices and increased volumes processed.
Operations and maintenance expense was $5.9 million in the third quarter
of 2004 as compared to $10.7 million in 2003. The 2004 amount includes a $3.2
million gain on sale of two of Bear Paw Energy's gathering systems and other
compressor equipment. In addition, the decrease in expense was due to the
segment recording a $1.8 million estimated recovery of previously recorded bad
debts. As a result of the bankruptcy of Enron North America in 2001, Bear Paw
Energy had recorded bad debt expense for commodity hedges. The bankruptcy court
has approved Bear Paw Energy's claim for these commodity hedges (see "The Impact
Of Enron's Chapter 11 Filing On The Partnership's Business".)
Depreciation and amortization expense was $3.8 million in the third
quarter of 2004 as compared to $222.2 million in 2003. The expense for 2003
includes $219.1 million of impairment charges. Excluding the impact of the
impairment charges, depreciation and amortization expense would have increased
$0.7 million between 2003 and 2004. As discussed in the Partnership's Annual
Report on Form 10-K for the year ended December 31, 2003, the Partnership
determined it was appropriate to shorten the useful life of its low-pressure gas
gathering assets in the Powder River Basin from 30 to 15 years, which increased
depreciation expense.
Other income was $3.8 million in the third quarter of 2003. This included
a $3.3 million payment received for a change in ownership of the other partner
in Bighorn Gas Gathering and a $0.5 million refund from an electric cooperative.
COAL SLURRY
The coal slurry pipeline segment reported income from continuing
operations of $0.9 million in the third quarter of 2004 on revenues of $5.5
million. In the third quarter of 2003, the segment reported income from
continuing operations of $1.5 million on revenues of $5.5 million. The decrease
in income in the third quarter of 2004 as compared to 2003 was primarily due to
a $0.3 million increase in depreciation and amortization expense and slightly
lower revenues than would otherwise have been realized due to temporary
shutdowns for maintenance and repair. Operations and maintenance expense was
$3.4 million in the third quarter of 2004 as compared to $3.1 million in 2003.
The increase
22
PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (CONTINUED)
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
was primarily due to a $0.2 million increase in electric power costs.
Depreciation and amortization expense for the coal slurry pipeline was $0.8
million in the third quarter of 2004 as compared to $0.5 million in 2003. The
Partnership determined it was appropriate to shorten the useful life of certain
of its coal slurry assets to correspond with the expiration of the existing coal
slurry transportation agreement in 2005. The impact of the shorter life will
increase annual depreciation in 2004 by approximately $1.8 million over 2003.
OTHER
Items not attributable to any segment include certain of the Partnership's
general and administrative expenses, interest expense on the Partnership's debt
and other income and expense items. The general and administrative expenses not
allocated to any segment were $2.0 million in the third quarter of 2004 as
compared to $1.3 million in 2003. The increase was primarily related to
increased insurance costs of $0.4 million and $0.4 million of costs incurred as
part of the Partnership's comprehensive effort to ensure compliance with Section
404 of the Sarbanes Oxley Act of 2002. Interest expense on the Partnership's
debt was $8.5 million in the third quarter of 2004 as compared to $7.4 million
in 2003. The increase in interest expense in 2004 from 2003 was primarily due to
an increase in average debt outstanding for the Partnership partially offset by
a decrease in average interest rates. Other expenses not allocated to any
segment were $1.2 million in the third quarter of 2004, which represented
business development expenditures related to unsuccessful acquisitions.
NINE MONTHS ENDED SEPTEMBER 30, 2004 COMPARED WITH NINE MONTHS ENDED SEPTEMBER
30, 2003
INTERSTATE NATURAL GAS PIPELINES
The interstate natural gas pipelines segment reported income of $98.1
million in the nine months ended September 30, 2004, as compared to $89.6
million in 2003. Income for the interstate natural gas pipelines segment
reflects a $6.3 million increase in Northern Border Pipeline's income and a $1.6
million increase in Viking Gas Transmission's income. The increase in Northern
Border Pipeline's income was primarily due to a $4.7 million increase in
operating revenues and a $4.2 million decrease in interest expense (a combined
$6.2 million impact on continuing operations after minority interest). As
discussed in the Partnership's Annual Report on Form 10-K for the year ended
December 31, 2003, the Partnership acquired all of the common stock of Viking
Gas Transmission on January 17, 2003. The increase in Viking Gas Transmission's
income in 2004 was primarily due to 2003 only including operating results
beginning at the January 17, 2003 acquisition date.
Operating revenues were $287.2 million in the nine months ended September
30, 2004 as compared to $279.1 million in 2003. The increase in operating
revenues in 2004 over 2003 resulted from a $4.7 million increase in Northern
Border Pipeline's revenues, a $1.9 million increase in Viking Gas Transmission's
revenues and a $1.5 million increase in Midwestern Gas Transmission's revenues.
The increase in Northern Border Pipeline's revenues was due to several factors.
Northern Border Pipeline was able to generate and
23
PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (CONTINUED)
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
retain additional revenue from the sale of short-term capacity, which
represented approximately $2.0 million of the increase. Under a condition of
Northern Border Pipeline's previous rate case settlement, it was required to
share interruptible transportation and new services revenues with its shippers.
This condition expired in October 2003 and allowed Northern Border Pipeline to
realize an additional $1.8 million of revenue during the nine months ended
September 30, 2004. The leap year added an additional day of transportation,
which approximated $0.9 million of the revenue increase. Viking Gas
Transmission's revenue was higher in 2004 because 2003 does not reflect revenue
prior to the January 17, 2003 acquisition date. Midwestern Gas Transmission's
revenue increased primarily due to operational sales of gas.
Operations and maintenance expense was $43.5 million in the nine months
ended September 30, 2004 as compared to $43.6 million in 2003. During the nine
months ended September 30, 2004, Northern Border Pipeline recorded $1.3 million
of expense for the option to renew a pipeline right-of-way lease with the Fort
Peck Indian Reservation (see Note 5 - Notes to Consolidated Financial
Statements). Additionally in 2004, the interstate pipelines reduced their
operations and maintenance expense by approximately $1.3 million related to the
settlement of previously accrued charges for administrative services provided by
Northern Plains Natural Gas, the pipelines' operator, and its affiliates.
Interest expense was $32.1 million in the nine months ended September 30,
2004 as compared to $36.4 million in 2003. The decrease in interest expense in
2004 from 2003 was primarily due to a decrease in average debt outstanding for
Northern Border Pipeline.
Other expense was $1.4 million in the nine months ended September 30,
2004, as compared to $0.7 million in 2003. The increase was primarily due to
$0.6 million of reserves established for costs associated with a potential
future capital project.
Minority interests in net income, which represent the 30% minority
interest in Northern Border Pipeline, was $36.2 million in the nine months ended
September 30, 2004 as compared to $33.5 million in 2003. The increase in 2004
over 2003 was due to increased net income for Northern Border Pipeline.
NATURAL GAS GATHERING AND PROCESSING
The natural gas gathering and processing segment reported income of $34.2
million in the nine months ended September 30, 2004, as compared to a loss of
$(187.6) million in 2003. The segment recorded impairment charges of $219.1
million in 2003. Excluding the effect of the impairment charges, the segment's
income from continuing operations increased $2.7 million between 2003 and 2004.
The increase is primarily due to higher natural gas and natural gas liquids
prices, increased gathering and processing volumes in the Williston Basin and
lower operations and maintenance expense partially offset by lower gathering
volumes in the Powder River Basin and higher depreciation expense.
Operating revenues were $133.0 million in the nine months ended September
30, 2004, as compared to $115.4 million in 2003. The increase in revenues
reflects an increase in realized prices for natural gas and natural gas liquids
and increased gathering and processing volumes in the Williston Basin partially
offset by lower gathering volumes in the Powder River Basin.
24
PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (CONTINUED)
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
Product purchases were $71.0 million in the nine months ended September
30, 2004, as compared to $60.7 million in 2003. Under certain gathering and
processing agreements in the Williston Basin, Bear Paw Energy purchases raw
natural gas from producers at a price tied to a percentage of the price for
which it sells extracted natural gas and natural gas liquids. Total revenues
from the sale of these products are included in operating revenues. Amounts paid
to the producers to purchase their raw natural gas are reflected in product
purchases. The increase in 2004 over 2003 is primarily due to an increase in
natural gas and natural gas liquid prices and increased volumes processed.
Operations and maintenance expense was $26.8 million in the nine months
ended September 30, 2004, as compared to $30.7 million in 2003. The 2004 amount
includes a $3.4 million gain on sale of two of Bear Paw Energy's gathering
systems and other compressor equipment. In addition, the decrease in expense was
due to the segment recording a $1.8 million estimated recovery of previously
recorded bad debts. As a result of the bankruptcy of Enron North America in
2001, Bear Paw Energy had recorded bad debt expense for commodity hedges. The
bankruptcy court has approved Bear Paw Energy's claim for these commodity hedges
(see "The Impact Of Enron's Chapter 11 Filing On The Partnership's Business".)
Depreciation and amortization expense was $11.4 million in the nine months
ended September 30, 2004, as compared to $228.4 million in 2003. The expense for
2003 includes $219.1 million of impairment charges. Excluding the impact of the
impairment charges, depreciation and amortization expense would have increased
$2.1 million between 2003 and 2004. As discussed previously, the Partnership
determined it was appropriate to shorten the useful life of its low-pressure gas
gathering assets in the Powder River Basin from 30 to 15 years, which increased
depreciation expense.
Other income was $0.2 million in the nine months ended September 30, 2004,
as compared to $3.8 million in 2003. The 2003 amount included a $3.3 million
payment received for a change in ownership of the other partner in Bighorn Gas
Gathering and a $0.5 million refund from an electric cooperative.
COAL SLURRY
The coal slurry pipeline segment reported income from continuing
operations of $2.4 million in the nine months ended September 30, 2004, on
revenues of $16.3 million. In the nine months ended September 30, 2003, the
segment reported income from continuing operations of $3.2 million on revenues
of $16.0 million. The $0.8 million decrease in income from continuing operations
was primarily due to higher depreciation expense of $1.7 million ($1.0 million
impact after income taxes). Depreciation and amortization expense for the coal
slurry pipeline was $3.0 million in the nine months ended September 30, 2004, as
compared to $1.3 million in 2003. The Partnership determined it was appropriate
to shorten the useful life of certain of its coal slurry assets to correspond
with the expiration of the existing coal slurry transportation agreement in
2005. The impact of the shorter life will increase annual depreciation in 2004
by approximately $1.8 million over 2003.
25
PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (CONTINUED)
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
OTHER
Items not attributable to any segment include certain of the Partnership's
general and administrative expenses, interest expense on the Partnership's debt
and other income and expense items. The general and administrative expenses not
allocated to any segment were $5.7 million in the nine months ended September
30, 2004, as compared to $4.7 million in 2003. The increase in expense between
2003 and 2004 was primarily related to increased insurance costs of $1.3 million
and $0.4 million of costs incurred as part of the Partnership's comprehensive
effort to ensure compliance with Section 404 of the Sarbanes Oxley Act of 2002
partially offset by a $0.5 million reduction related to the settlement of
previously accrued charges for administrative services provided by Northern
Plains Natural Gas and its affiliates. Other expenses not allocated to any
segment were $1.2 million in the nine months ended September 30, 2004, as
compared to $0.5 million in 2003. The increase represented business development
expenditures related to unsuccessful acquisitions.
LIQUIDITY AND CAPITAL RESOURCES
DEBT AND CREDIT FACILITIES
The Partnership's debt and credit facilities outstanding at September 30,
2004, are as follows:
Payments Due by Period
--------------------------------
Current Portion
(Less Than Long-Term
Total 1 Year) Portion
------------- ------------- -------------
(In Thousands)
Northern Border Pipeline
$175 million Pipeline Credit
Agreement, average 2.29%,
due 2005 (a) $ 10,000 $ 10,000 $ --
6.25% Senior Notes due 2007 225,000 -- 225,000
7.75% Senior Notes due 2009 200,000 -- 200,000
7.50% Senior Notes due 2021 250,000 -- 250,000
Viking Gas Transmission
Series A, B, C and D Senior
Notes, average 7.42%,
due 2008 to 2014 32,091 4,760 27,331
Northern Border Partners, L.P.
$275 million Partnership Credit
Agreement, average 2.56%,
due 2007 (a) 129,000 -- 129,000
8 7/8% Senior Notes due 2010 250,000 -- 250,000
7.10% Senior Notes due 2011 225,000 -- 225,000
------------- ------------- -------------
Total $ 1,321,091 $ 14,760 $ 1,306,331
============= ============= =============
(a) Both Northern Border Partners, L.P. and Northern Border Pipeline are
required to pay a 0.125% fee on the principal commitment amount of their credit
agreements.
26
PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (CONTINUED)
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
Northern Border Pipeline has outstanding interest rate swap agreements
with notional amounts totaling $225 million that expire in May 2007. Under the
interest rate swap agreements, Northern Border Pipeline makes payments to
counterparties at variable rates based on the London Interbank Offered Rate and
in return receives payments based on a 6.25% fixed rate. At September 30, 2004,
the average effective interest rate on Northern Border Pipeline's interest rate
swap agreements was 2.46%.
The Partnership has outstanding interest rate swap agreements with
notional amounts totaling $150 million that expire in March 2011. Under the
interest rate swap agreements, the Partnership makes payments to counterparties
at variable rates based on the London Interbank Offered Rate and in return
receives payments based on a 7.10% fixed rate. At September 30, 2004, the
average effective interest rate on the Partnership's interest rate swap
agreements was 4.61%.
Short-term liquidity needs will be met by operating cash flows and through
the Partnership Credit Agreement and the Pipeline Credit Agreement. Long-term
capital needs may be met through the Partnership's ability to issue long-term
indebtedness as well as additional limited partner interests.
CASH FLOWS FROM OPERATING ACTIVITIES
Cash flows provided by operating activities were $192.0 million in the
nine months ended September 30, 2004, as compared to $169.3 million for the
comparable period in 2003. The increase in operating revenues and lower interest
expense in 2004 as compared to 2003 contributed to the increase in operating
cash flow. These increases were partially offset by higher product purchases,
decreases in other income and a $5.5 million decrease in distributions received
from unconsolidated affiliates. Other cash flows from operating activities for
2004 also reflect Northern Border Pipeline's initial payment of $7.4 million to
the Fort Peck Tribes, in accordance with the terms of the Agreement. Operating
cash flows in 2003 reflect Northern Border Pipeline's refund to its shippers for
$10.3 million. Operating cash flows in 2003 were also decreased due to payments
made to NBP Services Corp. for administrative services provided prior to 2003 of
approximately $5.6 million. In addition, cash flows in 2003 were also decreased
approximately $9.5 million due to Northern Border Pipeline's discontinuance of
certain shipper transportation prepayments.
CASH FLOWS FROM INVESTING ACTIVITIES
Cash used in investing activities was $16.3 million in the nine months
ended September 30, 2004, as compared to $97.6 million in 2003. The results for
2003 included the acquisition of Viking Gas Transmission in January and the sale
of the Gladys and Mazeppa processing plants in June. Acquisitions of businesses
were $119.3 million in the nine months ended September 30, 2003, which
represents the net cash paid to acquire Viking Gas Transmission. Sale of
gathering and processing assets were $40.3 million in the nine months ended
September 30, 2003, due to the sale of the Gladys and Mazeppa processing plants.
Sale of gathering and processing assets totaled $8.7 million in the
27
PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (CONTINUED)
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
nine months ended September 30, 2004. This includes $7.0 million from the sale
of two of Bear Paw Energy's gathering systems on September 30, 2004, which is
recorded in accounts receivable on the consolidated balance sheet. Subsequent to
September 30, 2004, Bear Paw Energy received cash proceeds from the sale
totaling $5.5 million. The remaining proceeds are expected to be received in the
fourth quarter of 2004 and in early 2005. As a result, the consolidated cash
flow statement for the nine months ended September 30, 2004, does not include
the $7.0 million as a component of cash flows from investing activities.
The investment in unconsolidated affiliates was $3.5 million in the nine
months ended September 30, 2003, which primarily represents capital
contributions to Guardian Pipeline. No capital contributions have been required
in 2004.
Capital expenditures were $17.9 million in the nine months ended September
30, 2004, which included $9.3 million for the interstate natural gas pipelines
segment, $7.1 million for the natural gas gathering and processing segment and
$1.5 million for the coal slurry pipeline segment. For the nine months ended
September 30, 2003, capital expenditures were $15.0 million, which included $7.8
million for the interstate natural gas pipelines segment, $5.5 million for the
natural gas gathering and processing segment and $1.7 million for the coal
slurry pipeline segment.
Total capital expenditures for 2004 are estimated to be $42 million.
Capital expenditures for the interstate natural gas pipelines segment are
estimated to be $19 million, including $14 million for Northern Border Pipeline,
and are primarily related to renewals and replacements of existing facilities.
Northern Border Pipeline currently anticipates funding its 2004 capital
expenditures primarily by borrowing on its credit facility and using operating
cash flows. Capital expenditures for the natural gas gathering and processing
segment are estimated to be $21 million for 2004, primarily related to
expenditures that are expected to generate additional revenues or significant
operating efficiency. Funds required to meet the capital requirements for 2004
are anticipated to be provided from the Partnership's credit facility and
operating cash flows.
CASH FLOWS FROM FINANCING ACTIVITIES
Cash flows used in financing activities were $171.3 million in the nine
months ended September 30, 2004, as compared to $77.7 million in 2003. Cash
distributions to unitholders and general partners in the nine months ended
September 30, 2004 and 2003, were $119.7 million and $115.3 million,
respectively. The increase in 2004 over 2003 is due to an increase in the number
of common units outstanding.
In the nine months ended September 30, 2004, Northern Border Pipeline
received equity contributions from its general partners including $39.0 million
from its minority interest holder. Northern Border Pipeline's distributions to
its minority interest holder increased $12.9 million. Effective January 1, 2004,
Northern Border Pipeline changed its cash distribution policy. Cash
distributions will be equal to 100% of distributable cash flow as determined
from Northern Border Pipeline's financial statements based upon earnings before
interest, taxes, depreciation and amortization less interest expense and less
maintenance capital expenditures.
28
PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (CONTINUED)
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
During the nine months ended September 30, 2003, the Partnership issued
additional partnership interests of $102.4 million, which were primarily used to
repay indebtedness outstanding.
For the nine months ended September 30, 2004, borrowings on long-term debt
totaled $100.0 million, which were primarily used for the Partnership's equity
contribution to Northern Border Pipeline. For 2003, borrowings on long-term debt
totaled $270.0 million, which were primarily used for the acquisition of Viking
Gas Transmission and to repay existing indebtedness. Total repayments of debt in
the nine months ended September 30, 2004 and 2003, were $143.8 million and
$313.2 million, respectively.
In March 2003, the Partnership received $12.3 million from the termination
of an interest rate swap agreement with a notional amount of $75 million. The
proceeds were primarily used to repay existing indebtedness.
THE IMPACT OF ENRON'S CHAPTER 11 FILING ON THE PARTNERSHIP'S BUSINESS
As discussed in the Partnership's Annual Report on Form 10-K for the year
ended December 31, 2003, on December 2, 2001, Enron Corp. and certain of its
wholly owned subsidiaries filed a voluntary petition for bankruptcy protection
under Chapter 11 of the United States Bankruptcy Code. Refer to the Form 10-K
for the year ended December 31, 2003 for the full discussion of impacts of
Enron's Chapter 11 Filing on the Partnership's business.
On March 31, 2004, Enron transferred its ownership interest in Northern
Plains Natural Gas Company, Pan Border Gas Company and NBP Services Corporation
to CrossCountry Energy, LLC ("CrossCountry"). In addition, CrossCountry and
Enron entered into a transition services agreement pursuant to which Enron will
provide to CrossCountry, on an interim, transitional basis, various services,
including but not limited to (i) information technology services, (ii)
accounting system usage rights and administrative support and (iii) payroll,
employee benefits and administrative services. In turn, these services are
provided to the Partnership and its subsidiaries through Northern Plains and NBP
Services. The agreement terminates on the earlier of a sale of CrossCountry or
December 31, 2004. The agreement may be extended by mutual agreement of the
parties and approval of Enron's Official Committee of Unsecured Creditors.
On June 24, 2004, Enron announced that it had reached an agreement with a
joint venture of Southern Union Company and GE Commercial Finance Energy
Financial Services ("CCE Holdings") for the sale of CrossCountry. On September
1, 2004, Enron announced that it reached an amended agreement for the sale of
CrossCountry to CCE Holdings ("CCE Holdings Agreement"). On September 10, 2004,
the Bankruptcy Court issued an order (the "September 10 Order") approving the
CCE Holdings Agreement. The acquisition is subject to satisfaction of certain
approvals and other closing conditions and is expected to close no later than
mid-December 2004.
On September 16, 2004, Southern Union Company and ONEOK, Inc. each
announced that ONEOK had entered into an agreement ("ONEOK Agreement") to
purchase Northern Plains, Pan Border and NBP Services (collectively the
"Transfer Group Companies") from CCE Holdings. This acquisition, which is
subject to satisfaction of certain approvals and other closing conditions, is
expected to close concurrently with the CCE Holdings purchase of CrossCountry.
29
PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (CONTINUED)
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
Under the CCE Holdings Agreement, Enron has agreed to extend certain of
the terms of the transition services agreement and transition services
supplemental agreement between CrossCountry and Enron (together the "TSA") for a
period of six months from the closing date. Under the ONEOK Agreement, CCE
Holdings and ONEOK have agreed to use reasonable commercial efforts to
memorialize a transition services agreement referred to as the "Northern Border
Transition Services Agreement" covering certain transition services by and among
ONEOK, the Transfer Group Companies, CCE Holdings and Enron. There is no
obligation on the part of Enron to enter into such arrangement and there can be
no assurance that any such agreement will be entered into by Enron. In the event
the Northern Border Transition Services Agreement is not entered into, then the
ONEOK Agreement provides that certain transition services will be provided to
the parties on substantially the same basis as provided prior to closing. The
Partnership expects that most of the services it received in the past from Enron
and CrossCountry will continue to be provided through the term of the transition
services agreements or until those services can be provided directly by Northern
Plains and NBP Services or indirectly by ONEOK. As services are transitioned to
Northern Plains, NBP Services or ONEOK, it is possible that additional costs for
computer hardware, software and personnel may result. Any such costs have not
been determined. Additionally, it is not known at this time what rights Enron,
CrossCountry or CCE Holdings may have to use third party software and what
personnel will be available to provide the transition services to Northern
Plains and NBP Services.
As previously reported in the Partnership's Form 10-K for the year ended
December 31, 2003, on December 31, 2003, Enron filed a motion seeking approval
of the Bankruptcy Court to provide additional funding to, and for authority to
terminate, the Enron Corp. Cash Balance Plan ("Cash Balance Plan") and certain
other defined benefit plans of Enron's affiliates (collectively the "Plans") in
"standard terminations" within the meaning of Section 4041 of the Employee
Retirement Income Security Act of 1974, as amended ("ERISA"). Such standard
terminations would satisfy all of the obligations of Enron and its affiliates
with respect to funding liabilities under the Plans. In addition, a standard
termination would eliminate the contingent claims of the Pension Benefit
Guaranty Corporation ("PBGC") against Enron and its affiliates with respect to
funding liabilities under the Plans. On January 30, 2004, the Bankruptcy Court
entered an order authorizing the termination, additional funding and other
actions necessary to effect the relief requested. Pursuant to the Bankruptcy
Court order, any contributions to the Plans are subject to the prior receipt of
a favorable determination by the Internal Revenue Service that the Plans are
tax-qualified as of their respective dates of termination.
On June 2, 2004, the PBGC issued a notice to Enron stating that it had
determined that the Plans will be unable to pay benefits when due and should be
terminated in order to protect the interests of the participants in the Plans,
and/or that the risk of loss to the PBGC would increase unreasonably if the
Plans were not so terminated. On June 3, 2004, the PBGC filed a complaint in the
District Court for the Southern District of Texas against Enron as the sponsor
and/or administrator of the Plans (the "Action") which complaint was served on
Enron on July 19, 2004. By filing the Action, the PBGC is seeking an order (i)
terminating the Plans; (ii) appointing the PBGC the statutory trustee of the
Plans; (iii) requiring transfer to the PBGC of all records, assets or other
property of the Plans required to determine the benefits payable to the Plans'
participants; and (iv) establishing June 2, 2004 as the termination date of the
Plans.
30
PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (CONTINUED)
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
Enron management previously informed Northern Plains and NBP Services that
Enron will seek funding contributions from each member of its ERISA controlled
group of corporations that employs, or employed, individuals who are, or were,
covered under the Cash Balance Plan. Northern Plains and NBP Services are
considered members of Enron's ERISA controlled group of corporations. As of
December 31, 2003, an amount of approximately $6.2 million was estimated for
Northern Plains' and NBP Services' proportionate share of the up to $200 million
estimated termination costs for the Plans authorized by the Bankruptcy Court
order. Under the operating agreement with Northern Plains and the administrative
agreement with NBP Services, these costs may be the Partnership's
responsibility. In December of 2003, the Partnership accrued $6.2 million to
satisfy claims of reimbursement for these termination costs.
In the Bankruptcy Court September 10 Order, Enron was authorized to enter
into an escrow agreement with CCE Holdings and PBGC. Upon closing, Enron will
deposit the amount of $321.8 million to an escrow account, which is intended to
ensure that none of CCE Holdings or its affiliates are exposed to liability to
the PBGC under Title IV of the Employee Retirement Income Security Act of 1974,
as amended, for which CCE Holdings may otherwise be indemnified pursuant to the
CCE Holdings Agreement. In addition, the form of escrow agreement approved
pursuant to the September 10 Order provides that, under certain circumstances
and upon approval by or notice to the parties to the escrow agreement, some or
all of the funds placed in escrow may be paid directly in respect of the Cash
Balance Plan or to the PBGC. However, the September 10 Order also provides that
PBGC retains any rights or claims it may have against the Transfer Group
Companies.
Under both the CCE Holdings Agreement and the ONEOK Agreement, neither
Northern Plains nor NBP Services nor the Partnership will be required to
contribute to or otherwise be liable for any contributions to Enron in
connection with the Cash Balance Plan. The purchase price under the agreements
will be deemed to include all contributions which otherwise would have been
allocable to Northern Plains and NBP Services.
While the final amounts chargeable to the Partnership under the operating
agreement for the termination of the Cash Balance Plan cannot be determined at
this time, the Partnership believes the ultimate settlement of this matter may
be for an amount significantly less than the $6.2 million accrual.
On July 15, 2004, the Bankruptcy Court approved the amended joint Chapter
11 plan and related disclosure statement ("Chapter 11 Plan"). Under the approved
Chapter 11 Plan, assuming the previously announced sales of Portland General
Electric and CrossCountry are consummated, Enron creditors, which should include
subsidiaries of the Partnership, will receive a combination of cash and equity
of Prisma Energy International, Enron's international energy asset business. The
Partnership has previously fully reserved its claims against Enron. During this
quarter, the Bankruptcy Court approved a settlement between Bear Paw Energy,
Enron and certain of its wholly-owned subsidiaries of Bear Paw Energy's claim
for commodity hedges. As a result, the Partnership adjusted its reserves to
reflect an estimated $1.8 million recovery for its claim. The Partnership
anticipates reaching approved settlements of its remaining claims and may
31
PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (CONTINUED)
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
realize total recoveries of $2 million to $6 million for claims in the Enron
bankruptcy proceedings. However, the Chapter 11 Plan has not yet become
effective and a number of parties have filed Notices of Appeal, which could
delay the effective date and/or change the terms of the Plan. There can be no
assurances on the amounts of the claims recovered or timing of distributions
under the Chapter 11 Plan.
PUBLIC UTILITY HOLDING COMPANY ACT ("PUHCA") REGULATION
As more fully discussed in the Partnership's Annual Report on Form 10-K
for the year ended December 31, 2003, on March 9, 2004, Enron registered as a
holding company under the Public Utility Holding Company Act of 1935 ("PUHCA").
Under PUHCA, the Partnership is a subsidiary of a registered holding company.
Immediately after Enron registered, the Securities and Exchange Commission
("SEC") issued an order granting Enron and its subsidiaries authority to
undertake certain transactions without further authorization from the SEC under
PUHCA ("Omnibus Order"). Upon consummation of the sale to CCE Holdings and to
ONEOK, the Partnership will no longer be a subsidiary of a registered holding
company.
INFORMATION REGARDING FORWARD-LOOKING STATEMENTS
The statements in this Quarterly Report that are not historical
information are forward-looking statements within the meaning of Section 27A of
the Securities Act of 1933 and Section 21E of the Securities Exchange Act of
1934. These forward-looking statements are identified as any statement that does
not relate strictly to historical or current facts. Forward-looking statements
are not guarantees of performance. They involve risks, uncertainties and
assumptions. The future results of the Partnership's operations may differ
materially from those expressed in these forward-looking statements. Such
forward-looking statements include, among other things, the discussions in
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" (i) "Liquidity and Capital Resources" regarding the Partnership's
estimated capital expenditures in 2004; (ii) "Overview" regarding recontracting
on Northern Border Pipeline, expansion projects on Northern Border Pipeline and
Midwestern Gas Transmission and the future of the Black Mesa pipeline; and (iii)
"The Impact of Enron's Chapter 11 Filing on the Partnership's Business"
regarding transition services and potential costs. Although the Partnership
believes that its expectations regarding future events are based on reasonable
assumptions within the bounds of its knowledge of its business, it can give no
assurance that its goals will be achieved or that its expectations regarding
future developments will be realized. Important factors that could cause actual
results to differ materially from those in the forward-looking statements herein
include, among other things, developments in the December 2, 2001 filing by
Enron of a voluntary petition for bankruptcy, the sale of CrossCountry and
subsequent sale of Northern Plains, Pan Border and NBP Services to ONEOK;
transition of certain services by Enron and CrossCountry to Northern Plains and
NBP Services, and the outcome of Enron's Chapter 11 process; regulations under
PUHCA; industry results; ability to recontract available capacity at maximum
transportation rates on Northern Border Pipeline; future demand for natural gas;
availability of supplies of Canadian natural gas; the ability to recover the
costs in pipeline rates of the settlement with the Fort Peck Tribes on
rights-of-way and tax issues; the rate of
32
PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (CONCLUDED)
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
development, gas quality, and competitive conditions in gas fields near the
Partnership's natural gas gathering systems in the Powder River and Williston
Basins and its investments in the Powder River and Wind River Basins; regulatory
actions and receipt of expected regulatory clearances; renewal of the coal
slurry transportation contract under favorable terms; competitive conditions in
the overall natural gas and electricity markets; the ability to market pipeline
capacity on favorable terms; performance of contractual obligations by the
shippers; prices of natural gas and natural gas liquids; actions by rating
agencies; the ability to renegotiate gathering contracts with producers;
legislative and regulatory developments that impact FERC proceedings involving
interstate pipelines and the interstate pipelines' success in sustaining their
positions in such proceedings; timely receipt of FERC approval and other
regulatory approvals of the new projects on the interstate pipelines; the
ability to control operating costs; competitive developments by Canadian and
U.S. natural gas transmission peers; and conditions in the capital markets and
the ability to access the capital markets.
These and other risks are described in greater detail in the section
entitled "Management's Discussion and Analysis of Financial Condition and
Results of Operations - Risk Factors and Information Regarding Forward-Looking
Statements" included in the Partnership's Annual Report on Form 10-K for the
year ended December 31, 2003. All forward-looking statements attributable to the
Partnership or persons acting on its behalf are expressly qualified in their
entirety by these factors. Other than as required under the securities laws, the
Partnership does not assume a duty to update these forward-looking statements,
whether as a result of new information, subsequent events or circumstances,
changes in expectations or otherwise.
33
PART I. FINANCIAL INFORMATION - (CONTINUED)
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
The Partnership may be exposed to market risk through changes in commodity
prices and interest rates, as discussed below. A control environment has been
established which includes policies and procedures for risk assessment and the
approval, reporting and monitoring of financial instrument activities.
The Partnership has utilized and expects to continue to utilize derivative
financial instruments in the management of interest rate risks and natural gas
and natural gas liquids marketing activities to achieve a more predictable cash
flow by reducing its exposure to interest rate and commodity price fluctuations.
For more information on risk management activities, see Note 2 to the
Partnership's consolidated financial statements included elsewhere in this
report.
INTEREST RATE RISK
The Partnership's interest rate exposure results from variable rate
borrowings from commercial banks. To mitigate potential fluctuations in interest
rates, the Partnership attempts to maintain a significant portion of its
consolidated debt portfolio in fixed rate debt. It also uses interest rate swaps
as a means to manage interest expense by converting a portion of fixed rate debt
to variable rate debt to take advantage of declining interest rates. At
September 30, 2004, the Partnership has $514.0 million of variable rate debt
outstanding (approximately 39% of its debt portfolio), $375.0 million of which
is previously fixed rate debt that has been converted to variable rate debt
through the use of interest rate swaps.
If average interest rates change by one percent compared to rates in
effect as of September 30, 2004, consolidated annual interest expense would
change by approximately $5.1 million. This amount has been determined by
considering the impact of the hypothetical interest rates on the Partnership's
variable rate borrowings outstanding as of September 30, 2004.
COMMODITY PRICE RISK
Bear Paw Energy is subject to certain contracts that give it quantities
of natural gas and natural gas liquids as partial consideration for processing
services. The income and cash flows from these contracts will be impacted by
changes in prices realized for these commodities. Prior to considering the
effects of any hedging, for each $0.10 per million British thermal unit change
in natural gas prices or for each $0.01 per gallon change in natural gas liquid
prices, the Partnership's annual net income would change by approximately $0.4
million. This amount has been determined by considering the impact of the
hypothetical commodity prices on Bear Paw Energy's projected gathering and
processing volumes for 2004. Subsequent to September 30, 2004, the Partnership
entered into additional hedge contracts for 2005 volumes. The Partnership has
hedged approximately 63% of its commodity price risk for the remainder of 2004
and approximately 18% of its commodity price risk for 2005.
34
PART I. FINANCIAL INFORMATION - (CONCLUDED)
ITEM 4. CONTROLS AND PROCEDURES
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
The Partnership's principal executive officer and principal financial
officer have evaluated the effectiveness of the Partnership's "disclosure
controls and procedures," as such term is defined in Rule 13a-15(e) and Rule
15d-15(e) of the Securities Exchange Act of 1934, as amended, as of the date of
the end of the period covered by this Quarterly Report on Form 10-Q. Based upon
their evaluation, the principal executive officer and principal financial
officer concluded that the Partnership's disclosure controls and procedures are
effective.
Except as discussed below, there were no changes in the Partnership's
internal control over financial reporting that occurred during its last fiscal
quarter that have materially affected, or are reasonably likely to materially
affect, its internal control over financial reporting.
The Partnership is currently undergoing a comprehensive effort to ensure
compliance with Section 404 of the Sarbanes Oxley Act of 2002 for the year
ending December 31, 2004. This effort includes internal control documentation
and review under the direction of the Partnership's principal executive officer
and principal financial officer. During the course of these activities, certain
control issues were identified that the Partnership believes can be improved.
These control issues in large part are related to documentation of the operation
and execution of internal controls. The Partnership has implemented a number of
improvements in its internal controls over financial reporting as a result of
its review efforts.
In addition, certain critical business systems, including information
technology applications, third party software licenses and computer and
communication hardware, supporting the Partnership's financial accounting and
reporting systems are owned by Enron and/or CrossCountry. The Partnership's
rights to utilize these systems may be impacted by the sale of CrossCountry. The
Partnership's access to these business systems is currently being provided
through services agreements, including a transition services agreement between
Enron and CrossCountry. Although that agreement terminates upon the sale of
CrossCountry, in the purchase and sale agreement with CCE Holdings, Enron has
agreed to extend the terms of the transition services agreement for certain
services for a period of six months from the closing date, which is expected to
occur no later than mid-December 2004. Also, in the purchase and sale agreement
with CCE Holdings and ONEOK, CCE Holdings has agreed to provide certain
transition services. Until these agreements have been finalized, Northern Plains
and NBP Services will be unable to advise the Partnership which critical systems
of Enron, CrossCountry, CCE Holdings or ONEOK will be utilized for the
Partnership. Implementation of controls, as well as documentation and
testing, of any new systems that require conversion before year-end may not be
possible.
At this time the Partnership expects it will complete all internal
controls review, testing and documentation as required under Section 404 of the
Sarbanes-Oxley Act. However, the Partnership's ability to realize this
expectation is dependent upon the availability of resources to execute internal
controls, complete all of the testing and documentation required and on the
actions of Enron, CrossCountry, CCE Holdings and ONEOK, as the sale process is
consummated. See also Item 2. "Management's Discussion And Analysis Of Financial
Condition And Results Of Operations - The Impact of Enron's Chapter 11 Filing On
the Partnership's Business."
35
PART II. OTHER INFORMATION
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
ITEM 1. LEGAL PROCEEDINGS
In Northern Border Pipeline's pending proceeding before the FERC on
procedures for awarding capacity, an order was issued on April 15, 2004 in which
the Federal Energy Regulatory Commission ("FERC") requested comments from
interested parties on whether the FERC's current policy on awarding available
capacity to a short-haul shipper appropriately balances the risks to the
pipeline, bidding shippers and other shippers on the pipeline. Comments were
filed by June 15, 2004. The timing of the issuance of the FERC's order in this
proceeding is not known. On September 21, 2004, Northern Border Pipeline filed a
motion to expedite the issuance of an order in this proceeding.
Also, see Note 5 to the Consolidated Financial Statements for an update on
certain legal proceedings involving Northern Border Pipeline and "Management's
Discussion and Analysis of Financial Condition and Results of Operations -
Overview - Coal Slurry Pipeline" for an update on legal proceedings affecting
the Black Mesa pipeline.
ITEM 6. EXHIBITS
31.1 Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.
31.2 Rule 13a-14(a)/15d-14(a) Certification of Chief Financial and
Accounting Officer.
32.1 Section 1350 Certification of Chief Executive Officer.
32.2 Section 1350 Certification of Chief Financial and Accounting
Officer.
36
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
NORTHERN BORDER PARTNERS, L.P.
(A Delaware Limited Partnership)
Date: November 9, 2004 By: /s/ Jerry L. Peters
-----------------------------------
Jerry L. Peters
Chief Financial and Accounting
Officer
37
Index to Exhibits
Exhibit No Description
- ---------- --------------------------------------------------------------------
31.1 Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.
31.2 Rule 13a-14(a)/15d-14(a) Certification of Chief Financial and
Accounting Officer.
32.1 Section 1350 Certification of Chief Executive Officer pursuant to 18
U.S.C. Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
32.2 Section 1350 Certification of Chief Financial and Accounting Officer
pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section
906 of the Sarbanes-Oxley Act of 2002.