UNITED STATES SECURITIES AND EXCHANGE
COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2001
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)
Enron Building
1400 Smith Street
Houston, Texas 77002
(Address of principal executive (Zip code)
offices)
(713) 853-6161
(Registrant's telephone number, including area code)
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 [ ]
1 of 23
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 June 30, 2001 and 2000
and Six Months Ended June 30, 2001 and 2000 3
Consolidated Statement of Comprehensive Income -
Three Months Ended June 30, 2001 and 2000
and Six Months Ended June 30, 2001 and 2000 3
Consolidated Balance Sheet - June 30, 2001
and December 31, 2000 4
Consolidated Statement of Cash Flows -
Six Months Ended June 30, 2001 and 2000 5
Consolidated Statement of Changes in Partners'
Equity - Six Months Ended June 30, 2001 6
Notes to Consolidated Financial Statements 7
ITEM 2. Management's Discussion and Analysis of
Financial Condition and Results of Operations 14
ITEM 3. Quantitative and Qualitative Disclosures About
Market Risk 21
PART II. OTHER INFORMATION
ITEM 1. Legal Proceedings 22
ITEM 6. Exhibits and Reports on Form 8-K 22
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 Six Months Ended
June 30, June 30,
2001 2000 2001 2000
<s> <c> <c> <c> <c>
OPERATING REVENUES, NET $125,474 $82,536 $213,434 $164,053
OPERATING EXPENSES
Product purchases 17,516 -- 17,516 --
Operations and maintenance 24,636 14,684 40,653 27,558
Depreciation and amortization 20,164 15,290 35,858 30,879
Taxes other than income 7,549 7,815 11,642 15,698
Operating expenses 69,865 37,789 105,669 74,135
OPERATING INCOME 55,609 44,747 107,765 89,918
INTEREST EXPENSE 24,632 19,249 46,328 37,940
OTHER INCOME (EXPENSE)
Equity earnings (losses) in
unconsolidated affiliates 772 (300) 555 (657)
Other income (expense) (578) 1,668 (2,081) 2,134
Other income (expense) 194 1,368 (1,526) 1,477
MINORITY INTERESTS IN NET INCOME 9,489 8,824 20,256 17,447
NET INCOME BEFORE
EXTRAORDINARY ITEMS 21,682 18,042 39,655 36,008
EXTRAORDINARY LOSS FROM
DEBT RESTRUCTURING (1,213) -- (1,213) --
NET INCOME TO PARTNERS $ 20,469 $18,042 $ 38,442 $ 36,008
NET INCOME PER UNIT $ 0.48 $ 0.60 $ 1.02 $ 1.19
NUMBER OF UNITS USED IN COMPUTATION 39,341 29,347 35,453 29,347
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
(In Thousands)
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
2001 2000 2001 2000
<s> <c> <c> <c> <c>
Net income to partners $ 20,469 $18,042 $ 38,442 $36,008
Other comprehensive income:
Transition adjustment from
adoption of SFAS No. 133 -- -- 22,183 --
Change associated with current
period hedging transactions 9,088 -- 6,073 --
Change associated with
current period foreign
currency translation 1,894 -- 1,894 --
Total comprehensive income $ 31,451 $18,042 $ 68,592 $36,008
<FN>
The accompanying notes are an integral part of these consolidated
financial statements.
PART I. FINANCIAL INFORMATION (Continued)
ITEM 1. FINANCIAL STATEMENTS (Continued)
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(In Thousands)
(Unaudited)
June 30, December 31,
ASSETS 2001 2000
<s> <c> <c>
CURRENT ASSETS
Cash and cash equivalents $ 29,304 $ 35,363
Accounts receivable 46,924 40,617
Materials and supplies, at cost 7,909 5,736
Assets from price risk management activities 5,759 --
Other 671 --
Total current assets 90,567 81,716
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment 2,770,720 2,454,918
Less: Accumulated provision for
depreciation and amortization 755,658 722,842
Property, plant and equipment, net 2,015,062 1,732,076
INVESTMENTS AND OTHER ASSETS
Investment in unconsolidated affiliates 227,464 221,625
Goodwill 270,686 28,405
Other 59,154 18,898
Total investments and other assets 557,304 268,928
Total assets $2,662,933 $2,082,720
LIABILITIES AND PARTNERS' EQUITY
CURRENT LIABILITIES
Current maturities of long-term debt $ 517,459 $ 44,464
Accounts payable 36,013 35,413
Accrued taxes other than income 23,799 28,493
Accrued interest 18,806 15,635
Other 1,455 --
Accumulated provision for rate refunds -- 4,726
Total current liabilities 597,532 128,731
LONG-TERM DEBT, NET OF CURRENT MATURITIES 862,331 1,127,498
MINORITY INTERESTS IN PARTNERS' EQUITY 252,779 248,098
RESERVES AND DEFERRED CREDITS 6,677 6,119
PARTNERS' EQUITY
Partner's capital 913,464 572,274
Accumulated other comprehensive income 30,150 --
Total partners' equity 943,614 572,274
Total liabilities and partners' equity $2,662,933 $2,082,720
<FN>
The accompanying notes are an integral part of these consolidated
financial statements.
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)
Six Months Ended
June 30,
2001 2000
<s> <c> <c>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income to partners $ 38,442 $ 36,008
Adjustments to reconcile net income to partners
to net cash provided by operating activities, net
of the effect of the acquired businesses:
Depreciation and amortization 36,041 30,837
Minority interests in net income 20,256 17,447
Provision for rate refunds 2,036 13,773
Rate refunds paid (6,762) --
Changes in components of working capital, net
of the effect of the acquired businesses 8,011 (3,590)
Other 369 283
Total adjustments 59,951 58,750
Net cash provided by operating activities 98,393 94,758
CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in unconsolidated affiliates (6,229) (2,499)
Acquisitions of businesses (340,197) (20,800)
Capital expenditures for property, plant
and equipment (48,033) (4,094)
Net cash used in investing activities (394,459) (27,393)
CASH FLOWS FROM FINANCING ACTIVITIES:
Cash distributions to Unitholders and
General Partners (53,448) (39,342)
Distributions to Minority Interests (20,960) (19,296)
Issuance of long-term debt 485,703 169,783
Decrease in bank overdraft (22,437) --
Issuance of partnership interests, net 173,165 --
Payments on termination of derivatives (4,346) --
Long-term debt financing costs (2,859) (1,474)
Retirement of long-term debt (264,811) (146,018)
Net cash provided by (used in)
financing activities 290,007 (36,347)
NET CHANGE IN CASH AND CASH EQUIVALENTS (6,059) 31,018
Cash and cash equivalents-beginning of period 35,363 22,927
Cash and cash equivalents-end of period $ 29,304 $ 53,945
Supplemental Disclosures of Cash Flow Information:
Cash paid for:
Interest (net of amount capitalized) $ 44,052 $ 37,436
Changes in components of working capital:
Accounts receivable $ 9,540 $ (5,257)
Materials and supplies (761) (1,622)
Accrued income taxes receivable/payable (671) --
Under/over recovered cost of service -- 3,742
Accounts payable 1,085 (47)
Accrued taxes other than income (4,999) (1,158)
Other 646 --
Accrued interest 3,171 752
Total $ 8,011 $ (3,590)
<FN>
The accompanying notes are an integral part of these consolidated
financial statements.
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
General Common Comprehensive Total
Partners Units Income Equity
<s> <c> <c> <c> <c>
Balance at December 31, 2000 $11,445 $560,829 $ -- $572,274
Net income to partners 2,408 36,034 -- 38,442
Transition adjustment from
adoption of SFAS No. 133 -- -- 22,183 22,183
Change associated with current
period hedging transactions -- -- 6,073 6,073
Change associated with current
period foreign currency translation -- -- 1,894 1,894
Issuance of partnership
interests, net 7,124 349,072 -- 356,196
Distributions to partners (2,708) (50,740) -- (53,448)
Balance at June 30, 2001 $18,269 $895,195 $30,150 $943,614
<FN>
The accompanying notes are an integral part of this consolidated
financial statement.
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 ("SEC"). Accordingly, they
reflect all adjustments which 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 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, 2000.
The preparation of financial statements in conformity with
accounting principles generally accepted in the United States
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., a Canadian company;
Midwestern Gas Transmission Company; and Black Mesa Holdings, Inc.
are wholly-owned subsidiaries of the Partnership. Crestone Energy
Ventures owns a 49% common membership interest and a 100% class A
share interest in Bighorn Gas Gathering, L.L.C.; a 33% interest in
Fort Union Gas Gathering, L.L.C.; and a 35% interest in Lost Creek
Gathering, L.L.C. Crestone Gathering Services, L.L.C. is a wholly-
owned subsidiary of Crestone Energy Ventures.
2. ACQUISITIONS
On March 30, 2001, the Partnership completed the acquisition of
Bear Paw Energy for $381.7 million. The purchase price consisted of
$198.7 million in cash and the issuance of 5.7 million common units
valued at $183.0 million. Bear Paw Energy has extensive gathering
and processing operations in the Powder River Basin in Wyoming and
the Williston Basin in Montana and North Dakota. Bear Paw Energy
has approximately 226,000 acres under dedication and 600 miles of
gathering pipelines in the Powder River Basin. In the Williston
Basin, Bear Paw Energy has over 2,800 miles of gathering pipelines
and four processing plants with 90 million cubic feet per day of
capacity.
On April 4, 2001, Border Midstream Services completed the
acquisition of the Mazeppa and Gladys sour gas processing plants,
gas gathering systems and a minority interest in the Gregg Lake/Obed
Pipeline for $70 million (Canadian) or $45.0 million (U.S.). The
Mazeppa and Gladys plants, which are located near Calgary, Alberta,
have a combined capacity of 87 million cubic feet per day. The
Gregg Lake/Obed Pipeline system, which is located near Edmonton,
Alberta, is comprised of 85 miles of gathering lines with a capacity
of approximately 150 million cubic feet per day.
On April 30, 2001, the Partnership acquired Midwestern Gas
Transmission for approximately $102 million. The Midwestern Gas
Transmission system is a 350-mile interstate natural gas pipeline
extending from Portland, Tennessee to Joliet, Illinois with a
capacity of 650 million cubic feet per day. Midwestern Gas
Transmission connects to seven other major interstate pipeline
systems, including Northern Border Pipeline.
The Partnership has accounted for these acquisitions using the
purchase method of accounting. At this time, the Partnership has
made preliminary allocations of the purchase price of each
acquisition based upon the estimated fair value of the assets and
liabilities acquired as of each acquisition date. The Partnership
expects to finalize the allocations by the fourth quarter of 2001.
The excess of the purchase price over the fair value of the net
assets acquired is reflected as goodwill on the consolidated balance
sheet and is being amortized on a straight-line basis over 30 years.
The investment in Gregg Lake/Obed Pipeline is being reflected in
investments in unconsolidated affiliates on the consolidated balance
sheet.
The following is a summary of the effects of the acquisitions
made in the first half of 2001 on the Partnership's consolidated
financial position (amounts in thousands):
<s> <c>
Current assets $ 17,257
Property, plant and equipment 265,715
Investments in unconsolidated affiliates 1,059
Goodwill 245,903
Other assets 29,461
Current liabilities (25,255)
Long-term debt, including current maturities (13,113)
Other liabilities (498)
Accumulated other comprehensive income 2,699
Common units issued by the Partnership (183,031)
Net cash paid $ 340,197
If the acquisitions made in 2001 had occurred at the beginning of
2001, the Partnership's consolidated operating revenues would have
been $258 million, net income to partners would have been $39
million and net income per unit would have been $1.02 for the six
months ended June 30, 2001. These unaudited pro forma results are
for illustrative purposes only and are not necessarily indicative of
the operating results that would have occurred had the business
acquisitions been consummated at that date, nor are they necessarily
indicative of future operating results.
3. RATES AND REGULATORY ISSUES
Rate Case
Northern Border Pipeline filed a rate proceeding with the Federal
Energy Regulatory Commission ("FERC") in May 1999 for, among other
things, a redetermination of its allowed equity rate of return. The
total annual cost of service increase due to Northern Border
Pipeline's proposed changes was approximately $30 million. In June
1999, the FERC issued an order in which the proposed changes were
suspended until December 1, 1999, after which the proposed changes
were implemented with subsequent billings subject to refund.
In September 2000, Northern Border Pipeline filed a stipulation
and agreement with the FERC that documented the proposed settlement
of its pending rate case. The settlement was approved by the FERC
in December 2000. Under the approved settlement, effective December
1, 1999, shippers pay stated transportation rates based on a
straight-fixed variable rate design. From December 1, 1999, through
and including December 31, 2000, the rates were based upon an annual
revenue level of $307 million. Beginning January 1, 2001, the rates
are based upon an annual revenue level of $305 million.
After the FERC approved the rate case settlement and prior to the
end of 2000, Northern Border Pipeline made estimated refund payments
to its shippers totaling approximately $22.7 million, primarily
related to the period from December 1999 to November 2000. During
the first quarter of 2001, Northern Border Pipeline paid the
remaining refund obligation to its shippers totaling approximately
$6.8 million, which related to periods through January 2001.
Certificate Application
On March 16, 2000, the FERC issued an order granting Northern
Border Pipeline's application for a certificate to construct and
operate the proposed expansion and extension of its pipeline system
into Indiana ("Project 2000"). The FERC approved Northern Border
Pipeline's request for a certificate to construct and operate the
proposed facilities. The FERC approved Northern Border Pipeline's
request for rolled-in rate treatment based upon the proposed project
costs. The project has a targeted in-service date of November 2001.
The capital expenditures for the project are budgeted to be
approximately $94 million, of which $23.5 million had been incurred
through June 30, 2001.
4. CREDIT FACILITIES AND LONG-TERM DEBT
In March 2001, the Partnership completed a private offering of
$225 million of 7.10% Senior Notes due 2011 ("2001 Partnership
Senior Notes"). The Partnership has filed a registration
statement with the SEC to exchange the 2001 Partnership Senior
Notes for notes with substantially identical terms and expects
to complete the exchange during the third quarter of 2001. The
indenture under which the 2001 Partnership Senior Notes were
issued does not limit the amount of unsecured debt the Partnership
may incur, but does contain material financial covenants, including
restrictions on incurrence of secured indebtedness. The proceeds
from the 2001 Partnership Senior Notes were used to fund a portion
of the acquisition of Bear Paw Energy (see Note 2).
The Partnership entered into a $200 million three-year revolving
credit agreement with certain financial institutions ("2001
Partnership Credit Agreement") in March 2001. The 2001 Partnership
Credit Agreement is to be used for capital expenditures,
acquisitions and general business purposes. The 2001 Partnership
Credit Agreement permits the Partnership to choose among various
interest rate options, to specify the portion of the borrowings to
be covered by specific interest rate options and to specify the
interest rate period. The Partnership is required to pay a fee on
the principal commitment amount of $200 million. The 2001
Partnership Credit Agreement replaced revolving credit agreements
entered into in June 2000. At June 30, 2001, $32.0 million was
outstanding under the 2001 Partnership Credit Agreement at an
average effective interest rate of 5.62%.
In June 2001, the Partnership repaid Black Mesa's 10.7% Secured
Senior Notes due May 2004. The total repayment of approximately
$13.6 million consisted of remaining principal and interest of $12.4
million and an early payment premium of $1.2 million. The early
payment premium is reflected as an extraordinary loss on the
consolidated statement of income.
5. BUSINESS SEGMENT INFORMATION
The Partnership's reportable segments are strategic business
units that offer different services. The Partnership evaluates
performance based on EBITDA (net income before minority interests;
interest expense; and depreciation and amortization, including
goodwill amortization, which is netted against equity earnings of
unconsolidated affiliates).
Gas
Gathering
and
Interstate Processing Coal
(In thousands) Pipeline (a) Slurry Other(b) Total
Three Months Ended
June 30, 2001
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Revenues from
external customers $ 79,106 $40,769 $ 5,599 $ -- $125,474
EBITDA 60,875 15,398 1,814 (933) 77,154
Three Months Ended
June 30, 2000
Revenues from
external customers $ 77,346 $ -- $ 5,190 $ -- $ 82,536
EBITDA 60,261 (132) 1,860 (393) 61,596
Six Months Ended
June 30, 2001
Revenues from
external customers $156,146 $46,268 $11,020 $ -- $213,434
EBITDA 126,090 17,978 4,072 (3,321) 144,819
Six Months Ended
June 30, 2000
Revenues from
external customers $153,587 $ -- $10,466 $ -- $164,053
EBITDA 120,085 (321) 3,628 (721) 122,671
Total assets by segment are as follows:
June 30, December 31,
(In thousands) 2001 2000
<s> <c> <c>
Interstate Pipeline $1,856,228 $1,768,505
Gas Gathering and Processing 771,330 279,855
Coal Slurry 27,471 29,605
Other (b) 7,904 4,755
Total Assets $2,662,933 $2,082,720
<FN>
(a) Gas gathering and processing operating results commence from
the date of the acquisition of gas gathering and processing
businesses in September 2000, except for equity earnings of Bighorn
Gas Gathering, which commenced in January 2000.
(b) Includes other items not allocable to segments.
6. PARTNERS' CAPITAL
In April 2001 and May 2001, the Partnership sold 407,550 and
4,000,000 common units, respectively. In conjunction with the
issuance of the additional common units, including the units issued
for Bear Paw Energy in March 2001 (see Note 2), the Partnership's
general partners made capital contributions to the Partnership to
maintain a 2% general partner interest in accordance with the
partnership agreements. The net proceeds from the sale of common
units and the general partners' capital contributions totaled
approximately $173.2 million and were primarily used to repay
amounts borrowed under the 2001 Partnership Credit Agreement.
In connection with the Partnership's sale of common units in May
2001, Northwest Border Pipeline Company, a subsidiary of The
Williams Companies, Inc. and one of the Partnership's general
partners, sold its 1,123,500 common units. These common units had
previously been outstanding and did not affect the number of the
Partnership's total common units outstanding. The Partnership did
not receive any of the proceeds from the common units sold by
Northwest Border Pipeline.
7. 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
$1.6 million.
On July 19, 2001, the Partnership declared a cash distribution of
$0.7625 per unit ($3.05 per unit on an annualized basis) for the
quarter ended June 30, 2001. The distribution is payable August 14,
2001, to unitholders of record at July 31, 2001.
8. 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.
In 1998, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards ("SFAS") No. 133,
"Accounting for Derivative Instruments and Hedging Activities,"
which was subsequently amended by SFAS No. 137 and SFAS No. 138.
SFAS No. 133 requires that every derivative instrument (including
certain derivative instruments embedded in other contracts) be
recorded on the balance sheet as either an asset or liability
measured at its fair value. The 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, and requires that a company formally document, designate
and assess the effectiveness of transactions that receive hedge
accounting. The Partnership adopted SFAS No. 133 beginning January 1,
2001.
At December 31, 2000, the Partnership had classified in long-term
debt $26.0 million of unamortized proceeds from the termination of
derivatives. This included unamortized proceeds of $14.9 million
from the termination of interest rate swap agreements by the
Partnership in December 2000 and $11.1 million from the termination
of interest rate forward agreements by Northern Border Pipeline in
August 1999. As a result of the adoption of SFAS No. 133, the
Partnership reclassified $22.7 million from long-term debt to
accumulated other comprehensive income and $3.3 million from long-
term debt to minority interests in partners' equity. The
Partnership is reflecting in consolidated accumulated other
comprehensive income its 70% share of Northern Border Pipeline's
accumulated other comprehensive income. The remaining 30% is
reflected as an adjustment to minority interests in partners'
equity.
Also upon adoption of SFAS No. 133, Northern Border Pipeline
designated an outstanding interest rate swap agreement with a
notional amount of $40.0 million as a cash flow hedge. As a result,
the Partnership recorded a non-cash loss of $0.5 million in
accumulated other comprehensive income and $0.3 million as an
adjustment to minority interests in partners' equity.
In February 2001, the Partnership entered into forward starting
interest rate swaps with notional amounts totaling $150 million
related to the anticipated issuance of fixed rate debt. Upon
issuance of the 2001 Partnership Senior Notes in March 2001, the
Partnership paid approximately $4.3 million to terminate the swaps,
which was recorded in accumulated other comprehensive income. The
swaps were designated as cash flow hedges as they were entered into
to hedge the fluctuations in Treasury rates and spreads between the
execution date of the swaps and the issuance of the 2001 Partnership
Senior Notes.
During the three months and six months ended June 30, 2001, the
Partnership amortized approximately $0.5 million and $1.1 million,
respectively, related to the terminated derivatives, as a reduction
to interest expense from accumulated other comprehensive income.
The Partnership expects to amortize comparable amounts in each of
the remaining quarters of 2001.
In March 2001, Northern Border Pipeline entered into forward
starting interest rate swaps with notional amounts totaling $200
million related to the planned issuance of 10-year and 30-year fixed
rate debt. The swap instruments may be settled any time prior to
their expiration date on October 1, 2001. The swaps, which have
been designated as cash flow hedges, were entered into to hedge the
fluctuations in Treasury rates and spreads between the execution
date of the swaps and the anticipated issuance date of the fixed
rate debt. At June 30, 2001, Northern Border Pipeline recognized a
non-cash gain in accumulated other comprehensive income of
approximately $8.0 million, with a corresponding amount reflected in
other assets on the accompanying consolidated balance sheet.
Bear Paw Energy, which was acquired by the Partnership in March
2001 (see note 2), periodically enters into commodity derivatives
contracts and fixed-price physical contracts. Bear Paw Energy
primarily utilizes price swaps and collars, which have been
designated as cash flow hedges, to hedge Bear Paw Energy's exposure
to gas and natural gas liquid price volatility. The price swaps and
collars that Bear Paw Energy had in place when it was acquired by
the Partnership were redesignated as hedges upon acquisition. Bear
Paw Energy recognized a non-cash gain in accumulated other
comprehensive income of approximately $5.8 million, with a
corresponding amount reflected in current assets on the accompanying
consolidated balance sheet at June 30, 2001.
9. SUBSEQUENT EVENTS
In July 2001, the Partnership entered into 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. The swaps have been designated as fair
value hedges as they were entered into to hedge the fluctuations in
the market value of the 2001 Partnership Senior Notes.
10. NEW ACCOUNTING PRONOUNCEMENTS
In July 2001, the Financial Accounting Standards Board issued
SFAS No. 141, "Business Combinations," SFAS No. 142, "Goodwill
and Other Intangible Assets," and SFAS No. 143, "Accounting for
Asset Retirement Obligations." SFAS No. 141 requires all business
combinations initiated after June 30, 2001, to be accounted for
using the purchase method. SFAS No. 142 modifies the accounting
and reporting of goodwill and intangible assets. It requires
entities to discontinue the amortization of goodwill, reallocate
goodwill among its reporting segments and perform initial impairment
tests by applying a fair-value-based analysis on the goodwill in
each reporting segment. Subsequent to the initial adoption, goodwill
shall be tested for impairment annually or more frequently if
circumstances indicate a possible impairment. For goodwill and
intangible assets on the balance sheet at June 30, 2001, the
provisions of SFAS No. 142 must be applied to fiscal years beginning
after December 15, 2001. At June 30, 2001, the Partnership's balance
sheet included goodwill of approximately $457 million. Estimated
annual amortization is approximately $16 million. SFAS No. 143
requires entities to record the fair value of a liability for an
asset retirement obligation in the period in which it is incurred.
When the liability is initially recorded, the entity capitalizes a
cost by increasing the carrying amount of the related long-lived
asset. Over time, the liability is accreted to its present value
and the capitalized cost is depreciated over the useful life of
the related asset. Upon settlement of the liability, an entity
either settles the obligation for its recorded amount or incurs a
gain or loss upon settlement. The standard is effective for fiscal
years beginning after June 15, 2002, with earlier application
encouraged. The Partnership is in the process of evaluating the
application of these pronouncements.
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
Results of Operations
Northern Border Partners, L.P. (the "Partnership") owns a 70%
general partner interest in Northern Border Pipeline Company.
Northern Border Pipeline's revenue is derived from agreements with
its shippers for the transportation of natural gas. It transports
gas under a Federal Energy Regulatory Commission ("FERC") regulated
tariff. Northern Border Pipeline had used a cost of service form of
tariff since its inception but agreed to convert to a stated rate
form of tariff as part of the settlement of its rate case discussed
below.
Under the cost of service tariff, Northern Border Pipeline was
provided an opportunity to recover all of the operations and
maintenance costs of the pipeline, taxes other than income taxes,
interest, depreciation and amortization, an allowance for income
taxes and a regulated return on equity. Northern Border Pipeline
was generally allowed to collect from its shippers a return on
regulated rate base as well as recover that rate base through
depreciation and amortization. Billings for the firm transportation
agreements were based on contracted volumes to determine the
allocable share of the cost of service and were not dependent upon
the percentage of available capacity actually used.
Northern Border Pipeline filed a rate proceeding with the FERC in
May 1999 for, among other things, a redetermination of its allowed
equity rate of return. In September 2000, Northern Border Pipeline
filed a stipulation and agreement with the FERC that documented the
proposed settlement of its pending rate case. The settlement was
approved by the FERC in December 2000. Under the approved
settlement, effective December 1, 1999, shippers began paying stated
transportation rates based on a straight-fixed variable rate design.
Under the straight-fixed variable rate design, approximately 98% of
the agreed upon revenue level is attributed to demand charges, based
upon contracted firm capacity, and the remaining 2% is attributed to
commodity charges, based on the volumes of gas actually transported
on the system.
As of December 31, 2000, the termination dates of the shippers'
contracts ranged from October 31, 2001 to December 21, 2013 and the
weighted average contract life was approximately six years with just
under 99% of capacity contracted through mid-September 2003.
Contracts for approximately 44% of the capacity will expire between
mid-September 2003 and the end of October 2005.
Crestone Energy Ventures acquired its interests in Fort Union Gas
Gathering, L.L.C., Lost Creek Gathering, L.L.C., Crestone Gathering
Services, L.L.C. and a portion of Bighorn Gas Gathering, L.L.C. in
September 2000. Prior to that time, Crestone Energy Ventures' sole
asset was its investment in Bighorn Gas Gathering.
During 2001, the following acquisitions have been made: Bear Paw
Energy in late March; the Mazeppa and Gladys sour gas processing
plants, gas gathering systems and a minority interest in the Gregg
Lake/Obed Pipeline in early April; and Midwestern Gas Transmission
in late April (see Note 2 - Notes to Consolidated Financial
Statements).
Second Quarter 2001 Compared With Second Quarter 2000
Operating revenues, net increased $42.9 million (52%) for the
second quarter of 2001, as compared to the same period in 2000, due
primarily to $40.8 million of revenues from the gas gathering and
processing segment. Operating revenues from the interstate pipelines
increased $1.8 million due primarily to $2.2 million of revenues from
Midwestern Gas Transmission. Net operating revenues attributable to
Northern Border Pipeline decreased $0.4 million for the second quarter
of 2001, from the same period in 2000. Northern Border Pipeline's net
operating revenues reflect the rate case settlement discussed above.
Product purchases of $17.5 million recorded in the second quarter
of 2001 represent amounts incurred by Bear Paw. Bear Paw pays
producers for natural gas liquids and residue that it gathers and
processes in its facilities. The amount owed to the producers is
based upon a percentage of the gross proceeds upon sale of the
product.
Operations and maintenance expense increased $10.0 million (68%)
for the second quarter of 2001, as compared to the same period in
2000, due primarily to $10.3 million of expense from the gas
gathering and processing segment. Operations and maintenance
expense from the interstate pipelines decreased $1.3 million due
primarily to a decrease in Northern Border Pipeline's expense by
$1.9 million (17%) partially offset by $0.6 million of expense from
Midwestern Gas Transmission. Northern Border Pipeline's operations
and maintenance expense in 2000 included expenses incurred in
connection with its rate case discussed above.
Depreciation and amortization expense increased $4.9 million
(32%) for the second quarter of 2001, as compared to the same period
in 2000, due primarily to $4.5 million of expense from the gas
gathering and processing segment. Depreciation and amortization
expense from the interstate pipelines increased $0.4 million due
primarily to $0.7 million of expense from Midwestern Gas
Transmission partially offset by a decrease in Northern Border
Pipeline's expense by $0.3 million. Depreciation and amortization
expense in the second quarter of 2001 and 2000 includes goodwill
amortization of consolidated affiliates of $2.3 million and $0.1
million, respectively. See "New Accounting Pronouncements" for
discussion of a recently issued accounting pronouncement that will
impact goodwill amortization in 2002.
Consolidated interest expense increased $5.4 million (28%) for
the second quarter of 2001, as compared to the same period in 2000.
Interest expense for the Partnership increased approximately $7.9
million (322%) for the second quarter of 2001, as compared to the
same period in 2000, due to additional borrowings and an increase in
the Partnership's average interest rate. In June 2000 and September
2000, the Partnership issued $250 million of 8 7/8% Senior Notes and
in March 2001, the Partnership issued $225 million of 7.10% Senior
Notes. The additional borrowings were made primarily for the
acquisition of gas gathering and processing businesses during 2000
and the acquisitions made in March 2001 and April 2001 (see Note 2 -
Notes to Consolidated Financial Statements). Interest expense
attributable to Northern Border Pipeline decreased $2.7 million
(16%) for the second quarter of 2001, as compared to the same period
in 2000, due to a decrease in Northern Border Pipeline's average
interest rate and a decrease in average debt outstanding.
Other income (expense) decreased $1.2 million (86%) for the
second quarter of 2001, as compared to the same period in 2000.
Other income (expense) for the second quarter of 2001 includes a
charge of approximately $1.7 million for an uncollectible receivable
from a telecommunications company that had purchased excess capacity
on Northern Border Pipeline's communication system. In the
second quarter of 2000, Northern Border Pipeline had recorded
approximately $1.2 million of income from the purchase of excess
capacity by the telecommunications company. Equity earnings on
unconsolidated affiliates increased $1.1 million to $0.8 million for
the second quarter of 2001 as compared to the same period in 2000.
Goodwill amortization netted against equity earnings of
unconsolidated affiliates totaled $1.6 million and $0.2 million in
the second quarter of 2001 and 2000, respectively. See "New
Accounting Pronouncements" for discussion of a recently issued
accounting pronouncement that will impact goodwill amortization in
2002.
The extraordinary loss from debt restructuring of $1.2 million
recorded in the second quarter of 2001 relates to Black Mesa's 10.7%
Secured Senior Notes, which were repaid by the Partnership prior to
maturity (see Note 4 - Notes to Consolidated Financial Statements).
Six Months Ended June 30, 2001 Compared With
Six Months Ended June 30, 2000
Operating revenues, net increased $49.4 million (30%) for the
first half of 2001, as compared to the same period in 2000, due
primarily to $46.3 million of revenues from the gas gathering and
processing segment. Operating revenues from the interstate
pipelines increased $2.6 million due primarily to $2.2 million of
revenues from Midwestern Gas Transmission. Net operating revenues
attributable to Northern Border Pipeline increased $0.4 million for
the first half of 2001, from the same period in 2000. Northern
Border Pipeline's net operating revenues reflect the rate case
settlement discussed above.
Product purchases of $17.5 million recorded in the first half of
2001 represent amounts incurred by Bear Paw. Bear Paw pays
producers for natural gas liquids and residue that it gathers and
processes in its facilities. The amount owed to the producers is
based upon a percentage of the gross proceeds upon sale of the
product.
Operations and maintenance expense increased $13.1 million (48%)
for the first half of 2001, as compared to the same period in 2000,
due primarily to $14.3 million of expense from the gas gathering and
processing segment. Operations and maintenance expense from the
interstate pipelines decreased $1.8 million due primarily to a
decrease in Northern Border Pipeline's expense by $2.4 million (12%)
partially offset by $0.6 million of expense from Midwestern Gas
Transmission. Northern Border Pipeline's operations and maintenance
expense in 2000 included expenses incurred in connection with its
rate case discussed above.
Depreciation and amortization expense increased $5.0 million
(16%) for the first half of 2001, as compared to the same period in
2000, due entirely to the gas gathering and processing segment.
Depreciation and amortization expense from the interstate pipelines
remained unchanged between periods due primarily to $0.7 million of
expense from Midwestern Gas Transmission offset by a decrease in
Northern Border Pipeline's expense by $0.7 million. Depreciation
and amortization expense in the first half of 2001 and 2000 includes
goodwill amortization of consolidated affiliates of $2.6 million and
$0.2 million, respectively. See "New Accounting Pronouncements" for
discussion of a recently issued accounting pronouncement that will
impact goodwill amortization in 2002.
Taxes other than income decreased $4.1 million (26%) for the first
half of 2001, as compared to the same period in 2000, due primarily
to Northern Border Pipeline's adjustments to previous estimates of
ad valorem taxes.
Consolidated interest expense increased $8.4 million (22%) for
the first half of 2001, as compared to the same period in 2000.
Interest expense for the Partnership increased approximately $12.2
million (277%) for the first half of 2001, as compared to the same
period in 2000, due to additional borrowings and an increase in the
Partnership's average interest rate. In June 2000 and September
2000, the Partnership issued $250 million of 8 7/8% Senior Notes and
in March 2001, the Partnership issued $225 million of 7.10% Senior
Notes. The additional borrowings were made primarily for the
acquisition of gas gathering and processing businesses during 2000
and the acquisitions made in March 2001 and April 2001 (see Note 2 -
Notes to Consolidated Financial Statements). Interest expense
attributable to Northern Border Pipeline decreased $3.9 million
(12%) for the first half of 2001, as compared to the same period in
2000, due to a decrease in Northern Border Pipeline's average
interest rate and a decrease in average debt outstanding.
Other income (expense) decreased $3.0 million for the first half
of 2001, as compared to the same period in 2000. Other income
(expense) for the first half of 2001 includes a charge of
approximately $1.7 million for an uncollectible receivable from a
telecommunications company that had purchased excess capacity on
Northern Border Pipeline's communication system. In the first half
of 2000, Northern Border Pipeline had recorded approximately $1.2
million of income from the purchase of excess capacity by the
telecommunications company. The results for 2001 also included non-
recurring charges of $2.4 million, primarily related to a loss on a
forward purchase of Canadian dollars to fund the acquisition of
gathering and processing assets in Alberta (see Note 2 - Notes to
Consolidated Financial Statements). Equity earnings on
unconsolidated affiliates increased $1.2 million to $0.6 million for
the first half of 2001 as compared to the same period in 2000.
Goodwill amortization netted against equity earnings of
unconsolidated affiliates totaled $3.1 million and $0.3 million in
the first half of 2001 and 2000, respectively. See "New Accounting
Pronouncements" for discussion of a recently issued accounting
pronouncement that will impact goodwill amortization in 2002.
The extraordinary loss from debt restructuring of $1.2 million
recorded in the first half of 2001 relates to Black Mesa's 10.7%
Secured Senior Notes, which were repaid by the Partnership prior to
maturity (see Note 4 - Notes to Consolidated Financial Statements).
Liquidity and Capital Resources
General
Northern Border Pipeline had previously entered into a 1997
credit agreement ("Pipeline Credit Agreement") with certain
financial institutions, which is comprised of a $200 million five-
year revolving credit facility and a $389 million term loan, both
maturing in June 2002. At June 30, 2001, $85 million was
outstanding under the five-year revolving credit facility. Northern
Border Pipeline intends to refinance a portion of the Pipeline
Credit Agreement in the third quarter of 2001 and refinance any
remaining amounts outstanding by the first quarter of 2002.
At June 30, 2001, Northern Border Pipeline also had outstanding
$184 million of senior notes issued in a $250 million private
placement under a July 1992 note purchase agreement. The note
purchase agreement provides for four series of notes, Series A
through D, maturing between August 2000 and August 2003. The
Series A Notes with a principal amount of $66 million were repaid
in August 2000. The Series B Notes with a principal amount of
$41 million mature in August 2001. Northern Border Pipeline
anticipates borrowing on the Pipeline Credit Agreement to
repay the Series B Notes.
In March 2001, Northern Border Pipeline entered into forward
starting interest rate swaps with notional amounts totaling $200
million related to the planned issuance of 10-year and 30-year fixed
rate debt. The swap instruments may be settled any time prior to
their expiration date on October 1, 2001. The proceeds from the
fixed rate debt will be used to repay outstanding indebtedness.
The Partnership completed a private offering of $150 million of 8
7/8% Senior Notes due 2010 ("2000 Partnership Senior Notes") in June
2000. In September 2000, the Partnership completed an additional
private offering of $100 million of 2000 Partnership Senior Notes.
The 2000 Partnership Senior Notes were subsequently exchanged in a
registered offering for notes with substantially identical terms.
The proceeds from the 2000 Partnership Senior Notes were used in
acquisitions made by the Partnership in June 2000 and September
2000.
In March 2001, the Partnership completed a private offering of
$225 million of 7.10% Senior Notes due 2011 ("2001 Partnership
Senior Notes"). The Partnership has filed a registration
statement with the SEC to exchange the 2001 Partnership Senior
Notes for notes with substantially identical terms and expects
to complete the exchange during the third quarter of 2001. The
indenture under which the 2001 Partnership Senior Notes were
issued does not limit the amount of unsecured debt the Partnership
may incur, but does contain material financial covenants, including
restrictions on incurrence of secured indebtedness. The proceeds
from the 2001 Partnership Senior Notes were used to fund a portion
of the acquisition of Bear Paw Energy (see Note 2 - Notes to
Consolidated Financial Statements).
The Partnership entered into a $200 million three-year revolving
credit agreement with certain financial institutions ("2001
Partnership Credit Agreement") in March 2001. The 2001 Partnership
Credit Agreement is to be used for capital expenditures,
acquisitions and general business purposes. The 2001 Partnership
Credit Agreement replaced revolving credit agreements entered into
in June 2000. At June 30, 2001, $32.0 million was outstanding under
the 2001 Partnership Credit Agreement.
In July 2001, the Partnership entered into 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. The swaps were entered into to hedge
the fluctuations in the market value of the 2001 Partnership Senior
Notes.
In April 2001 and May 2001, the Partnership sold 407,550 and
4,000,000 common units, respectively. In conjunction with the
issuance of the additional common units, including the units issued
for Bear Paw Energy in March 2001 (see Note 2 - Notes to
Consolidated Financial Statements), the Partnership's general
partners made capital contributions to the Partnership to maintain a
2% general partner interest in accordance with the partnership
agreements. The net proceeds of the sale of common units and the
general partners' capital contributions totaled approximately $173.2
million and were primarily used to repay amounts borrowed under the
2001 Partnership Credit Agreement.
Short-term liquidity needs will be met by internal sources and
through the credit facilities discussed above. Long-term capital
needs may be met through the ability to issue long-term indebtedness
as well as additional limited partner interests of the Partnership.
Cash Flows From Operating Activities
Cash flows provided by operating activities increased $3.6
million to $98.4 million for the first half of 2001, as compared to
the same period in 2000, due primarily to an increase in net income.
This was partially offset by net cash outflows of approximately $4.7
million related to Northern Border Pipeline's rate case. During the
first quarter of 2001, Northern Border Pipeline made refunds to its
shippers totaling $6.8 million, which included approximately $2.1
million collected in the first quarter of 2001 with the remainder
collected previously.
Cash Flows From Investing Activities
The investment in unconsolidated affiliates of $6.2 million and
$2.5 million for the first half of 2001 and 2000, respectively,
primarily reflects capital contributions to Bighorn Gas Gathering.
Acquisitions of businesses of $340.2 million for the first half
of 2001 represents acquisitions of Midwestern Gas Transmission and
assets in Alberta, Canada in April 2001 and the cash portion of the
purchase price of Bear Paw Energy in March 2001. The purchase of
Bear Paw Energy also involved the issuance of 5.7 million common
units valued at $183.0 million, for a total purchase price of $381.7
million.
Capital expenditures of $48.0 million for the first half of 2001
include $31.7 million for gas gathering and processing facilities
and $16.3 million for interstate pipeline facilities. The
expenditures for interstate pipeline facilities include $12.4
million for Northern Border Pipeline's Project 2000 (see Note 3 -
Notes to Consolidated Financial Statements). For the same period in
2000, total capital expenditures were $4.1 million, which included
$2.3 million related to Project 2000.
Total capital expenditures, business acquisitions and investments
in unconsolidated affiliates for 2001 are estimated to be $694
million, which includes $578 million expended through the end of the
first half of 2001. Capital expenditures for the interstate
pipelines are estimated to be $79 million, including approximately
$61 million for Northern Border Pipeline's Project 2000. Northern
Border Pipeline currently anticipates funding its 2001 capital
expenditures primarily by using internal sources and borrowing on
the Pipeline Credit Agreement. Capital expenditures for gas
gathering and processing facilities are estimated to be $66 million
and additional investments in unconsolidated affiliates are
estimated to be $20 million for 2001. Total business acquisitions
are estimated to be $529 million. The Partnership anticipates
financing its capital requirements primarily by borrowing on the
2001 Partnership Credit Agreements and by issuing partnership
interests.
Cash Flows From Financing Activities
Cash flows provided by financing activities were $290.0 million
for the first half of 2001 as compared to cash flows used in
financing activities of $36.3 million for the first half of 2000.
Cash distributions to the unitholders and the general partners
increased $14.1 million to $53.4 million. The increase is due
to both an increase in the number of common units outstanding
and an increase in the distribution rate. The distributions paid
in the first and second quarter of 2001 were $0.70 per unit and
$0.7625 per unit, respectively, as compared to $0.65 per unit for
both the first and second quarter of 2000. The net proceeds from
the private offering of the 2001 Partnership Senior Notes totaled
approximately $223.2 million. Borrowings under the 2001 Partnership
Credit Agreement were $200.0 million for the first half of 2001.
The proceeds from the 2001 Partnership Senior Notes and the 2001
Partnership Credit Agreement were primarily used to fund the
acquisition of Bear Paw Energy, Canadian assets and Midwestern
Gas Transmission discussed previously and to repay $47.3 million
of indebtedness outstanding on a prior credit facility. For
the first half of 2001, Northern Border Pipeline recognized a
decrease in bank overdraft of $22.4 million. At December 31, 2000,
Northern Border Pipeline reflected the bank overdraft primarily due
to rate case refund checks outstanding. In March 2001, the
Partnership paid approximately $4.3 million to terminate interest
rate swap agreements (see Note 8 - Notes to Consolidated Financial
Statements). Financing activities for 2001 reflect the issuance of
partnership interests of $173.2 million, which was primarily used to
repay amounts borrowed on the 2001 Partnership Credit Agreement of
$168.0 million (see Note 6 - Notes to Consolidated Financial
Statements).
New Accounting Pronouncements
In July 2001, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards ("SFAS") No. 141,
"Business Combinations," SFAS No. 142, "Goodwill and Other
Intangible Assets," and SFAS No. 143, "Accounting for Asset
Retirement Obligations." See Note 10 - Notes to Consolidated
Financial Statements.
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. Such forward looking statements
include the discussions in "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and in "Notes to
Consolidated Financial Statements" regarding Northern Border
Pipeline's efforts to pursue opportunities to further increase its
capacity, Northern Border Pipeline's plans to issue debt and the
Partnership's anticipated financing plans for its capital requirements.
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 industry results, future demand for natural
gas, availability of supplies of Canadian natural gas, political and
regulatory developments that impact FERC proceedings involving
Northern Border Pipeline, Northern Border Pipeline's success in
sustaining its positions in such proceedings or the success of
intervenors in opposing Northern Border Pipeline's positions,
competitive developments by Canadian and U.S. natural gas
transmission peers, political and regulatory developments in Canada,
and conditions of the capital markets and equity markets.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET 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 debt portfolio in fixed rate debt. The
Partnership also uses interest rate swap agreements to increase the
portion of its fixed rate debt. Since December 31, 2000, there has
not been any material change to the Partnership's interest rate
exposure.
The Partnership's recently acquired gas gathering and processing
businesses are 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 these commodity prices. The
Partnership has hedged a substantial portion of its expected
commodity price risk under these contracts for 2001 and
approximately one-fourth of its expected commodity price risk for
2002.
PART II. OTHER INFORMATION
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
ITEM 1. Legal Proceedings
On July 31, 2001, the Assiniboine and Sioux Tribes of the Fort
Peck Indian Reservation filed a lawsuit in Tribal Court against
Northern Border Pipeline Company to collect more than $3 million in
back taxes, together with interest and penalties. The lawsuit
relates to a utilities tax on certain of Northern Border Pipeline's
properties within the Fort Peck Reservation. Based on recent
decisions by the federal courts and other defenses, the Partnership
believes that the Tribes do not have the authority to impose the tax
and that the lawsuit will not have a material adverse impact on the
Partnership.
ITEM 6. Exhibits and Reports on Form 8-K
(a) Exhibits.
10.27 Employment Agreement between Northern Plains Natural Gas
Company and William R. Cordes effective June 1, 2001.
(b) Reports on Form 8-K.
On May 16, 2001, the Partnership filed a Current Report on
Form 8-K in connection with the public offering of 4,455,218 common
units representing limited partner interests in the Partnership by
the Partnership and Northwest Border Pipeline Company (the "Selling
Unitholder"), and up to 668,282 additional common units by the
Selling Unitholder pursuant to an over-allotment option granted to
the underwriters.
SIGNATURES
Pursuant to the requirements of the Securities and Exchange Act
of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned thereunto duly authorized.
NORTHERN BORDER PARTNERS, L.P.
(A Delaware Limited Partnership)
Date: August 14, 2001 By: JERRY L. PETERS
Jerry L. Peters
Chief Financial and Accounting
Officer