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 September 30, 2000
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)
(877) 208-7318
(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 20
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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, 2000 and 1999
and Nine Months Ended September 30, 2000 and 1999 3
Consolidated Balance Sheet - September 30, 2000
and December 31, 1999 4
Consolidated Statement of Cash Flows -
Nine Months Ended September 30, 2000 and 1999 5
Consolidated Statement of Changes in Partners'
Capital - Nine Months Ended September 30, 2000 6
Notes to Consolidated Financial Statements 7
ITEM 2. Management's Discussion and Analysis of
Financial Condition and Results of Operations 11
ITEM 3. Quantitative and Qualitative Disclosures About
Market Risk 18
PART II. OTHER INFORMATION
ITEM 6. Exhibits and Reports on Form 8-K 19
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<TABLE>
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)
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
2000 1999 2000 1999
<S> <C> <C> <C> <C>
OPERATING REVENUES
Operating revenues $86,755 $79,046 $264,318 $235,953
Provision for rate refunds (3,205) -- (16,715) --
Operating revenues, net 83,550 79,046 247,603 235,953
OPERATING EXPENSES
Operations and maintenance 13,802 13,279 41,360 38,606
Depreciation and amortization 15,333 13,855 46,548 41,037
Taxes other than income 6,532 7,184 22,230 22,366
Operating expenses 35,667 34,318 110,138 102,009
OPERATING INCOME 47,883 44,728 137,465 133,944
INTEREST EXPENSE 20,593 17,238 58,533 49,808
OTHER INCOME 3,336 605 5,149 3,926
MINORITY INTERESTS IN NET INCOME 10,288 8,738 27,735 26,513
NET INCOME TO PARTNERS $20,338 $19,357 $ 56,346 $ 61,549
NET INCOME PER UNIT $ 0.66 $ 0.65 $ 1.85 $ 2.05
NUMBER OF UNITS USED IN COMPUTATION 29,347 29,347 29,347 29,347
<FN>
The accompanying notes are an integral part of these consolidated
financial statements.
</TABLE>
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<TABLE>
PART I. FINANCIAL INFORMATION (Continued)
ITEM 1. FINANCIAL STATEMENTS (Continued)
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(In Thousands)
(Unaudited)
<CAPTION>
September 30, December 31,
ASSETS 2000 1999
<S> <C> <C>
CURRENT ASSETS
Cash and cash equivalents $ 46,119 $ 22,927
Accounts receivable 33,535 30,238
Materials and supplies, at cost 6,668 4,410
Under recovered cost of service -- 3,068
Total current assets 86,322 60,643
TRANSMISSION PLANT
Property, plant and equipment 2,413,378 2,410,133
Less: Accumulated provision for
depreciation and amortization 708,988 664,777
Property, plant and equipment, net 1,704,390 1,745,356
INVESTMENTS AND OTHER ASSETS
Investment in gas gathering businesses 208,705 --
Investment in unconsolidated affiliate 60,331 31,895
Other 29,561 25,543
Total investments and other assets 298,597 57,438
Total assets $2,089,309 $1,863,437
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES
Current maturities of long-term debt $ 44,373 $ 183,617
Accrued distributions payable 21,398 --
Accounts payable 7,079 8,279
Accrued taxes other than income 29,180 26,608
Accrued interest 14,205 17,608
Over recovered cost of service 5,342 --
Accumulated provision for rate refunds 19,660 2,317
Total current liabilities 141,237 238,429
LONG-TERM DEBT, NET OF CURRENT MATURITIES 1,200,051 848,369
MINORITY INTERESTS IN PARTNERS' CAPITAL 248,736 250,450
RESERVES AND DEFERRED CREDITS 8,081 10,920
PARTNERS' CAPITAL
General Partners 9,824 10,305
Common Units 481,380 504,964
Total partners' capital 491,204 515,269
Total liabilities and partners' capital $2,089,309 $1,863,437
<FN>
The accompanying notes are an integral part of these consolidated
financial statements.
</TABLE>
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<TABLE>
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)
<CAPTION>
Nine Months Ended
September 30,
2000 1999
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income to partners $ 56,346 $ 61,549
Adjustments to reconcile net income to partners
to net cash provided by operating activities:
Depreciation and amortization 46,752 41,071
Minority interests in net income 27,735 26,513
Provision for rate refunds, including interest 17,343 --
Changes in components of working capital 4,347 6,189
Other (6,095) 816
Total adjustments 90,082 74,589
Net cash provided by operating activities 146,428 136,138
CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in unconsolidated affiliate (8,766) --
Acquisition of gas gathering businesses (229,505) --
Capital expenditures for property, plant
and equipment (7,506) (90,426)
Net cash used in investing activities (245,777) (90,426)
CASH FLOWS FROM FINANCING ACTIVITIES:
Cash distributions to Unitholders and
General Partners (59,013) (54,870)
Distributions to Minority Interests (29,449) (29,374)
Issuance of long-term debt 431,148 281,026
Proceeds received upon termination of
interest rate forward agreements -- 12,896
Retirement of long-term debt (217,807) (262,076)
Long-term debt financing costs (2,338) (1,561)
Net cash provided by (used in)
financing activities 122,541 (53,959)
NET CHANGE IN CASH AND CASH EQUIVALENTS 23,192 (8,247)
Cash and cash equivalents-beginning of period 22,927 41,042
Cash and cash equivalents-end of period $ 46,119 $ 32,795
Supplemental Disclosures of Cash Flow Information:
Cash paid for:
Interest (net of amount capitalized) $ 64,840 $ 52,809
Changes in components of working capital:
Accounts receivable $ (3,297) $ (8,501)
Materials and supplies (2,258) (176)
Over/under recovered cost of service 8,410 9,905
Accounts payable 2,323 3,290
Accrued taxes other than income 2,572 4,901
Accrued interest (3,403) (3,230)
Total $ 4,347 $ 6,189
<FN>
The accompanying notes are an integral part of these consolidated
financial statements.
</TABLE>
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<TABLE>
PART I. FINANCIAL INFORMATION (Continued)
ITEM 1. FINANCIAL STATEMENTS (Continued)
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' CAPITAL
(In Thousands)
(Unaudited)
<CAPTION>
Total
General Common Partners'
Partners Units Capital
<S> <C> <C> <C>
Partners' Capital at December 31, 1999 $10,305 $504,964 $515,269
Net income to partners 2,159 54,187 56,346
Distributions declared,
payable November 2000 (854) (20,544) (21,398)
Distributions paid to partners (1,786) (57,227) (59,013)
Partners' Capital at September 30, 2000 $ 9,824 $481,380 $491,204
<FN>
The accompanying notes are an integral part of this consolidated
financial statement.
</TABLE>
<PAGE>
PART I. FINANCIAL INFORMATION - (Continued)
ITEM 1. FINANCIAL STATEMENTS - (Continued)
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. 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 generally accepted accounting principles 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, 1999.
The preparation of financial statements in conformity with
generally accepted accounting principles 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 ("Northern Border Pipeline").
Black Mesa Holdings, Inc., Black Mesa Pipeline Operations, L.L.C.
and Crestone Energy Ventures, L.L.C. ("Crestone Energy")(formerly
NBP Energy Pipelines, L.L.C.) are wholly-owned subsidiaries of
the Partnership.
2. In December 1999, Crestone Energy purchased a 39% common
membership interest in Bighorn Gas Gathering, L.L.C. ("Bighorn")
for approximately $31.9 million and in June 2000, Crestone Energy
purchased 80% of class A shares in Bighorn for approximately
$20.8 million. These transactions are reflected as an investment
in unconsolidated affiliate on the Consolidated Balance Sheet at
September 30, 2000.
In September 2000, Crestone Energy purchased interests in gas
gathering businesses in the Powder River and Wind River basins in
Wyoming from Enron North America Corp. ("ENA"), a subsidiary of
Enron Corp., for approximately $208.7 million ("September
Acquisition"). The September Acquisition included the purchase
of a 100% interest in Enron Midstream Services, L.L.C., now known
as Crestone Gathering Services, L.L.C. ("CGS"), a 33.33%
interest in Fort Union Gas Gathering, L.L.C. and a 35% interest
in Lost Creek Gathering, L.L.C. The purchase of CGS increased
Crestone Energy's ownership in Bighorn to a 49% common membership
interest and a 100% interest in the class A shares. The September
Acquisition is reflected as an investment in gas gathering
businesses on the Consolidated Balance Sheet. The Partnership is
currently in the process of allocating the purchase price.
3. In October 1998, Northern Border Pipeline filed a certificate
application with the Federal Energy Regulatory Commission
("FERC") to seek approval to expand and extend its pipeline
system into Indiana ("Project 2000"). When completed, Project
2000 would afford shippers on the expanded and extended pipeline
system access to industrial gas consumers in northern Indiana.
The certificate application was subsequently amended by Northern
Border Pipeline in March and December 1999. On March 16, 2000,
the FERC issued an order granting Northern Border Pipeline's
application 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 estimated to be approximately $94 million.
4. 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. The total annual cost of service
increase due to Northern Border Pipeline's proposed changes was
approximately $30 million. A number of Northern Border
Pipeline's shippers and competing pipelines filed
interventions and protests. 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. The June order and a
subsequent clarification issued by the FERC in August 1999 set
for hearing not only Northern Border Pipeline's proposed changes
but also several issues raised by intervenors including the
appropriateness of Northern Border Pipeline's cost of service
tariff; rolled-in rate treatment of The Chicago Project, which
was Northern Border Pipeline's expansion and extension project
placed in service in December 1998; capital project cost
containment mechanism ("PCCM") amount recorded for The Chicago
Project; depreciation schedule; and creditworthiness standards.
As agreed to in a prior rate case settlement, the PCCM was
implemented to limit Northern Border Pipeline's ability to
include cost overruns on The Chicago Project in rate base and to
provide incentives for cost underruns. The PCCM amount is
computed by comparing the final cost of The Chicago Project to
the budgeted cost, adjusted for the effects of inflation and
project scope changes as defined in the prior rate case
settlement. Testimony filed by the FERC staff and intervenors in
the current rate case proceeding had proposed changes to the PCCM
computation, which would have resulted in rate base reductions
ranging from $32 million to $43 million.
On September 26, 2000, Northern Border Pipeline filed a
stipulation and agreement that documents the proposed settlement
of its pending rate case. The settlement was reached between
Northern Border Pipeline, the majority of its shippers and the
FERC staff and will become effective if and when approved by the
FERC. Northern Border Pipeline anticipates the FERC will act on
the settlement in the first quarter of 2001. If the settlement is
approved, shippers will pay stated transportation rates based on
a straight fixed variable rate design. Under the straight fixed
variable rate design, approximately 98% of the shipper payments
are attributed to demand charges, based upon contracted firm
capacity, and 2% to commodity charges based on the volumes of gas
actually transported on the system. On a per unit of transportation
basis, the rates under the settlement are approximately equal to the
previous rates under the cost of service tariff. The settlement
further provides for the incorporation into Northern Border
Pipeline's rate base all of the construction costs of The Chicago
Project and specifies an annual depreciation rate on transmission
plant of 2.25%. Northern Border Pipeline has netted a provision
for rate refunds against operating revenues to reflect the
significant terms of the settlement in its Statement of Income.
While the proposed settlement agreement has not been opposed by
any of its shippers, Northern Border Pipeline can give no
assurance whether it will be approved by the FERC.
5. In June 2000, the Partnership completed a private offering of
$150 million of 8 7/8% Senior Notes due 2010 ("Partnership Senior
Notes"). The proceeds from the private offering, net of debt
discounts and issuance costs, were primarily used to reduce
existing indebtedness under a November 1997 credit agreement and
to acquire the class A shares in Bighorn (see Note 2). In
September 2000, the Partnership completed a private offering of
an additional $100 million of Partnership Senior Notes. The
proceeds from this offering, along with the proceeds from the
credit agreements described below, were used for the acquisition
of the interests in gas gathering businesses from ENA. The
indenture under which the Partnership Senior Notes were issued
does not limit the amount of indebtedness or other obligations
that the Partnership may incur, but does contain material
financial covenants, including restrictions on the incurrence of
secured indebtedness. In September 2000, the Partnership filed a
registration statement with the SEC to exchange the $250 million
of Partnership Senior Notes for notes with substantially
identical terms. The Partnership expects the exchange will be
completed in the fourth quarter of 2000.
The Partnership entered into interest rate swap agreements
with an aggregate notional principal amount of $150 million in
June 2000. The interest rate swap agreements are scheduled to
terminate in June 2010. Under the agreements, the Partnership
makes payments to counterparties at variable rates based on the
London Interbank Offered Rate (6.66% at September 30, 2000) and
in return receives payments based on an average fixed rate of
7.64%.
In June 2000, the Partnership entered into two credit
agreements with certain financial institutions, a $75 million 364-
day credit agreement and a $75 million three-year revolving
credit agreement (collectively, "Partnership Credit Agreements").
The Partnership Credit Agreements are to be used for
capital expenditures, working capital and general business
purposes. Upon proper notification to the financial
institutions, the maturity date of the Partnership Credit
Agreements may be extended to June 2005. The Partnership Credit
Agreements permit 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 $150 million. At
September 30, 2000, $97.5 million had been borrowed under the
Partnership Credit Agreements primarily for the acquisition of
the interests in gas gathering businesses from ENA. The
Partnership Credit Agreements require the maintenance of a ratio
of debt to total capital, excluding the debt of consolidated
subsidiaries, of no more than 35%. At the closing of the
acquisition from ENA, the Partnership amended the Partnership
Credit Agreements to increase the permitted ratio of debt to
total capital to no more than 45% and gradually decreasing to 35%
by September 30, 2001.
6. 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 distributions paid to partners and
distributions declared amounts shown on the accompanying
consolidated statement of changes in partners' capital include
incentive distributions to the general partners of approximately
$1.1 million.
On September 25, 2000, the Partnership declared a cash
distribution of $0.70 per unit ($2.80 per unit on an annualized
basis) for the quarter ended September 30, 2000. The
distribution is payable November 14, 2000, to unitholders of
record at October 31, 2000.
7. In November 2000, the Partnership sold, through an
underwritten public offering, 1,875,000 Common Units. In
conjunction with the issuance of the additional Common Units, 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 public offering and the general partners' capital
contribution totaled approximately $53 million and were used to
repay amounts borrowed under the Partnership Credit Agreements.
As part of the underwritten public offering, the Partnership
granted the underwriters an over-allotment option to purchase up
to an additional 281,250 Common Units. The underwriters have
exercised the over-allotment option and the Partnership expects
proceeds of approximately $8 million, including the general
partners' capital contribution, to be received on November 14,
2000.
<PAGE>
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"). Northern Border Pipeline's revenue
is derived from agreements with various shippers for the
transportation of natural gas. It transports gas under a Federal
Energy Regulatory Commission ("FERC") regulated tariff. Northern
Border Pipeline has used a cost of service form of tariff since
its inception but has agreed to convert to stated rates as part
of a settlement of its current rate case discussed below.
The cost of service tariff provides Northern Border Pipeline
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 is generally allowed to collect from its
shippers a return on regulated rate base as well as recover that
rate base through depreciation and amortization. The return
amount Northern Border Pipeline may collect from its shippers
declines as the rate base is recovered. Billings for the firm
transportation agreements are based on contracted volumes to
determine the allocable share of the cost of service and are 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. 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.
On September 26, 2000, Northern Border Pipeline filed a
stipulation and agreement that documents the proposed settlement
of its pending rate case. The settlement was reached between
Northern Border Pipeline, the majority of its shippers and the
FERC staff and will become effective if and when approved by the
FERC. Northern Border Pipeline anticipates the FERC will act on
the settlement in the first quarter of 2001. If the settlement
is approved, shippers will pay stated transportation rates based
on a straight fixed variable rate design. Under the straight
fixed variable rate design, approximately 98% of the shipper
payments are attributed to demand charges, based upon contracted
firm capacity, and 2% to commodity charges based on the volumes
of gas actually transported on the system. On a per unit of
transportation basis, the rates under the settlement are
approximately equal to the previous rates under the cost of
service tariff. The settlement further provides for the
incorporation into Northern Border Pipeline's rate base all
of the construction costs of The Chicago Project, which was
Northern Border Pipeline's expansion and extension project
placed in service in December 1998, and specifies an annual
depreciation rate on transmission plant of 2.25%. Under the
settlement, both Northern Border Pipeline and its existing
shippers will not be able to seek rate changes until November 1,
2005. Northern Border Pipeline's earnings and cash flow will
depend on its future costs, contracted capacity, the volumes
of gas transported and its ability to recontract capacity at
acceptable rates. Northern Border Pipeline has netted a provision
for rate refunds against operating revenues to reflect the significant
terms of the settlement in its Statement of Income. While the
proposed settlement agreement has not been opposed by any of its
shippers, Northern Border Pipeline can give no assurance whether
it will be approved by the FERC.
Third Quarter 2000 Compared With Third Quarter 1999
Operating revenues, net increased $4.5 million (6%) for the
third quarter of 2000, as compared to the same period in 1999,
due primarily to a $4.3 million increase in net operating
revenues of Northern Border Pipeline. Northern Border Pipeline's
net operating revenues for 2000 reflect the significant terms of
the settlement discussed previously. Operating revenues for 1999
were determined under Northern Border Pipeline's cost of service
tariff.
Depreciation and amortization expense increased $1.5 million
(11%) for the third quarter of 2000, as compared to the same
period in 1999, due primarily to an increase in the depreciation
rate applied to Northern Border Pipeline's transmission plant.
As required by its cost of service tariff, Northern Border
Pipeline used a depreciation rate of 2.0% for all of 1999, which
was increased to 2.3% beginning January 1, 2000.
Interest expense increased $3.4 million (19%) for the third
quarter of 2000, as compared to the same period in 1999.
Interest expense for Northern Border Pipeline increased
approximately $1.0 million, due primarily to an increase in
interest rates between 1999 and 2000. Interest expense for the
Partnership increased approximately $2.4 million, due to
additional borrowings and an increase in interest rates. The
additional borrowings were made primarily for the acquisition of
a 39% common membership interest and 80% of the non-voting class
A shares in Bighorn Gas Gathering, L.L.C. ("Bighorn") and the
acquisition of gas gathering businesses in the Powder River and
Wind River basins in Wyoming (see Note 2 - Notes to Consolidated
Financial Statements).
Other income increased $2.7 million for the third quarter of
2000, as compared to the same period in 1999. Other income for
Northern Border Pipeline increased $2.6 million, due primarily to
a reduction in reserves previously established for regulatory
issues.
Nine Months September 30, 2000 Compared With Nine Months Ended
September 30, 1999
Operating revenues, net increased $11.7 million (5%) for the
first nine months of 2000, as compared to the same period in
1999, due primarily to a $11.2 million increase in net operating
revenues of Northern Border Pipeline. Northern Border Pipeline's
net operating revenues for 2000 reflect the significant terms of
the settlement discussed previously. Operating revenues for 1999
were determined under Northern Border Pipeline's cost of service
tariff.
Operations and maintenance expense increased $2.8 million (7%)
for the first nine months of 2000, as compared to the same period
in 1999, due primarily to increased administrative expenses for
Northern Border Pipeline.
Depreciation and amortization expense increased $5.5 million
(13%) for the first nine months of 2000, as compared to the same
period in 1999, due primarily to an increase in the depreciation
rate applied to Northern Border Pipeline's transmission plant.
As required by its cost of service tariff, Northern Border
Pipeline used a depreciation rate of 2.0% for all of 1999, which
was increased to 2.3% beginning January 1, 2000.
Interest expense increased $8.7 million (18%) for the first
nine months of 2000, as compared to the same period in 1999.
Interest expense for Northern Border Pipeline increased
approximately $4.7 million, due primarily to an increase in
interest rates between 1999 and 2000. Interest expense for the
Partnership increased approximately $4.3 million, due to
additional borrowings and an increase in interest rates. The
additional borrowings were made primarily for the acquisition of
a 39% common membership interest and 80% of the non-voting class
A shares in Bighorn and the acquisition of gas gathering
businesses in the Powder River and Wind River basins in Wyoming
(see Note 2 - Notes to Consolidated Financial Statements).
Other income increased $1.2 million (31%) for the first nine
months of 2000, as compared to the same period in 1999. The 2000
results reflect a reduction in Northern Border Pipeline's
reserves previously established for regulatory issues of $2.7
million. Additionally, the 2000 results include $1.4 million of
income earned from third-party usage of capacity on Northern
Border Pipeline's microwave system. The 1999 results included
$3.0 million of other non-operating income.
Liquidity and Capital Resources
General
In August 1999, Northern Border Pipeline completed a private
offering of $200 million of 7.75% Senior Notes due 2009, which
notes were subsequently exchanged in a registered offering for
notes with substantially identical terms ("Pipeline Senior
Notes"). The proceeds from the Pipeline Senior Notes were used
to reduce indebtedness under a June 1997 credit agreement.
Northern Border Pipeline entered into a credit agreement
("Pipeline Credit Agreement") with certain financial institutions
in June 1997. The Pipeline Credit Agreement is comprised of a
term loan and a $200 million five-year revolving credit facility,
both maturing in June 2002. At September 30, 2000, $424.0
million was outstanding under the term loan and $60.0 million
were outstanding under the revolving credit facility.
At September 30, 2000, Northern Border Pipeline also had
outstanding $184 million of senior notes issued in a 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 primarily by borrowing under the Pipeline Credit
Agreement. The Series B Notes with a principal amount of $41
million mature in August 2001.
In June 2000, the Partnership completed a private offering of
$150 million of 8 7/8% Senior Notes due 2010 ("Partnership Senior
Notes"). In September 2000, the Partnership completed an
additional private offering of $100 million of Partnership Senior
Notes. In September 2000, the Partnership filed a registration
statement with the Securities and Exchange Commission to exchange
the Partnership Senior Notes for notes with substantially
identical terms. The Partnership expects the exchange will be
completed in the fourth quarter of 2000. The proceeds from the
Partnership Senior Notes were used in acquisitions made by the
Partnership in June 2000 and September 2000 (see Note 2 - Notes
to Consolidated Financial Statements).
The Partnership entered into interest rate swap agreements
with an aggregate notional principal amount of $150 million in
June 2000. The interest rate swap agreements are scheduled to
terminate in June 2010. Under the agreements, the Partnership
makes payments to counterparties at variable rates based on the
London Interbank Offered Rate (6.66% at September 30, 2000) and
in return receives payments based on an average fixed rate of
7.64%.
In June 2000, the Partnership entered into two credit
agreements with certain financial institutions, a $75 million 364-
day credit agreement and a $75 million three-year revolving
credit agreement (collectively, "Partnership Credit Agreements").
The Partnership Credit Agreements are to be used for capital
expenditures, working capital and general business purposes.
Upon proper notification to and consent of the financial
institutions, the maturity date of the Partnership Credit
Agreements may be extended to June 2005. Prior to the
termination of the Partnership Credit Agreements, the Partnership
may request an increase in the commitment level to a maximum $200
million in the aggregate for both agreements. At September 30,
2000, $97.5 million had been borrowed under the Partnership
Credit Agreements. The proceeds were used in acquisitions made
by the Partnership in September 2000 (see Note 2 - Notes to
Consolidated Financial Statements).
In November 2000, the Partnership sold, through an
underwritten public offering, 1,875,000 Common Units. In
conjunction with the issuance of the additional Common Units, 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 public offering and the general partners' capital
contribution totaled approximately $53 million and were used to
repay amounts borrowed under the Partnership Credit Agreements.
As part of the underwritten public offering, the Partnership
granted the underwriters an over-allotment option to purchase up
to an additional 281,250 Common Units. The underwriters have
exercised the over-allotment option and the Partnership expects
proceeds of approximately $8 million, including the general
partners' capital contribution, to be received on November 14,
2000.
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 $10.3
million to $146.4 million for the first nine months of 2000, as
compared to the same period in 1999 primarily due to the billings
collected subject to refund related to Northern Border Pipeline's
current rate proceeding (see Note 4 - Notes to Consolidated
Financial Statements).
Cash Flows From Investing Activities
The investment in unconsolidated affiliate for the first nine
months of 2000 reflect capital contributions of $8.8 million to
Bighorn for construction of gas gathering facilities. The
Partnership has agreed to make additional capital contributions
to Bighorn for construction of gas gathering facilities.
The Partnership's capital contributions to Bighorn are estimated
to be approximately $10 million in 2000. The Partnership
anticipates financing its obligations using the Partnership
Credit Agreements.
The acquisition of gas gathering businesses for the first nine
months of 2000 include the acquisition of gas gathering
businesses in the Powder River and Wind River basins in Wyoming
for approximately $208.7 million and the acquisition of 80% of
the non-voting class A shares in Bighorn for approximately $20.8
million (see Note 2 - Notes to Consolidated Financial
Statements).
Capital expenditures of $7.5 million for the first nine months
of 2000 included $3.3 million for Project 2000 (see Note 3 -
Notes to Consolidated Financial Statements). For the comparable
period in 1999, capital expenditures were $90.4 million and
included $78.3 million for The Chicago Project. The remaining
capital expenditures for 2000 and 1999 were primarily related to
renewals and replacements of existing facilities.
Total capital expenditures for 2000 are estimated to be $26
million. Capital expenditures for Northern Border Pipeline are
estimated to be $18 million, including $8 million for Project
2000 and $10 million primarily for renewals and replacements of
existing facilities. Northern Border Pipeline currently
anticipates funding its 2000 capital expenditures primarily by
using internal sources and borrowing on its revolving credit
facility. Capital expenditures and equity investments for
Crestone Energy Ventures, L.L.C. ("Crestone Energy") are
estimated to be $7 million for 2000. The Partnership anticipates
financing Crestone Energy's capital expenditures and equity
investments primarily by using the Partnership Credit Agreements.
Cash Flows From Financing Activities
Cash flows provided by financing activities was $122.5 million
for the first nine months of 2000 compared to cash flows used of
$54.0 million for the same period in 1999. Cash distributions to
the unitholders and the general partners increased $4.1 million
to $59.0 million reflecting an increase in the quarterly
distribution from $0.61 per Unit to $0.65 per Unit. The
distribution for the fourth quarter of 2000 of $0.70 per Unit was
declared in September 2000 to be paid in November 2000. The
proceeds from the private offering of the Partnership Senior
Notes including premiums but net of associated debt discounts and
issuance costs, totaled approximately $252.0 million. The net
proceeds were used to repay the Partnership's existing
indebtedness of $119.5 million, to fund the acquisition of the
Bighorn class A shares of $20.8 million and to partially fund the
acquisition of gas gathering businesses discussed previously.
The funding for the remainder of the gas gathering businesses
came from borrowings under the Partnership Credit Agreements
of $97.5 million. In August 2000, Northern Border Pipeline
repaid its Series A Notes of $66 million primarily by
borrowing under the Pipeline Credit Agreement. Under the
Pipeline Credit Agreement, borrowings totaled $75 million
and repayments totaled $30 million during the nine months
ended September 30, 2000. Financing activities for the nine
months ended September 30, 1999, included $197.5 million from the
issuance of the Senior Notes, net of associated debt discounts
and issuance costs, and $12.9 million from the termination of the
interest rate forward agreements. Advances under the Pipeline
Credit Agreement, which were primarily used to finance a portion
of the capital expenditures for The Chicago Project, were $82.0
million for the nine months ended September 30, 1999. During the
nine months ended September 30, 1999, $255.0 million was repaid
on the Pipeline Credit Agreement.
New Accounting Pronouncement
In 1998, the Financial Accounting Standards Board issued SFAS
No. 133, "Accounting for Derivative Instruments and Hedging
Activities." SFAS No. 133 establishes accounting and reporting
standards requiring 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 must formally
document, designate and assess the effectiveness of transactions
that receive hedge accounting.
In June 1999, the FASB issued SFAS No. 137, which deferred the
effective date of SFAS No. 133 to fiscal years beginning after
June 15, 2000. In June 2000, the FASB issued SFAS No. 138, which
amended certain guidance within SFAS No. 133. The Partnership
plans to adopt SFAS No. 133 beginning January 1, 2001. The
Partnership believes that SFAS No. 133 (as amended) will not have
a material impact on its financial position or results of
operations.
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 and Northern Border Pipeline's
efforts to finalize settlement of its rate case. 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, Northern Border Pipeline's
ability to replace its rate base as it is depreciated and
amortized, 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 the
portion of its consolidated debt portfolio subject to variable
rates. To mitigate potential fluctuations in interest rates, the
Partnership maintains a significant portion of its consolidated
debt portfolio in fixed rate debt. The Partnership also uses
interest rate swap agreements to manage its level of exposure to
interest rate changes. The Partnership's annual interest rate
exposure from a hypothetical 1% increase in interest rates was
$6.9 million at September 30, 2000, as compared to $5.1 million
at December 31, 1999. Approximately $4.4 million of the
September amount would result from applying the hypothetical 1%
increase in interest rates to Northern Border Pipeline's
outstanding debt portfolio. In its Annual Report on Form 10-K
for the year ended December 31, 1999, the Partnership reported
that Northern Border Pipeline would be able to recover an
increase in interest expense under its cost of service tariff, if
an increase were to occur. If the rate case settlement is
approved (see Note 4 - Notes to Consolidated Financial
Statements), Northern Border Pipeline would bear the risk for an
increase in interest rates.
<PAGE>
PART II. OTHER INFORMATION
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
ITEM 6. Exhibits and Reports on Form 8-K
(a) Exhibits.
None.
(b) Reports on Form 8-K.
The company filed a Current Report on Form 8-K, dated
September 26, 2000, reporting the filing of a stipulation and
agreement with the FERC to document the proposed settlement of
Northern Border Pipeline Company's pending rate case.
<PAGE>
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: November 13, 2000 By: JERRY L. PETERS
Jerry L. Peters
Chief Financial and Accounting
Officer
