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UNITED STATES SECURITIES AND EXCHANGE
COMMISSION
WASHINGTON, D.C. 20549
_______________________
F O R M 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 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 (I.R.S. Employer
of incorporation or organization) Identification No.)
1400 Smith Street, Houston, Texas 77002-7369
(Address of principal executive offices)(zip code)
Registrant's telephone number, including area code: 713-853-6161
___________________
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
Common Units New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months
(or for such shorter period that the registrant was required to
file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes X No _
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of Regulation S-K is not contained herein,
and will not be contained, to the best of registrant's knowledge,
in definitive proxy or information statements incorporated by
reference in Part III of this Form 10-K or any amendment to this
Form 10-K. X
Aggregate market value of the Common Units held by non-
affiliates of the registrant, based on closing prices in the
daily composite list for transactions on the New York Stock
Exchange on March 2, 2001, was approximately $995,168,848.
NORTHERN BORDER PARTNERS, L.P.
TABLE OF CONTENTS
Page No.
Part I
Item 1. Business 1
Item 2. Properties 13
Item 3. Legal Proceedings 14
Item 4. Submission of Matters to a Vote of Security
Holders 14
Part II
Item 5. Market for Registrant's Common Units and Related
Security Holder Matters 15
Item 6. Selected Financial Data 16
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations 17
Item 7a. Quantitative and Qualitative Disclosures
About Market Risk 24
Item 8. Financial Statements and Supplementary Data 24
Item 9. Changes in and Disagreements With Accountants on
Accounting and Financial Disclosure 24
Part III
Item 10. Partnership Management 25
Item 11. Executive Compensation 28
Item 12. Security Ownership of Certain Beneficial Owners
and Management 33
Item 13. Certain Relationships and Related Transactions 33
Part IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K. 36
PART I
Item 1. Business
General
We are a publicly traded limited partnership and a
leading transporter of natural gas imported from Canada to
the United States. We, through our subsidiary limited
partnership, Northern Border Intermediate Limited
Partnership, collectively referred to herein as
"Partnership", own a 70% general partner interest in
Northern Border Pipeline Company, a Texas general
partnership. In addition, Crestone Energy Ventures, L.L.C.
and Black Mesa Pipeline Company are wholly-owned subsidiaries
of the Partnership. Our general partners and the general
partners of the intermediate limited partnership are Northern
Plains Natural Gas Company and Pan Border Gas Company, both
subsidiaries of Enron Corp., and Northwest Border Pipeline
Company, a subsidiary of The Williams Companies, Inc.
Our general partners hold an aggregate 2% general
partner interest in the Partnership. The general partners
or their affiliates also own common units representing an
aggregate 13.5% limited partner interest. The combined
general and limited partner interests in the Partnership
held by Enron and Williams are 11.7% and 3.8%, respectively
(See Item 13. "Certain Relationships and Related
Transactions"). The Partnership is managed by or under the
direction of the Partnership Policy Committee consisting of
three members, each of whom has been appointed by one of the
general partners (See Item 10. "Partnership Management").
Northern Border Pipeline owns an interstate pipeline
system that transports natural gas from the Montana-
Saskatchewan border to natural gas markets in the midwestern
United States. This pipeline system connects with multiple
pipelines that provide shippers with access to the various
natural gas markets served by those pipelines. In the year
ended December 31, 2000, we estimate that Northern Border
Pipeline transported approximately 22% of the total amount
of natural gas imported from Canada to the United States.
Over the same period, approximately 90% of the natural gas
transported was produced in the western Canadian sedimentary
basin located in the provinces of Alberta, British Columbia
and Saskatchewan.
Northern Border Pipeline transports gas for shippers
under a tariff regulated by the Federal Energy Regulatory
Commission ("FERC"). The tariff specifies the calculation
of amounts to be paid by shippers and the general terms and
conditions of transportation service on the pipeline system.
Northern Border Pipeline's revenues are derived from
agreements for the receipt and delivery of gas at points
along the pipeline system as specified in each shipper's
individual transportation contract. Northern Border
Pipeline does not own the gas that it transports, and
therefore it does not assume the related natural gas
commodity risk.
Our interest in Northern Border Pipeline represents the
largest proportion of our assets, earnings and cash flows.
The remaining 30% general partner interest in Northern
Border Pipeline is owned by TC PipeLines Intermediate
Limited Partnership, a subsidiary limited partnership of TC
PipeLines, LP, a publicly traded partnership. The general
partner of TC PipeLines and its subsidiary limited
partnership is TC PipeLines GP, Inc., which is a subsidiary
of TransCanada PipeLines Limited.
Management of Northern Border Pipeline is overseen by
the Northern Border Management Committee, which is comprised
of three representatives from the Partnership (one
designated by each general partner) and one representative
from TC PipeLines. Voting power on the management committee
is presently allocated among Northern Border Partners' three
representatives in proportion to their general partner
interests in Northern Border Partners. As a result, the 70%
voting power of our three representatives on the management
committee is allocated as follows: 35% to the representative
designated by Northern Plains, 22.75% to the representative
designated by Pan Border and 12.25% to the representative
designated by Northwest Border. Therefore, Enron controls
57.75% of the voting power of the management committee and
has the right to select two of the members of the management
committee. For a discussion of specific relationships with
affiliates, refer to Item 13. "Certain Relationships and
Related Transactions."
The pipeline system is operated by Northern Plains
pursuant to an operating agreement. Northern Plains employs
approximately 200 individuals located at the operating
headquarters in Omaha, Nebraska, and at various locations
along the pipeline route. Northern Plains' employees are
not represented by any labor union and are not covered by
any collective bargaining agreements.
In September 2000, we purchased interests in gas
gathering businesses in the Powder River and Wind River
Basins in Wyoming for approximately $209 million from Enron
North America. The transaction included the purchase of
Enron Midstream Services, L.L.C., now known as Crestone
Gathering Services, L.L.C., and ownership interests in
Bighorn Gas Gathering, L.L.C. ("Bighorn"), Fort Union Gas
Gathering, L.L.C. ("Fort Union") and Lost Creek Gathering,
L.L.C. ("Lost Creek"). The transaction added to our
previous ownership in Bighorn. Through our wholly owned
subsidiary, Crestone Energy Ventures, we own 100% of
Crestone Gathering Services, a 49% interest in Bighorn, a
33% interest in Fort Union and a 35% interest in Lost Creek,
which collectively own over 300 miles of gas gathering
facilities in Wyoming. Crestone Gathering Services provides
gas gathering services to third parties. The gathering
facilities interconnect to the interstate gas pipeline grid
serving gas markets in the Rocky Mountains, the Midwest and
California. The Bighorn and Fort Union systems gather coal
seam methane gas produced in the Powder River basin in
northeastern Wyoming. Under various agreements, the
majority of which are long-term, producers have dedicated
their reserves to Bighorn, giving Bighorn the right to
gather coal seam methane gas produced in areas of Wyoming
covering 800,000 acres. Bighorn's system is capable of
gathering more that 250 million cubic feet per day of coal
bed methane gas for delivery to the Fort Union gathering
system. The Fort Union gathering system is capable of
delivering more than 450 million cubic feet per day of coal
seam methane gas into the interstate pipeline grid. Fort
Union has announced a planned expansion to increase capacity
to 634 million cubic feet per day that is expected to be in
service in October 2001. The Lost Creek system gathers
natural gas produced from conventional gas wells in the Wind
River basin in central Wyoming and consists of 106 miles of
gathering header. The system is capable of delivering more
than 275 million cubic feet per day of gas into the
interstate pipeline grid.
CMS Field Services, Inc. holds the remaining ownership
interest in Bighorn and is the project manager and operator.
The Bighorn system is managed through a management committee
consisting of representatives of the owners. CMS Field
Services, CIG Resources Company, Western Gas Resources and
Barrett Resources hold the remaining interest in Fort Union.
CMS Field Services is the managing member, Western Gas
Resources is the field operator and CIG is the
administrative manager. Burlington Resources Trading, Inc.
holds the remaining interest in Lost Creek and is the
managing member. A subsidiary of Crestone Energy Ventures
is the commercial and administrative manager. The system is
operated by Elkhorn Field Services Company.
NBP Services Corporation, an Enron subsidiary, provides
administrative services for us and operating services for
Crestone Energy Ventures. NBP Services Corporation has 22
employees and utilizes employees of its affiliates to
provide these services.
We also own Black Mesa Pipeline Company. Black Mesa
owns a 273-mile, 18-inch diameter coal slurry pipeline which
originates at a coal mine in Kayenta, Arizona. The coal
slurry pipeline transports crushed coal suspended in water.
It traverses westward through northern Arizona to the 1,500
megawatt Mohave Power Station located in Laughlin, Nevada.
The coal slurry pipeline is the sole source of fuel for the
Mohave Power Station, which consumes an average of 4.8
million tons of coal annually. The capacity of the pipeline
is fully contracted to the coal supplier for the Mohave
Power Station through the year 2005. The pipeline is
operated by Black Mesa Pipeline Operations, LLC, a
wholly-owned subsidiary of the Partnership. Approximately
58 people are employed in the operations of Black Mesa, of
which 26 are represented by a labor union, the United Mine
Workers.
Pending Acquisitions
In March 2001, we signed a definitive agreement for the
acquisition of Midwestern Gas Transmission from El Paso
Corporation for approximately $100 million. The Midwestern
system is a 350-mile interstate natural gas pipeline
extending from Portland, Tennessee to Joliet, Illinois.
Midwestern connects to Northern Border Pipeline and other
major interstate pipeline systems including Alliance
Pipeline, Tennessee Gas Pipeline, Trunkline and Texas Gas
Transmission to provide bi-directional service to markets in
Kentucky, Indiana, southern Illinois and the Joliet/Chicago
market hub. The acquisition is expected to close in the
second quarter of this year, subject to the receipt of all
necessary approvals.
In March 2001, we signed a definitive agreement to
purchase Bear Paw Energy, L.L.C. The purchase price is
approximately $366 million to be paid with 5.7 million of
our common units and $183 million in cash, of which $98.2
million will be used to retire debt of Bear Paw Energy with
the remainder payable to the sellers. An additional $6
million will be payable in February 2002, if certain
performance criteria are met. The purchase is targeted for
completion by the end of the first quarter of this year.
Bear Paw Energy has extensive gathering and processing
operations in the Powder River Basin in Wyoming and the
Williston Basin in Montana, North Dakota and Saskatchewan.
Bear Paw Energy has approximately 226,000 leasehold
production acres under dedication and 600 miles of high and
low pressure 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.
In February 2001, we signed a purchase and sale
agreement to purchase the Mazeppa Plant, Gladys Plant and a
minority interest in the Gregg Lake/Obed Pipeline, all of
which are located in Alberta, Canada, from Dynegy Canada,
Inc. The purchase price, which is subject to adjustment, is
approximately $46 million. The Mazeppa Plant is a sour gas
processing plant with 87 million cubic feet per day of
combined capacity and associated gathering pipelines. The
Gladys Plant is a sour gas processing plant with 7 million
cubic feet per day of capacity. The Gregg Lake/Obed
Pipeline is comprised of 85 miles of gathering lines with a
capacity of 150 million cubic feet per day. We are
targeting to close on this transaction by the end of March
2001.
The Northern Border Pipeline System
Northern Border Pipeline owns a 1,214-mile United
States interstate pipeline system that transports natural
gas from the Montana-Saskatchewan border near Port of
Morgan, Montana, to interconnecting pipelines in the upper
Midwest of the United States. Construction of the pipeline
was initially completed in 1982. The pipeline system was
expanded and/or extended in 1991, 1992 and 1998.
The pipeline system has pipeline access to natural gas
reserves in the western Canadian sedimentary basin in the
provinces of Alberta, British Columbia and Saskatchewan in
Canada, as well as the Williston Basin in the United States.
The pipeline system also has access to synthetic gas
produced at the Dakota Gasification plant in North Dakota.
For the year ended December 31, 2000, of the natural gas
transported on the system, approximately 90% was produced in
Canada, approximately 5% was produced by the Dakota
Gasification plant, and approximately 5% was produced in the
Williston Basin.
The pipeline system consists of 822 miles of 42-inch
diameter pipe designed to transport 2,373 million cubic feet
per day ("mmcfd") from the Canadian border to Ventura, Iowa;
30-inch diameter pipe and 36-inch diameter pipe, each
approximately 147 miles in length, designed to transport
1,300 mmcfd in total from Ventura, Iowa to Harper, Iowa; and
226 miles of 36-inch diameter pipe and 19 miles of 30-inch
diameter pipe designed to transport 645 mmcfd from Harper,
Iowa to a terminus near Manhattan, Illinois (Chicago area).
Along the pipeline there are 15 compressor stations with
total rated horsepower of 476,500 and measurement facilities
to support the receipt and delivery of gas at various
points. Other facilities include four field offices and a
microwave communication system with 51 tower sites.
At its northern end, the pipeline system is connected
to TransCanada's majority-owned Foothills Pipe Lines (Sask.)
Ltd. system in Canada, which is connected to TransCanada's
Alberta system and the pipeline system owned by Transgas
Limited in Saskatchewan. The Alberta system gathers and
transports approximately 18% of the total North American
natural gas production and approximately 74% of the natural
gas produced in the western Canadian sedimentary basin. The
pipeline system also connects with facilities of Williston
Basin Interstate Pipeline at Glen Ullin and Buford, North
Dakota, facilities of Amerada Hess Corporation at Watford
City, North Dakota and facilities of Dakota Gasification
Company at Hebron, North Dakota in the northern portion of
the pipeline system.
Interconnects
The pipeline system connects with multiple pipelines
that provide its shippers with access to the various natural
gas markets served by those pipelines. The pipeline system
interconnects with pipeline facilities of:
* Northern Natural Gas Company, an Enron subsidiary, at
Ventura, Iowa as well as multiple smaller
interconnections in South Dakota, Minnesota and Iowa;
* Natural Gas Pipeline Company of America at Harper,
Iowa;
* MidAmerican Energy Company at Iowa City and Davenport,
Iowa and Cordova, Illinois;
* Alliant Power Company at Prophetstown, Illinois;
* Northern Illinois Gas Company at Troy Grove and
Minooka, Illinois;
* Midwestern Gas Transmission Company near Channahon,
Illinois;
* ANR Pipeline Company near Manhattan, Illinois; and
* The Peoples Gas Light and Coke Company near Manhattan,
Illinois at the terminus of the pipeline system.
The Ventura, Iowa interconnect with Northern Natural
Gas Company functions as a large market center, where
natural gas transported on the pipeline system is sold,
traded and received for transport to significant consuming
markets in the Midwest and to interconnecting pipeline
facilities destined for other markets.
Shippers
The pipeline system serves more than 50 firm
transportation shippers with diverse operating and financial
profiles. Based upon shippers' contractual obligations, as
of December 31, 2000, 92% of the firm capacity is contracted
by producers and marketers. The remaining firm capacity is
contracted to local distribution companies (5%), interstate
pipelines (2%) and end-users (1%). As of December 31, 2000,
the termination dates of these contracts ranged from October
31, 2001 to December 21, 2013 and the weighted average
contract life, based upon annual contractual obligations,
was approximately six years with just under 99% of capacity
contracted through mid-September 2003.
Based on their proportionate shares of capacity, as of
December 31, 2000, the five largest shippers are: Pan-
Alberta Gas (U.S.) Inc. (25.5%), TransCanada Energy
Marketing USA, Inc. (11.4%), PanCanadian Energy Services Inc
(7.3%), Enron North America Corp. (6.3%) and Engage Energy
US, LP. (5.4%). The 20 largest shippers, in total, are
responsible for approximately 93% of total revenues.
As of December 31, 2000, the largest shipper, Pan-
Alberta, holds firm capacity of 690 mmcfd under three
contracts with terms to October 31, 2003. An affiliate of
Enron provides guaranties for 300 mmcfd of Pan-Alberta's
contractual obligations through October 31, 2001. In
addition, Pan-Alberta's remaining capacity is supported by
various credit support arrangements, including, among
others, a letter of credit, a guaranty from an interstate
pipeline company through October 31, 2001 for 132 mmcfd, an
escrow account and an upstream capacity transfer agreement.
Mirant Americas Energy Marketing, LP, formerly Southern
Company Energy Marketing L.P., manages the assets of Pan-
Alberta Gas, Ltd., which include Pan-Alberta's contracts
with Northern Border Pipeline.
Some of the shippers are affiliated with the general
partners of Northern Border Pipeline. TransCanada Energy
Marketing USA, Inc., a subsidiary of TransCanada, holds firm
contracts representing 11.4% of capacity. Enron North
America Corp., a subsidiary of Enron, holds firm contracts
representing 6.3% of capacity. Transcontinental Gas Pipe
Line Corporation, a subsidiary of Williams, holds a contract
representing 0.8% of capacity. See Item 13. "Certain
Relationships and Related Transactions."
Demand For Transportation Capacity
Northern Border Pipeline's long-term financial
condition is dependent on the continued availability of
economic western Canadian natural gas for import into the
United States. Natural gas reserves may require significant
capital expenditures by others for exploration and
development drilling and the installation of production,
gathering, storage, transportation and other facilities that
permit natural gas to be produced and delivered to pipelines
that interconnect with the pipeline system. Low prices for
natural gas, regulatory limitations or the lack of available
capital for these projects could adversely affect the
development of additional reserves and production,
gathering, storage and pipeline transmission of western
Canadian natural gas supplies. Additional pipeline export
capacity also could accelerate depletion of these reserves.
Northern Border Pipeline's business depends in part on
the level of demand for western Canadian natural gas in the
markets the pipeline system serves. The volumes of natural
gas delivered to these markets from other sources affect the
demand for both western Canadian natural gas and use of the
pipeline system. Demand for western Canadian natural gas to
serve other markets also influences the ability and
willingness of shippers to use the pipeline system to meet
demand in the markets that the pipeline serves.
A variety of factors could affect the demand for
natural gas in the markets that the pipeline system serves.
These factors include:
* economic conditions;
* fuel conservation measures;
* alternative energy requirements and prices;
* climatic conditions;
* government regulation; and
* technological advances in fuel economy and energy
generation devices.
We cannot predict whether these or other factors will
have an adverse effect on demand for use of the pipeline
system or how significant that adverse effect could be.
Future Demand and Competition
On March 16, 2000, the FERC issued an order granting
Northern Border Pipeline's application for a certificate to
construct and operate its proposed Project 2000 facilities.
Project 2000 will expand and extend the pipeline system
into Indiana. Project 2000 will afford shippers on the
extended pipeline system access to industrial gas consumers
in northern Indiana through an interconnect with Northern
Indiana Public Service Company, a major midwest local
distribution company, at the terminus near North Hayden,
Indiana.
The capital expenditures for Project 2000 are estimated
to be approximately $94 million with a planned in-service of
November 2001. Proposed facilities include approximately
34.4 miles of 30-inch pipeline, new equipment and
modifications at three compressor stations resulting in a
net increase of 22,500 compressor horsepower and one meter
station.
As a result of the Project 2000 expansion, the pipeline
system will have the ability to transport 1,484 mmcfd from
Ventura to Harper, Iowa, 844 mmcfd from Harper to Manhattan,
Illinois, and 544 mmcfd on the new extension from Manhattan
to North Hayden, Indiana. Five shippers have contracted for
all the additional capacity under long-term transportation
agreements.
The Project 2000 shippers are: Bethlehem Steel
Corporation, El Paso Energy Marketing Company, Northern
Indiana Public Service Company, Peoples Energy Services
Corporation and The Peoples Gas Light and Coke Company.
Northern Border Pipeline competes with other pipeline
companies that transport natural gas from the western
Canadian sedimentary basin or that transport natural gas to
markets in the midwestern United States. The competitors
for the supply of natural gas include six pipelines and the
Canadian domestic users in the western Canadian sedimentary
basin region. Northern Border Pipeline's competitive
position is affected by the availability of Canadian natural
gas for export, the prices of natural gas in alternative
markets, the cost of producing natural gas in Canada, and
demand for natural gas in the United States.
Alliance Pipeline, which commenced transporting natural
gas from the western Canadian sedimentary basin to the
midwestern United States in December 2000, delivers its
volumes into the Chicago market and other interstate
pipelines. Alliance Pipeline transports gas containing
high-energy liquid hydrocarbons. Additional facilities to
extract the natural gas liquids were constructed near
Alliance Pipeline's terminus in Chicago to permit Alliance
to transport natural gas with the liquids-rich element.
As a consequence of Alliance Pipeline, there has been
an increase in natural gas moving from the western Canadian
sedimentary basin to Chicago. Vector Pipeline L.P.
interconnects with Alliance and transports gas eastward to a
terminus in eastern Canada. There are several additional
projects proposed to transport natural gas from the Chicago
area that would provide access to additional markets for the
shippers. The proposed projects currently being pursued by
third parties are targeting markets in northern Illinois,
Wisconsin and the northeast United States. These proposed
projects are in various stages of regulatory approval.
Williams has a minority interest (14.6%) in Alliance
Pipeline. TransCanada and other unaffiliated companies own
and operate pipeline systems that transport natural gas from
the same natural gas reserves in western Canada that supply
Northern Border Pipeline's customers.
Natural gas is also produced in the United States and
transported by competing pipeline systems to the same
markets as those served by the pipeline system.
Crestone Energy Ventures competes with other natural
gas gathering and pipelines companies to carry natural gas
from the production area of the Powder River and Wind River
Basins of Wyoming to the major interstate transmission
pipelines in the Rocky Mountain Region. Crestone Energy
Ventures' competitive position is affected by the pace of
gas drilling, gas production rates, gas reserves, and the
demand for natural gas in the Rocky Mountains, Midwest, and
California markets served by the interstate pipeline gas
grid. The pace of drilling may be impacted by the ability
of gas producers to obtain the necessary drilling and
production permits in an economic manner.
In providing gas gathering services, Crestone Energy
Ventures may require acreage dedication and/or volume
commitments from gas producers. Development of future gas
gathering systems will be staged to reflect the growth in
number of wells and field production.
FERC Regulation
General
Northern Border Pipeline is subject to extensive
regulation by the FERC as a "natural gas company" under the
Natural Gas Act. Under the Natural Gas Act and the Natural
Gas Policy Act, the FERC has jurisdiction with respect to
virtually all aspects of the business, including:
* transportation of natural gas;
* rates and charges;
* construction of new facilities;
* extension or abandonment of service and facilities;
* accounts and records;
* depreciation and amortization policies;
* the acquisition and disposition of facilities; and
* the initiation and discontinuation of services.
Where required, Northern Border Pipeline holds
certificates of public convenience and necessity issued by
the FERC covering the facilities, activities and services.
Under Section 8 of the Natural Gas Act, the FERC has the
power to prescribe the accounting treatment for items for
regulatory purposes. Northern Border Pipeline's books and
records are periodically audited under Section 8.
The FERC regulates the rates and charges for
transportation in interstate commerce. Natural gas
companies may not charge rates exceeding rates judged just
and reasonable by the FERC. In addition, the FERC prohibits
natural gas companies from unduly preferring or unreasonably
discriminating against any person with respect to pipeline
rates or terms and conditions of service. Some types of
rates may be discounted without further FERC authorization.
Northern Border Rate Case Proceeding
In May 1999, Northern Border Pipeline filed a rate case
wherein it proposed, among other things, to increase the
allowed equity rate of return to 15.25%. The total annual
cost of service increase due to the proposed changes was
approximately $30 million. A number of the 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
they were implemented with subsequent billings subject to
refund. The order set for hearing not only the proposed
changes but also several issues raised by intervenors
including the appropriateness of the cost of service form of
tariff and the depreciation schedule. Upon a request for
clarification, the FERC issued an order in August 1999 that
provided that the manner in which the costs of the recently
completed expansion and extension project ("The Chicago
Project") could be recovered from shippers may be examined
in this proceeding and that, while Northern Border Pipeline
had not proposed to change the depreciation rates approved
in the last rate case, it had the burden of proving that the
depreciation rates are just and reasonable.
On September 26, 2000, Northern Border Pipeline filed a
stipulation and agreement in its 1999 rate case proceeding
that documented a settlement. On December 13, 2000, the
FERC issued its order approving the terms of the settlement.
One of the important elements of the settlement is the
conversion of Northern Border Pipeline's form of tariff from
cost of service to stated rates based on a straight-fixed
variable rate design. Under the former cost of service
tariff, the firm transportation shippers contracted to pay
for a proportionate share of the pipeline system's cost of
service. During any given month, each of these shippers
paid a uniform mileage-based charge for the amount of
capacity contracted, and calculated under a cost of service
tariff. The shippers were obligated to pay their
proportionate share of the cost of service regardless of the
amount of natural gas they actually transported. Under the
cost of service form of tariff, Northern Border Pipeline
could not charge or collect more than the cost of service.
Under Northern Border Pipeline's new form of tariff,
shippers pay Northern Border Pipeline on the basis of stated
transportation rates. Under the terms of the settlement,
and in accordance with straight-fixed variable rate design
principles, approximately 98% of the agreed upon revenue
level is attributed to demand charges. The firm shippers
are obligated to pay a monthly demand charge, regardless of
the amount of natural gas they actually transport, for the
term of their contracts. The remaining 2% of the agreed
upon revenue level is attributed to the commodity charge
based on the volumes of gas actually transported. From
December 1, 1999, through and including December 31, 2000,
the rates were based upon an annual revenue level of
$307 million. For periods after December 31, 2000, the
rates are based upon an annual revenue level of $305
million. On a per unit of transportation basis, the rates
under the new tariff are approximately equal to the cost of
service on a per unit basis charged prior to December 1,
1999. The settlement also provides that neither Northern
Border Pipeline nor its existing shippers can seek rate
changes until November 1, 2005, at which time Northern
Border Pipeline must file a new rate case. Prior to the new
rate case, Northern Border Pipeline will not be permitted to
increase rates if its costs increase, nor will it be
required to reduce rates based on cost savings. 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.
Under Northern Border Pipeline's previous cost of
service form of tariff, the amount of revenue that it
collected from customers generally declined as the rate base
was recovered. Under its new tariff, Northern Border
Pipeline is entitled to collect revenue based on stated
rates established in its 1999 rate case until its next rate
case, which will be filed November 1, 2005. It will,
however, continue to depreciate its rate base at an annual
depreciation rate on transmission plant in service of 2.25%
and its rate base in 2005 will be a factor in determining
what it can charge when it files a new rate case at that
time. In order to avoid a decline in revenue it can collect
from its customers, Northern Border Pipeline must maintain
or increase its rate base by acquiring or constructing
assets that replace or add to existing pipeline facilities
or by adding new facilities and maintain its level of
contracted capacity at the stated rates.
It was agreed in the settlement of the 1999 rate case,
that there would be no project cost containment mechanism
adjustment for The Chicago Project and that all costs as of
November 30, 1999 incurred in the construction and
commissioning of the Chicago Project were included in rate
base. The project cost containment mechanism was created in
the settlement of the 1995 rate case. The purpose of the
project cost containment mechanism was to limit Northern
Border Pipeline's ability to include cost overruns for The
Chicago Project in rate base and to provide incentives for
cost underruns.
The settlement of Northern Border Pipeline's 1995 rate
case provided that for at least seven years from the date
The Chicago Project was completed, Northern Border Pipeline
could continue to calculate the allowance for income taxes
in the manner it had historically used. In addition, a
settlement adjustment mechanism of $31 million was
implemented, which effectively reduces the return on rate
base. These provisions of the 1995 rate case were
maintained in the settlement of Northern Border's 1999 rate
case.
Northern Border Pipeline also provides interruptible
transportation service. Interruptible transportation
service is transportation in circumstances when surplus
capacity is available after satisfying firm service
requests. The maximum rate that may be charged to
interruptible shippers is calculated as the sum of the firm
transportation Rate Schedule T-1 maximum reservation charge
and commodity rate. Under the previous cost of service form
of tariff, all interruptible transportation service revenue
generated was credited to the benefit of the firm shippers.
Under the new tariff, Northern Border Pipeline shares net
interruptible transportation service revenue and any new
services revenue on an equal basis with its firm shippers
through October 31, 2003. In addition, Northern Border
Pipeline is permitted to retain revenue from interruptible
transportation service to offset any decontracted firm
capacity.
After October 31, 2003, all revenues from interruptible
transportation service and other new services will no longer
be subject to sharing and thus will be retained by Northern
Border Pipeline. In addition, the settlement of the 1999
rate case also provided for an equal sharing with its firm
shippers of revenue generated from a certain
telecommunications contract for the term of that contract.
Northern Border Pipeline intends to develop new services and
seek the FERC's authorization to implement such services.
While the receipt of those approvals and the future impact
of the revenue sharing provisions of the settlement on
Northern Border Pipeline's earnings cannot be determined at
this time, revenues from these sources are expected to be
minimal through at least October 31, 2003.
Open access regulation
Beginning on April 8, 1992, the FERC issued a series of
orders, known as Order 636, which required pipeline
companies to unbundle their services and offer sales,
transportation, storage, gathering and other services
separately, to provide all transportation services on a
basis that is equal in quality for all shippers and to
implement a program to allow firm holders of pipeline
capacity to resell or release their capacity to other
shippers. Capacity release provisions were adopted that
allowed shippers to release all or part of their capacity
either permanently or temporarily. Shippers on the pipeline
system have temporarily released capacity as well as
permanently released capacity to other shippers who have
agreed to comply with the underlying contractual and
regulatory obligations associated with that capacity.
Beginning in 1996, the FERC issued a series of orders,
referred to together as Order 587, amending its open access
regulations to standardize business practices and procedures
governing transactions between interstate natural gas
pipelines, their customers, and others doing business with
the pipelines. The intent of Order 587 was to assist
shippers that deal with more than one pipeline by
establishing standardized business practices and procedures.
These business standards, developed by the Gas Industry
Standards Board, govern important business practices
including shipper supplied service nominations, allocation
of available capacity, accounting and invoicing of
transportation service, standardized internet business
transactions and capacity release. Northern Border Pipeline
has implemented the necessary changes to its tariff and
internal systems.
In 1998, the FERC initiated a number of proceedings to
further amend its open access regulations. In the resulting
order, Order 637 issued February 9, 2000, the FERC revised
the short-term transportation regulations by 1) waiving the
maximum rate ceiling in its capacity release regulations
until September 30, 2002 for short-term releases of capacity
of less than one year; 2) permitting value-oriented peak/off-
peak rates to better allocate revenue responsibility between
short-term and long-term markets; 3) permitting term-
differentiated rates to better allocate risks between
shippers and the pipelines; 4) revising the regulations
related to scheduling procedures, capacity segmentation,
imbalance management and penalties; 5) retaining the right
of first refusal and the five-year matching cap but limiting
the right to customers with maximum rate contracts for 12 or
more consecutive months of service; and 6) adopting new
reporting requirements to take effect September 1, 2000 that
include reporting daily transactional data on all firm and
interruptible contracts, daily reporting of scheduled
quantities at points or segments, and the posting of
corporate and pipeline organizational charts, names and
functions. As required by Order No. 637, Northern Border
Pipeline filed pro forma tariff sheets in compliance to
address the issues identified in 4) above. This filing is
pending at the FERC. All other related compliance filings
and reporting requirements have been completed and
implemented.
We do not believe that these regulatory initiatives
will have a material adverse impact to Northern Border
Pipeline's operations.
Environmental and Safety Matters
Our operations are subject to federal, state and local
laws and regulations relating to safety and the protection
of the environment which include the Resource Conservation
and Recovery Act, the Comprehensive Environmental Response,
Compensation and Liability Act of 1980, as amended, Clean
Air Act, as amended, the Clean Water Act, as amended, the
Natural Gas Pipeline Safety Act of 1969, as amended, and the
Pipeline Safety Act of 1992.
Black Mesa Pipeline Company, our subsidiary, has
received a Findings of Violation by the United States
Environmental Protection Agency ("EPA"), citing violations
of the Clean Water Act and Notice of Violation from the
Arizona Department of Environmental Quality citing
violations of state laws due to discharges of coal slurry on
Black Mesa's pipeline from December 1997 through July 1999.
Black Mesa Pipeline has paid an amount of $128,000 in
penalties for all alleged violations into an escrow account
and has executed a Consent Decree which sets forth this
payment as well as certain preventative measures, reporting
requirements and associated penalties for failure to comply.
Upon execution by the EPA and the Arizona Department of
Environmental Quality, this Consent Decree will be filed in
the United States District Court, District of Arizona for
public notice, comment and final approval.
Although we believe that our operations and facilities
are in general compliance in all material respects with
applicable environmental and safety regulations, risks of
substantial costs and liabilities are inherent in pipeline
operations, and we cannot provide any assurances that we
will not incur such costs and liabilities. Moreover, it is
possible that other developments, such as increasingly
strict environmental and safety laws, regulations and
enforcement policies thereunder, and claims for damages to
property or persons resulting from the Partnership's
operations, could result in substantial costs and
liabilities to the Partnership. If we are unable to recover
such resulting costs, earnings and cash distributions could
be adversely affected.
Item 2. Properties
Northern Border Pipeline holds the right, title and
interest in its pipeline system. With respect to real
property, the pipeline system falls into two basic
categories: (a) parcels which Northern Border Pipeline owns
in fee, such as certain of the compressor stations, meter
stations, pipeline field office sites, and microwave tower
sites; and (b) parcels where the interest of Northern Border
Pipeline derives from leases, easements, rights-of-way,
permits or licenses from landowners or governmental
authorities permitting the use of such land for the
construction and operation of the pipeline system. The
right to construct and operate the pipeline across certain
property was obtained by Northern Border Pipeline through
exercise of the power of eminent domain. Northern Border
Pipeline continues to have the power of eminent domain in
each of the states in which it operates the pipeline system,
although it may not have the power of eminent domain with
respect to Native American tribal lands.
Approximately 90 miles of the pipeline is located on
fee, allotted and tribal lands within the exterior
boundaries of the Fort Peck Indian Reservation in Montana.
Tribal lands are lands owned in trust by the United States
for the Fort Peck Tribes and allotted lands are lands owned
in trust by the United States for an individual Indian or
Indians. Northern Border Pipeline does have the right of
eminent domain with respect to allotted lands.
In 1980, Northern Border Pipeline entered into a
pipeline right-of-way lease with the Fort Peck Tribal
Executive Board, for and on behalf of the Assiniboine and
Sioux Tribes of the Fort Peck Indian Reservation. This
pipeline right-of-way lease, which was approved by the
Department of the Interior in 1981, granted to Northern
Border Pipeline the right and privilege to construct and
operate its pipeline on certain tribal lands. This lease
expires in 2011.
In conjunction with obtaining a pipeline right-of-way
lease across tribal lands located within the exterior
boundaries of the Fort Peck Indian Reservation, Northern
Border Pipeline also obtained a right-of-way across allotted
lands located within the reservation boundaries. This right-
of-way on allotted lands is either a perpetual easement or
for a term of years. Most of the allotted lands are subject
to a perpetual easement either granted, by the Bureau of
Indian Affairs ("BIA") for and on behalf of individual
Indian owners or obtained through condemnation. Several
tracts are subject to a right-of-way grant that has a term
of 15 years.
Crestone Gathering Services holds the right, title and
interest in its gathering system which consists of low
pressure gas gathering lines and compression and measurement
facilities. Crestone Gathering Services' system is utilized
for the gathering and compression of coal bed methane gas
from low pressure at the wellhead to high pressure gathering
lines of which 30 miles is steel pipe and 99 miles is
polyethylene pipe. Along these gathering lines, Crestone
Gathering Services has installed 42 gas compression
facilities with a total rated horsepower of 36,000 and
measurement facilities to support the receipt and delivery
of gas at various points. The real property rights for
Crestone Gathering Service's system are derived through
leases, easements, rights-of-way and permits.
Item 3. Legal Proceedings
We are not currently parties to any legal proceedings
that, individually or in the aggregate, would reasonably be
expected to have a material adverse impact on our results of
operations or financial position. Also, see Item 1.
"Business - Environmental and Safety Matters."
Item 4. Submission of Matters to a Vote of Security Holders
There were no matters submitted to a vote of security
holders during 2000.
PART II
Item 5. Market for the Registrant's Common Units
and Related Security Holder Matters
The following table sets forth, for the periods
indicated, the high and low sale prices per common unit, as
reported on the New York Stock Exchange Composite Tape, and
the amount of cash distributions per common unit declared
for each quarter:
Price Range Cash
High Low Distributions
2000
First Quarter.................. $29.25 $23.00 $0.65
Second Quarter................. 28.125 23.75 $0.65
Third Quarter.................. 31.875 27.25 $0.70
Fourth Quarter................. 33.625 27.75 $0.70
1999
First Quarter.................. $35.50 $30.375 $0.61
Second Quarter................. 33.5625 30.1875 0.61
Third Quarter.................. 31.875 28.00 0.61
Fourth Quarter................. 29.50 21.625 0.65
As of March 1, 2001, there were approximately 1,480
record holders of common units and approximately 39,700
beneficial owners of the common units, including common
units held in street name.
We currently have 31,503,563 common units outstanding,
representing a 98% limited partner interest. The common
units are the only outstanding limited partner interests.
Thus, our equity consists of general partner interests
representing in the aggregate a 2% interest and common units
representing in the aggregate a 98% limited partner
interest.
The general partners are entitled to 2% of all cash
distributions, and the holders of common units are entitled
to the remaining 98% of all cash distributions, except that
the general partners are entitled to incentive distributions
if the amount distributed with respect to any quarter
exceeds $0.605 per common unit ($2.42 annualized). Under
the incentive distribution provisions, the general partners
are entitled to 15% of amounts distributed in excess of
$0.605 per common unit, 25% of amounts distributed in excess
of $0.715 per common unit ($2.86 annualized) and 50% of
amounts distributed in excess of $0.935 per common unit
($3.74 annualized). The amounts that trigger incentive
distributions at various levels are subject to adjustment in
certain events, as described in the Partnership Agreement.
On January 18, 2001, we declared a distribution of $0.70
per unit ($2.80 per unit on an annualized basis), payable
February 14, 2001 to the general partners and unitholders of
record at January 31, 2001.
Item 6. Selected Financial Data
(in thousands, except per unit, other financial data and operating data)
Year Ended December 31,
2000 1999 1998 1997 1996
INCOME DATA:
Operating revenues, net $ 339,732 $ 318,963 $ 217,592 $ 198,574 $ 201,943
Operations and
maintenance 62,097 53,451 44,770 37,418 28,366
Depreciation and
amortization 60,699 54,842 43,885 40,332 46,979
Taxes other than income 28,634 30,952 22,012 22,836 24,390
Regulatory credit -- -- (8,878) -- --
Operating income 188,302 179,718 115,803 97,988 102,208
Interest expense, net 81,495 67,709 30,922 30,860 32,670
Other income 8,032 4,562 13,208 8,149 2,900
Minority interests
in net income 38,119 35,568 30,069 22,253 22,153
Net income to partners $ 76,720 $ 81,003 $ 68,020 $ 53,024 $ 50,285
Net income per unit $ 2.50 $ 2.70 $ 2.27 $ 1.97 $ 1.88
Number of units used
in computation 29,665 29,347 29,345 26,392 26,200
CASH FLOW DATA:
Net cash provided by
operating activities $ 169,615 $ 173,368 $ 103,849 $ 119,621 $ 137,534
Capital expenditures 19,721 102,270 652,194 152,658 18,597
Distribution per unit 2.65 2.44 2.30 2.20 2.20
BALANCE SHEET DATA
(AT END OF PERIOD):
Property, plant
and equipment, net $1,732,076 $1,745,356 $1,730,476 $1,118,364 $ 937,859
Total assets 2,082,720 1,863,437 1,825,766 1,266,917 1,016,484
Long-term debt, including
current maturities 1,171,962 1,031,986 976,832 481,355 377,500
Minority interests in
partners' capital 248,098 250,450 253,031 174,424 158,089
Partners' capital 572,274 515,269 507,426 500,728 410,586
OTHER FINANCIAL DATA:
Ratio of earnings to
fixed charges (1) 2.4 2.7 3.0 3.2 3.2
OPERATING DATA:
Northern Border Pipeline:
Million cubic feet
of gas delivered 852,674 834,833 608,187 621,262 630,148
Average daily
throughput (MMcfd) 2,400 2,353 1,706 1,735 1,755
Transportation units
(million dekatherm
miles per day):
Firm service 2,276 2,289 1,417 1,393 1,392
Interruptible 19 6 28 47 56
(1) "Earnings" means the sum of pre-tax income from continuing
operations and fixed charges. "Fixed charges" means the sum of (a)
interest expensed and capitalized; (b) amortized premiums, discounts
and capitalized expenses related to indebtedness; and (c) an estimate
of interest within rental expenses.
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations
Results of Operations
Year Ended December 31, 2000 Compared With the Year Ended
December 31, 1999
Operating revenues, net increased $20.8 million (7%) for the
year ended December 31, 2000, as compared to the same period in
1999. Operating revenues attributable to Northern Border
Pipeline were $311.0 million for the year ended December 31,
2000, as compared to $298.3 million for the same period in 1999,
an increase of $12.7 million (4%). Northern Border Pipeline's
operating revenues for 2000 reflect the significant terms of the
rate case settlement discussed in Item 1. "Business - Northern
Border Rate Case Proceeding". Operating revenues for 1999 were
determined under Northern Border Pipeline's cost of service
tariff. Operating revenues from Crestone Energy Ventures were
$7.5 million for 2000, which represented three months of
activity. Crestone Energy Venture's operating results occurred
in the fourth quarter of 2000 after the acquisition of gas
gathering businesses in late September 2000 (see Item 1.
"Business - General").
Operations and maintenance expense increased $8.6 million
(16%) for the year ended December 31, 2000, from the same period
in 1999, due primarily to $5.1 million of expense from Crestone
Energy Ventures. Operations and maintenance expense attributable
to Northern Border Pipeline increased $2.8 million (7%) for the
year ended December 31, 2000, from the same period in 1999, due
primarily to increased employee payroll and benefit expenses and
costs to operate two electric-powered compressor units.
Depreciation and amortization expense increased $5.9 million
(11%) for the year ended December 31, 2000, as compared to the
same period in 1999. Depreciation and amortization expense
attributable to Northern Border Pipeline increased $5.4 million
(10%) for the year ended December 31, 2000, as compared to the
same period in 1999, due primarily to an increase in the
depreciation rate applied to transmission plant. As a result of
the rate case settlement, Northern Border Pipeline used a
depreciation rate for transmission plant of 2.25% for 2000.
Northern Border Pipeline had used a depreciation rate of 2.0% for
1999.
Taxes other than income decreased $2.3 million (7%) for the
year ended December 31, 2000, as compared to the same period in
1999, due primarily to adjustments to Northern Border Pipeline's
previous estimates of ad valorem taxes.
Interest expense, net increased $13.8 million (20%) for the
year ended December 31, 2000, as compared to the same period in
1999. Interest expense for the Partnership increased
approximately $9.2 million (167%) for the year ended December 31,
2000, as compared to the same period in 1999, due to additional
borrowings and an increase in interest rates. The additional
borrowings were made primarily for the acquisition of gas
gathering businesses in the Powder River and Wind River basins in
Wyoming in December 1999, June 2000 and September 2000. Interest
expense attributable to Northern Border Pipeline increased $4.9
million (8%) for the year ended December 31, 2000, as compared to
the same period in 1999, due primarily to an increase in average
interest rates between 1999 and 2000. The impact of the increase
in interest rates was partially offset by a decrease in average
debt outstanding.
Other income increased $3.5 million (76%) for the year ended
December 31, 2000, as compared to the same period in 1999. Other
income attributable to Northern Border Pipeline increased $6.7
million (491%) for the year ended December 31, 2000, as compared
to the same period in 1999, due primarily to a reduction in
reserves previously established for regulatory issues as a result
of the settlement of Northern Border Pipeline's rate case. The
1999 results included $3.0 million of other non-recurring income
for the Partnership.
Minority interests in net income increased $2.6 million (7%)
for the year ended December 31, 2000, as compared to the same
period in 1999, due to increased net income for Northern Border
Pipeline.
Year Ended December 31, 1999 Compared With the Year Ended
December 31, 1998
Operating revenues, net increased $101.4 million (47%) for
the year ended December 31, 1999, as compared to the same period
in 1998, due primarily to additional revenue from Northern Border
Pipeline's operation of The Chicago Project facilities.
Additional receipt capacity of 700 mmcfd, a 42% increase, and new
firm transportation agreements with 27 shippers resulted from The
Chicago Project. Northern Border Pipeline's cost of service
tariff provided an opportunity to recover 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 an opportunity to collect from its shippers
a return on unrecovered rate base as well as recover that rate
base through depreciation and amortization. The Chicago Project
increased Northern Border Pipeline's rate base, which increased
return for the year ended December 31, 1999. Also reflected in
the increase in 1999 revenues are recoveries of increased
pipeline operating expenses due to the new facilities.
Operations and maintenance expense increased $8.7 million
(19%) for the year ended December 31, 1999, from the same period
in 1998, due primarily to operations and maintenance expenses for
The Chicago Project facilities and increased employee payroll and
benefit expenses.
Depreciation and amortization expense increased $11.0
million (25%) for the year ended December 31, 1999, as compared
to the same period in 1998, due primarily to The Chicago Project
facilities placed into service. The impact of the additional
facilities on depreciation and amortization expense was partially
offset by a decrease in the depreciation rate applied to
transmission plant from 2.5% to 2.0%. Northern Border Pipeline
agreed to reduce the depreciation rate at the time The Chicago
Project was placed into service as part of a previous rate case
settlement.
Taxes other than income increased $8.9 million (41%) for the
year ended December 31, 1999, as compared to the same period in
1998, due primarily to ad valorem taxes attributable to the
facilities placed into service for The Chicago Project.
For the year ended December 31, 1998, Northern Border
Pipeline recorded a regulatory credit of $8.9 million. During
the construction of The Chicago Project, Northern Border Pipeline
placed new facilities into service in advance of the December
1998 project in-service date to maintain gas flow at firm
contracted capacity while existing facilities were being
modified. The regulatory credit deferred the cost of service of
these new facilities, which Northern Border Pipeline began to
recover from its shippers commencing with the in-service date of
The Chicago Project.
Interest expense, net increased $36.8 million (119%) for the
year ended December 31, 1999, as compared to the same period in
1998, due to an increase in interest expense of $17.9 million and
a decrease in interest expense capitalized of $18.9 million.
Interest expense increased due primarily to an increase in
average debt outstanding, reflecting amounts borrowed to finance
a portion of the capital expenditures for The Chicago Project.
The impact of the increased borrowings on interest expense was
partially offset by a decrease in average interest rates between
1998 and 1999. The decrease in interest expense capitalized is
due to the completion of construction of The Chicago Project in
December 1998.
Other income decreased $8.6 million (65%) for the year ended
December 31, 1999, as compared to the same period in 1998,
primarily due to a decrease in the allowance for equity funds
used during construction. The decrease in the allowance for
equity funds used during construction is due to the completion of
construction of The Chicago Project in December 1998.
Minority interests in net income increased $5.5 million
(18%) for the year ended December 31, 1999, as compared to the
same period in 1998, due to increased net income for Northern
Border Pipeline.
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 indenture under which the Pipeline Senior Notes
were issued does not limit the amount of unsecured debt Northern
Border Pipeline may incur, but does contain material financial
covenants, including restrictions on incurrence of secured
indebtedness. The proceeds from the Pipeline Senior Notes were
used to reduce indebtedness under a June 1997 credit agreement.
In June 1997, Northern Border Pipeline entered into a credit
agreement ("Pipeline Credit Agreement") with certain financial
institutions to borrow up to an aggregate principal amount of
$750 million. The Pipeline Credit Agreement is comprised of a
$200 million five-year revolving credit facility to be used for
the retirement of Northern Border Pipeline's prior credit
facilities and for general business purposes, and a $550 million
three-year revolving credit facility to be used for the
construction of The Chicago Project. Effective March 1999, in
accordance with the provisions of the Pipeline Credit Agreement,
Northern Border Pipeline converted the three-year revolving
credit facility to a term loan maturing in 2002. At December 31,
2000, $424 million was outstanding under the term loan and $45
million was outstanding under the five-year revolving credit
facility.
At December 31, 2000, 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 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. The Partnership Senior Notes were subsequently exchanged
in a registered offering for notes with substantially identical
terms. The indenture under which the 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 Partnership Senior Notes
were used in acquisitions made by the Partnership in June 2000
and September 2000 (see Cash Flows from Investing Activities).
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, "2000 Partnership Credit
Agreements"). At December 31, 2000, $26.3 million was
outstanding under the 2000 Partnership Credit Agreements.
In November 2000, the Partnership sold, through an
underwritten public offering, 2,156,250 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 $60.7 million and were
primarily used to repay amounts borrowed under the 2000
Partnership Credit Agreements.
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 will register an exchange offer
with the Securities and Exchange Commission to exchange the 2001
Partnership Senior Notes for notes with substantially identical
terms. 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 are to be used to fund a portion of the acquisition of Bear
Paw Energy (see Item 1. Business - Pending Acquisitions) and for
capital investments and general corporate purposes.
In March 2001, the Partnership entered into a $200 million
three-year revolving credit agreement with certain financial
institutions ("2001 Partnership Credit Agreement"). The 2001
Partnership Credit Agreement is to be used for capital
expenditures, working capital and general business purposes. The
2001 Partnership Credit Agreement replaced the 2000 Partnership
Credit Agreements discussed previously.
Short-term liquidity needs will be met by internal sources
and through the lines of credit 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 decreased $3.8
million to $169.6 million for the year ended December 31, 2000,
as compared to the same period in 1999, primarily due to reduced
earnings from higher interest costs. During 2000, we realized
net cash inflows of approximately $2.4 million related to
Northern Border Pipeline's rate case, which included $25.1
million of amounts collected subject to refund less estimated
refunds issued in late December 2000 totaling approximately $22.7
million. Cash flows provided by operating activities increased
$69.5 million to $173.4 million for the year ended December 31,
1999, as compared to the same period in 1998, primarily
attributed to The Chicago Project facilities placed into service
in late December 1998.
Cash Flows From Investing Activities
Business acquisitions for the year ended December 31, 2000
include gas gathering businesses in the Powder River and Wind
River basins in Wyoming for approximately $229.5 million. For
the comparable period in 1999, the Partnership acquired a 39%
common member interest in Bighorn for $31.9 million. See Item 1.
"Business - General" for a discussion of the acquisitions.
The investments in unconsolidated affiliates of $8.8
million for the year ended December 31, 2000 primarily reflects
capital contributions of $11.8 million to Bighorn, net of a $3.5
million payment received from Enron North America. As part of
the terms of the purchase agreement, Enron North America agreed
to fund approximately $3.5 million of an equity investment in
Lost Creek. Crestone Energy Ventures expects to make the
investment in Lost Creek during 2001.
Capital expenditures of $19.7 million for the year ended
December 31, 2000 included $7.4 million for Northern Border
Pipeline's Project 2000 (see Item 1. "Business - Future Demand
and Competition") and $3.8 million for gas gathering facilities
for Crestone Energy Ventures. For the same period in 1999,
capital expenditures were $102.3 million and included $85.5
million for The Chicago Project and $2.5 million for Project
2000. The remaining capital expenditures for 2000 and 1999 are
primarily related to renewals and replacements of existing
facilities.
Total capital expenditures and investments in unconsolidated
affiliates for 2001 are estimated to be $198 million. Capital
expenditures for Northern Border Pipeline are estimated to be $97
million, including approximately $81 million for Project 2000 and
approximately $16 million primarily for renewals and replacements
of existing facilities. 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 Crestone Energy Ventures are
estimated to be $79 million and investments in unconsolidated
affiliates are estimated to be $22 million for 2001. The
Partnership anticipates financing Crestone Energy Venture's
capital requirements primarily by borrowing on the Partnership
Credit Agreements or other debt facilities.
If the acquisitions discussed in Item 1. "Business - Pending
Acquisitions" are completed, capital expenditures of $30 to $35
million, in addition to those discussed above, are expected in
2001.
Cash Flows From Financing Activities
Cash flows provided by financing activities were $100.8
million for the year ended December 31, 2000 compared to cash
flows used of $57.3 million for the same period in 1999. Cash
distributions to the unitholders and the general partners
increased $7.3 million to $80.4 million reflecting an increase in
the distribution from $2.44 per unit for 1999 to $2.65 per unit
for 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 proceeds were used to repay
the Partnership's existing indebtedness of $119.5 million and to
partially fund the acquisition of gas gathering businesses
discussed previously. The funding for the remainder of the
acquisition of gas gathering businesses came from borrowings
under the Partnership Credit Agreements of $97.5 million.
Financing activities for 2000 reflect $60.7 million in net
proceeds from the issuance of 2,156,250 common units and a
related capital contribution by the Partnership's general
partners in November 2000. In December 2000, the Partnership
received approximately $15.0 million from the termination of
interest rate swap agreements. Repayments on the 2000
Partnership Credit Agreements of approximately $71.2 million were
primarily made using the proceeds from the issuance of common
units and the termination of the interest rate swap agreements.
For the year ended December 31, 2000, advances under the Pipeline
Credit Agreement, which were primarily used to repay $66 million
of Series A Notes, were $75 million as compared to advances of
$90 million for the same period in 1999, which were primarily
used to finance a portion of the capital expenditures for The
Chicago Project. Financing activities for the year ended
December 31, 1999 included $197.4 million from the issuance of
the Pipeline Senior Notes, net of associated debt discounts and
issuance costs, and $12.9 million from the termination of
Northern Border Pipeline's interest rate forward agreements.
Payments on the Pipeline Credit Agreement were $45 million for
the year ended December 31, 2000, as compared to $263 million for
the same period 1999. At December 31, 2000, we reflected a cash
overdraft of approximately $22.4 million primarily due to
Northern Border Pipeline's refund checks outstanding. The goal
of our cash management program is to maximize the amount of our
cash and cash equivalents balance in highly liquid, interest-
bearing investments. Those investments are converted to cash
when needed to replenish our bank accounts for check clearing
requirements.
Cash flows used in financing activities were $57.3 million
for the year ended December 31, 1999, as compared to cash flows
provided by financing activities of $482.6 million for the year
ended December 31, 1998. Cash distributions to the unitholders
and the general partners increased $4.3 million reflecting an
increase in the quarterly distribution from $2.30 per unit for
1998 to $2.44 per unit for 1999. Distributions paid to minority
interest holders were $38.1 million for the year ended December
31, 1999, as compared to net cash contributions received from
minority interest holders of $48.5 million for the year ended
December 31, 1998, which included amounts needed to finance a
portion of the capital expenditures for The Chicago Project.
Financing activities for the year ended December 31, 1998 reflect
$7.6 million in net proceeds from the issuance of 225,000 common
units and related capital contributions by the Partnership's
general partners in January 1998. Advances under the Pipeline
Credit Agreement, which were primarily used to finance a portion
of the capital expenditures for The Chicago Project, were $90.0
million for the year ended December 31, 1999. Advances under a
Partnership credit agreement, which were used for the acquisition
of Bighorn, were $24.5 million for the year ended December 31,
1999. For the same period in 1998, advances under the Pipeline
Credit Agreement and a Partnership credit agreement totaled
$498.0 million. During the year ended December 31, 1999, $263.0
million was repaid on the Pipeline Credit Agreement.
New Accounting Pronouncements
In June 1998, the Financial Accounting Standards Board
("FASB") issued Statement of Financial Accounting Standards
("SFAS") No. 133, "Accounting for Derivative Instruments and
Hedging Activities." 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.
See Note 11 to the Consolidated Financial Statements.
Information Regarding Forward Looking Statements
Statements in this Annual Report that are not historical
information are forward looking statements. Such forward looking
statements include:
* the discussions under "Business - Future Demand and
Competition" and elsewhere regarding Northern Border
Pipeline's efforts to pursue opportunities to further
increase the capacity of its pipeline system;
* the discussion under "Business - Northern Border Rate Case
Proceeding" regarding Northern Border Pipeline's rate case
settlement;
* the discussions under "Business - Pending Acquisitions"; and
* the discussion in "Management's Discussion and Analysis of
Financial Condition and Results of Operations - Liquidity
and Capital Resources."
Although we believe that our expectations regarding future
events are based on reasonable assumptions within the bounds of
our knowledge of our business, we can give no assurance that our
goals will be achieved or that our expectations regarding future
developments will be realized. Important factors that could
cause actual results to differ materially from those in the
forward looking statements include:
* future demand for natural gas;
* availability of economic western Canadian natural gas;
* industry conditions;
* natural gas, political and regulatory developments that
impact FERC proceedings;
* 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 companies;
* political and regulatory developments in the U.S. and
Canada;
* our ability to successfully negotiate final definitive
purchase agreements and to receive necessary approvals; and
* conditions of the capital markets and equity markets.
Item 7a. Quantitative and Qualitative Disclosures About Market Risk
Our interest rate exposure results from variable rate
borrowings from commercial banks. To mitigate potential
fluctuations in interest rates, we attempt to maintain a
significant portion of our consolidated debt portfolio in fixed
rate debt. We also use interest rate swap agreements to increase
the portion of fixed rate debt. As of December 31, 2000,
approximately 60% of our debt portfolio, after considering the
effect of interest rate swap agreements, is in fixed rate debt.
If average interest rates change by one percentage compared
to rates in effect as of December 31, 2000, consolidated annual
interest expense would change by approximately $4.6 million.
This amount has been determined by considering the impact of the
hypothetical interest rates on our variable rate borrowings
outstanding as of December 31, 2000.
Item 8. Financial Statements and Supplementary Data
The information required hereunder is included in this
report as set forth in the "Index to Financial Statements" on
page F-1.
Item 9. Changes in and Disagreements With Accountants on Accounting and
Financial Disclosure
None.
Item 10. Partnership Management
We are managed by or under the direction of the Partnership
Policy Committee consisting of three members, each of which has
been appointed by one of the general partners. The members
appointed by Northern Plains, Pan Border and Northwest Border
have 50%, 32.5% and 17.5%, respectively of the voting power. The
Partnership Policy Committee has appointed three individuals who
are neither officers nor employees of any general partner or any
affiliate of a general partner, to serve as a committee of the
Partnership (the "Audit Committee") with authority and
responsibility for selecting our independent public accountants,
reviewing our annual audit and resolving accounting policy
questions. The Audit Committee also has the authority to review,
at the request of a general partner, specific matters as to which
a general partner believes there may be a conflict of interest in
order to determine if the resolution of such conflict proposed by
the Partnership Policy Committee is fair and reasonable to us.
As is commonly the case with publicly-traded partnerships,
we do not directly employ any of the persons responsible for
managing or operating the Partnership or for providing it with
services relating to its day-to-day business affairs. We have
entered into an Administrative Services Agreement with NBP
Services Corporation, a wholly-owned subsidiary of Enron,
pursuant to which NBP Services provides tax, accounting, legal,
cash management, investor relations, operating and other services
for the Partnership. NBP Services has 22 employees and uses the
employees of Enron or its affiliates who have duties and
responsibilities other than those relating to the Administrative
Services Agreement. Upon completion of the acquisition of the
interests in Bear Paw, NBP Services will increase its employees
by approximately 100. In consideration for its services under
the Administrative Services Agreement, NBP Services is reimbursed
for its direct and indirect costs and expenses, including an
allocated portion of employee time and Enron's overhead costs.
Set forth below is certain information concerning the
members of the Partnership Policy Committee, our representatives
on the Northern Border Management Committee and the persons
designated by the Partnership Policy Committee as our executive
officers and as Audit Committee members. All members of the
Partnership Policy Committee and our representatives on the
Northern Border Management Committee serve at the discretion of
the general partner that appointed them. The persons designated
as executive officers serve in that capacity at the discretion of
the Partnership Policy Committee. Effective October 1, 2000,
William R. Cordes replaced Larry L. DeRoin as our Chief Executive
Officer and Chairman of the Partnership Policy Committee and of
the Northern Border Management Committee. The members of the
Partnership Policy Committee receive no management fee or other
remuneration for serving on this Committee. The Audit Committee
members are elected, and may be removed, by the Partnership
Policy Committee. Each Audit Committee member receives an annual
fee of $20,000 and is paid $1,500 for each meeting attended.
Effective February 2001, a third Audit Committee member was
elected.
Name Age Positions
Executive Officers:
William R. Cordes 52 Chief Executive Officer
Jerry L. Peters 43 Chief Financial and Accounting
Officer
Members of Partnership Policy
Committee and Partnership's
representatives on Northern
Border Management Committee:
William R. Cordes 52 Chairman
Stanley C. Horton 51 Member
Cuba Wadlington, Jr. 57 Member
Members of Audit Committee:
Daniel P. Whitty 69 Chairman
Daniel Dienstbier 60 Member
Gerald B. Smith 50 Member
William R. Cordes was named Chief Executive Officer of the
Partnership and Chairman of the Partnership Policy Committee in
October 2000. Mr. Cordes is the President of Northern Plains, an
Enron subsidiary, having been appointed to that position on
October 1, 2000, and is a director of Northern Plains. Mr.
Cordes was named Chairman of the Northern Border Management
Committee October 1, 2000. He started his career with another
Enron company, Northern Natural, in 1970 and has worked in
several management positions at Northern Natural. In June of
1993, he was named President of Northern Natural and added the
position of President of Transwestern Pipeline in May of 1996.
Stanley C. Horton was appointed to the Partnership Policy
Committee and to the Northern Border Management Committee in
December 1998. Mr. Horton is the Chairman and Chief Executive
Officer of Enron Transportation Services Company, formerly the
Enron Gas Pipeline Group, and has held that position since
January 1997. From February 1996 to January 1997, he was Co-
Chairman and Chief Executive Officer of Enron Operations Corp.
From June 1993 to February 1996, he was President and Chief
Operating Officer of Enron Operations Corp. He is a Director,
Chairman of the Board and Chief Executive Officer of EOTT Energy
Corp., the general partner of EOTT Energy Partners, L.P.
Cuba Wadlington, Jr. was named to the Partnership Policy
Committee and to the Northern Border Management Committee on
December 1, 1999. On January 4, 2000, Mr. Wadlington was named
President and Chief Executive Officer of Williams Gas Pipeline.
Previously, he had served as Executive Vice President and Chief
Operating Officer of Williams Gas Pipeline since July 1999. Mr.
Wadlington joined Transco in 1995 when Williams acquired Transco
Energy Company. From 1995 to 1999, he served as senior vice
president and general manager of Williams Gas Pipeline-Transco.
From 1988 to 1995, he served as senior vice president and general
manager of Williams Western Pipeline Company, executive vice
president of Kern River Gas Transmission Company, and director of
Northwest Pipeline Corporation and Williams Western Pipeline, all
affiliates or subsidiaries of Williams. Mr. Wadlington serves on
the Board of Directors of Williams Communication Group Inc., and
Sterling Bancshares Inc.
Jerry L. Peters was named Chief Financial and Accounting
Officer in July 1994. Mr. Peters has held several management
positions with Northern Plains since 1985 and was elected
Treasurer for Northern Plains in October 1998, Vice President of
Finance for Northern Plains in July 1994, and director of
Northern Plains in August 1994. Mr. Peters was also named Vice
President, Finance of Enron Transportation Services Company in
February 2001. Prior to joining Northern Plains in 1985, Mr.
Peters was employed as a Certified Public Accountant by KPMG Peat
Marwick, LLP.
Daniel P. Whitty was appointed to the Audit Committee in
December 1993. Mr. Whitty is an independent financial
consultant. He is a director of Enron Funding Corp., Enron
Equity Corp. and of EOTT Energy Corp., all subsidiaries of
Enron, and the latter of which is the general partner of EOTT
Energy Partners, L.P. He has served as a member of the Board of
Directors of Methodist Retirement Communities Inc., and a Trustee
of the Methodist Retirement Trust. Mr. Whitty was a partner at
Arthur Andersen & Co. until his retirement on January 31, 1988.
Gerald B. Smith was appointed to the Audit Committee in
April 1994. He is Chairman and Chief Executive Officer and co-
founder of Smith, Graham & Company Investment Advisors, a fixed
income investment management firm, which was founded in 1990. He
has served as a director of that company since December 1998 and
is a member of the Audit Committee and Executive Committee of the
board. He is also a director of Pennzoil-Quaker States, Charles
Schwab Family of Funds, Cooper Industries, and Rorento
N.V.(Netherlands). From 1988 to 1990, he served as Senior Vice
President and Director of Fixed Income and Chairman of the
Executive Committee of Underwood Neuhaus & Co.
Daniel Dienstbier was appointed to the Audit Committee
effective February 1, 2001. Mr. Dienstbier is currently a member
of the Board of Directors of Dynegy Corporation and has served on
that board since 1995. At the time of his retirement in 1994, he
was the President and Chief Operating Officer of American Oil &
Gas Company. He serves on arbitration panels involving energy
contract disputes. From 1965 through mid-1988, Mr. Dienstbier
held various positions with Northern Natural Gas Company. From
1985 to 1988, he was the President of Enron's Gas Pipeline Group,
which included Enron's interest in Northern Border Pipeline.
Item 11. Executive Compensation
The following table summarizes certain information regarding
compensation paid or accrued during each of Northern Plains' last
three fiscal years to the executive officers of the Partnership
(the "Named Officers") for services performed in their capacities
as executive officers of Northern Plains:
Summary Compensation Table
All Other
Annual Compensation Long-Term Compensation Compensation
Securities
Restricted Underlying
Other Annual Stock Awards Options/SARs LTIP Payouts
Name & Position Year Salary(1) Bonus(2) Compensation(3) ($)(4) (#) ($)(5) ($)(6)
Larry L. DeRoin 2000 $209,167 $ -- $16,844 $164,754 11,335 $403,125 $513,534
Chief Executive 1999 $266,367 $225,000 $ 7,773 $ -- -- $ -- $ 10,413
Officer 1998 $256,067 $250,000 $ 7,200 $125,024 19,020 $ -- $ 6,380
William R. Cordes 2000 $311,000 $250,000 $15,000 $205,984 17,405 $131,250 $ 13,110
Chief Executive
Officer
Jerry L. Peters 2000 $145,293 $110,000 $ 3,708 $112,385 15,040 $ -- $ 10,091
Chief Financial and 1999 $132,933 $100,000 $ 3,983 $ -- 9,070 $ -- $ 5,260
Accounting Officer 1998 $123,225 $110,000 $ 1,214 $ 60,030 20,000 $ -- $ 1,956
(1) Mr. DeRoin retired effective September 30, 2000. Mr. Cordes
was appointed President of Northern Plains and Chief Executive
Officer of the Partnership on October 1, 2000.
(2) Employees may elect to receive Northern Border phantom
units, Enron Corp. phantom stock, and/or Enron Corp. stock
options in lieu of all or a portion of an annual bonus payment.
Mr. Peters elected to receive Northern Border phantom units in
lieu of a portion of the cash bonus payment under the Northern
Border Phantom Unit Plan. He received 1,532 units in 1999 and
1,450 units in 2000. In each case, units will be released to him
five years following the grant date.
(3) Other Annual Compensation includes cash perquisite
allowances, service awards, and vacation payouts. Also, Enron
maintains three deferral plans for key employees under which
payment of base salary, annual bonus, and long-term incentive
awards may be deferred to a later specified date. Under the 1985
Deferral Plan, interest is credited on amounts deferred based on
150% of Moody's seasoned corporate bond yield index with a
minimum rate of 12%, which for 1998, 1999 and 2000 was the
minimum rate of 12%. No interest has been reported as Other
Annual Compensation under the 1985 Deferral Plan for
participating Named Officers because the crediting rates during
1998, 1999, and 2000, did not exceed 120% of the long-term
Applicable Federal Rate of 14.38% in effect at the time the 1985
Deferral Plan was implemented. Beginning January 1, 1996, the
1994 Deferral Plan credits interest based on fund elections
chosen by participants. Since earnings on deferred compensation
invested in third-party investment vehicles, comparable to mutual
funds, need not be reported, no interest has been reported as
Other Annual Compensation under the 1994 Deferral Plan during
1998, 1999 and 2000.
(4) The aggregate total of shares in unreleased Enron restricted
stock holdings and their values as of December 31, 2000, for each
of the Named Officers is: Mr. Cordes, 7,737 shares valued at
$643,138, and Mr. Peters, 2,755 shares valued at $229,009.
Dividend equivalents for all restricted stock awards accrue from
date of grant and are paid upon vesting.
(5) Reflects cash payments under the Enron Corp. Performance
Unit Plan for the 1996-1999 period. Payments made under the
Performance Unit Plan are based on Enron's total shareholder
return relative to its peers. Enron's performance over the 1996-
1999 performance period rendered a value of $1.50 based on a
ranking of second as compared to 11 industry peers. Mr. DeRoin's
payment includes amounts relating to 1997-2000 and 1998-2001
performance periods ($187,250 and $103,125 respectively) which
were paid early due to his retirement.
(6) The amounts shown include the value of Enron Common Stock
allocated to employees' special subaccounts under Enron's
Employee Stock Ownership Plan, matching contributions to
employees' Enron Corp. Savings Plan, and imputed income on life
insurance benefits. Mr. DeRoin received a $500,000 payment
following his retirement. Such payment was in lieu of any
severance pay or severance benefits that otherwise would be
payable under Enron's Severance Pay Plan. In addition, Mr. DeRoin
has entered into an agreement under which he has agreed to
provide consulting services to Northern Plains and its businesses
until September 30, 2002 for which he receives a payment of
$20,833 per month.
Stock Option Grants During 2000
The following table sets forth information with respect to grants of
stock options pursuant to Enron's stock plans to the Named Officers
reflected in the Summary Compensation Table. No stock appreciation rights
were granted during 2000.
Potential Realizable Value at
Individual Grants Assumed Annual Rates of Stock
Number of % of Total Price Appreciation for Option Term (1)
Securities Options/SARs
Underlying Granted to Exercise or
Options/SARs Employees in Base Price Expiration
Name Granted(#) Fiscal Year ($/Sh) Date 0%(2) 5% 10%
Larry L. DeRoin 11,285 (3) 0.03% $55.5000 01/18/2007 $ -- $254,974 $594,198
50 (4) 0.00% $55.5000 01/18/2007 $ -- $ 1,130 $ 2,633
William R. Cordes 14,105 (3) 0.04% $55.5000 01/18/2007 $ -- $318,689 $742,682
50 (4) 0.00% $55.5000 01/18/2007 $ -- $ 1,130 $ 2,633
3,250 (6) 0.01% $83.1250 12/29/2007 $ -- $ 73,431 $171,125
Jerry L. Peters 7,695 (3) 0.02% $55.5000 01/18/2007 $ -- $173,861 $405,171
50 (4) 0.00% $55.5000 01/18/2007 $ -- $ 1,130 $ 2,633
5,770 (5) 0.01% $65.0000 01/24/2007 $ -- $152,683 $355,816
1,525 (6) 0.00% $83.1250 12/29/2007 $ -- $ 34,456 $ 80,297
(1) The dollar amounts under these columns represent the potential
realizable value of each grant of options assuming that the market price on
Enron Common Stock appreciates in value from the date of grant at the 5%
and 10% annual rates prescribed by the SEC and therefore are not intended
to forecast possible future appreciation, if any, of the price of Enron
Common Stock.
(2) An appreciation in stock price, which will benefit all shareholders,
is required for optionees to receive any gain. A stock price appreciation
of 0% would render the option without value to the optionees.
(3) Represents stock options awarded under the Enron Corp. Long-Term
Incentive Program. Awards vest 25% on the grant date and 25% on each
anniversary thereafter.
(4) A grant of 50 stock options was provided to each eligible Enron
employee in recognition of Enron stock reaching a fair market value of $50
after the August, 1999, 2-for-1 stock split.
(5) Mr. Peters elected to receive stock options in lieu of a portion of
his 1999 annual cash bonus payment in the form of stock options which were
granted in January, 2000 and were 100% vested on date of grant.
(6) All eligible employees received an option grant under the EnronOptions
Program. The EnronOptions Program provides a grant of options equal to 5%
of base annual salary for each year of participation in the program, not to
exceed five years of participation. Stock options vest 20% each year
beginning June 30, 2001.
Aggregated Stock Option/SAR Exercises During 2000 and Stock
Option/SAR Values as of December 31, 2000
The following table sets forth information with respect to
the Named Officers concerning the exercise of Enron SARs and
options during the last fiscal year and unexercised Enron options
and SARs held as of the end of the fiscal year:
Number of Securities
Underlying Unexercised Value of Unexercised
Shares Options/SARs at In-the-Money Options/SARs
Acquired on Value December 31, 2000 December 31, 2000 (1)
Name Exercise (#) Realized Exercisable Unexercisable Exercisable Unexercisable
Larry L. DeRoin 102,990 $5,458,031 50,875 -- $ 2,630,794 $ --
William R. Cordes 47,130 $2,922,001 213,788 41,327 $13,454,935 $1,945,463
Jerry L. Peters 9,090 $ 432,676 54,084 9,891 $ 2,915,839 $ 393,525
(1) The dollar value in this column for Enron Corp. stock
options was calculated by determining the difference between the
fair market value underlying the options as of December 31, 2000
($83.1250) and the grant price.
Retirement and Supplemental Benefit Plans
Enron maintains the Enron Corp. Cash Balance Plan (the "Cash
Balance Plan") which is a noncontributory defined benefit pension
plan to provide retirement income for employees of Enron and its
subsidiaries. Through December 31, 1994, participants in the
Cash Balance Plan with five years or more of service were
entitled to retirement benefits in the form of an annuity based
on a formula that uses a percentage of final average pay and
years of service. In 1995, Enron's Board of Directors adopted an
amendment to and restatement of the Cash Balance Plan changing
the plan's name from the Enron Corp. Retirement Plan to the Enron
Corp. Cash Balance Plan. In connection with a change to the
retirement benefit formula, all employees became fully vested in
retirement benefits earned through December 31, 1994. The
formula in place prior to January 1, 1995 was suspended and
replaced with a benefit accrual in the form of a cash balance of
5% of annual base pay beginning January 1, 1996. Under the Cash
Balance Plan, each employee's accrued benefit will be credited
with interest based on ten-year Treasury Bond yields.
Enron also maintains a noncontributory employee stock
ownership plan ("ESOP") which covers all eligible employees.
Allocations to individual employees' retirement accounts within
the ESOP offset a portion of benefits earned under the Cash
Balance Plan prior to December 31, 1994. December 31, 1993 was
the final date on which ESOP allocations were made to employees'
retirement accounts.
In addition, Enron has a Supplemental Retirement Plan that
is designed to assure payments to certain employees of that
retirement income that would be provided under the Cash Balance
Plan except for the dollar limitation on accrued benefits imposed
by the Internal Revenue Code of 1986, as amended, and a Pension
Program for Deferral Plan Participants that provides supplemental
retirement benefits equal to any reduction in benefits due to
deferral of salary into Enron's Deferral Plan.
The following table sets forth the estimated annual benefits
payable under normal retirement at age 65, assuming current
remuneration levels without any salary or bonus projections and
participation until normal retirement at age 65, with respect to
the Named Officers under the provisions of the foregoing
retirement plans.
Estimated
Current Credited Current Estimated
Credited Years of Compensation Annual Benefit
Years of Service Covered Payable Upon
Service at Age 65 By Plans Retirement
Mr. Cordes 30.4 43.1 $311,000 $142,234
Mr. Peters 15.9 37.8 $145,293 $ 78,957
________
NOTE: The estimated annual benefits payable are based on the
straight life annuity form without adjustment for any offset
applicable to a participant's retirement subaccount in
Enron's ESOP.
Mr. DeRoin participates in the Executive Supplemental
Survivor Benefit Plan. In the event of death after retirement,
the Plan provides an annual benefit to the participant's
beneficiary equal to 50 percent of the participant's annual base
salary at retirement, paid for 10 years. The Plan also provides
that in the event of death before retirement, the participant's
beneficiary receives an annual benefit equal to 30% of the
participant's annual base salary at death, paid for the life of
the participant's spouse (but for no more than 20 years in some
cases).
Severance Plans
Enron's Severance Pay Plan, as amended, provides for the
payment of benefits to employees who are terminated for failing
to meet performance objectives or standards or who are terminated
due to reorganization or economic factors. The amount of
benefits payable for performance related terminations is based on
length of service and may not exceed six weeks' pay. For those
terminated as the result of reorganization or economic
circumstances, the benefit is based on length of service and
amount of pay up to a maximum payment of 26 weeks of base pay.
If the employee signs a Waiver and Release of Claims Agreement,
the severance pay benefits are doubled. Under no circumstances
will the total severance pay benefit exceed 52 weeks of pay.
Under the Enron Corp. Change of Control Severance Plan, in the
event of an unapproved change of control of Enron, any employee
who is involuntarily terminated within two years following the
change of control will be eligible for severance benefits equal
to two weeks of base pay multiplied by the number of full or
partial years of service, plus one month of base pay for each
$10,000 (or portion of $10,000) included in the employee's annual
base pay, plus one month of base pay for each five percent of
annual incentive award opportunity under any approved plan. The
maximum an employee can receive is 2.99 times the employee's
average W-2 earnings over the past five years.
Item 12. Security Ownership of Certain Beneficial
Owners and Management
The following table sets forth the beneficial ownership of
the voting securities of the Partnership as of February 15, 2001
by our executive officers, members of the Partnership Policy
Committee and the Audit Committee who own units and by certain
beneficial owners. Other than as set forth below, no person is
known by the general partners to own beneficially more than 5% of
the voting securities.
Amount and Nature of Beneficial Ownership
Common Units
Number Percent
of Units1/ of Class
Jerry L. Peters 1,000 *
1111 South 103rd Street
Omaha, NE 68124-1000
Stanley C. Horton
1400 Smith Street
Houston, TX 77002-7369 10,000 *
The Williams Companies, Inc.2/ 1,123,500 3.6
One Williams Center
Tulsa, OK 74101-3288
Enron Corp.2/
1400 Smith Street
Houston, TX 77002 3,215,452 10.2
Duke Energy Corp.2/
422 So. Church St.
Charlotte, NC 88242-0001 2,086,500 6.6
______________
* Less than 1%.
1/ All units involve sole voting and investment power.
2/ Indirect ownership through their subsidiaries.
Item 13. Certain Relationships and Related Transactions
We have extensive ongoing relationships with the general
partners. Such relationships include the following: (i) Northern
Plains provides, in its capacity as the operator of the Northern
Border pipeline system, certain tax, accounting and other
information to the Partnership, (ii) NBP Services, an affiliate
of Enron, assists the Partnership in connection with the
operation and management of the Partnership and operating
services for Crestone Energy Ventures pursuant to the terms of an
Administrative Services Agreement between the Partnership and NBP
Services, (iii) NBP Energy Pipelines, L.L.C. (now known as
Crestone Energy Ventures, L.L.C) purchased from Enron North
America Corp., an affiliate of Enron, interests in gas gathering
businesses in the Powder River and Wind River Basins in Wyoming
for approximately $209 million, and (iv) Crestone Energy Ventures
provides to Enron North America Corp., under a Master Services
Agreement effective September 21, 2000, gas and administrative
services for fixed and variable fees. The amount of fixed fees
for 2000 was $45,000 per day and for 2001 is $21,600 per day.
In addition, Northern Border Pipeline has extensive ongoing
relationships with the general partners and certain of their
affiliates and with affiliates of TC PipeLines. For example,
Northern Plains has acted (since 1980), and will continue to act,
as the operator of the pipeline system pursuant to the terms of
an operating agreement between Northern Plains and Northern
Border Pipeline.
In addition, as of February 1, 2001:
* Enron North America Corp., an affiliate of Enron, is one of
Northern Border Pipeline's firm shippers, and is obligated
to pay for 6.3% of the capacity. It also has contracted
with Crestone Energy Venture and Crestone Gas Services for
certain gas and administrative services for which it pays
both a fixed and variable fee.
* TransCanada Energy Marketing USA, Inc., an affiliate of
TransCanada PipeLines Limited, is one of Northern Border
Pipeline's firm shippers and is currently obligated to pay
for 11.4% of the capacity;
* Transcontinental Gas Pipe Line Corporation, an affiliate of
Williams, is one of Northern Border Pipeline's firm shippers
and is currently obligated to pay for 0.8% of the capacity;
and
* Northern Natural Gas Company, an affiliate of Enron,
provides a financial guaranty for a portion of the
transportation capacity held by Pan-Alberta Gas, which
currently represents 10.5% of the capacity.
The Partnership Policy Committee, whose members are
designated by our three general partners, establishes the
business policies of the Partnership. We have three
representatives on the Northern Border Management Committee, each
of whom votes a portion of the Partnership's 70% interest on the
Northern Border Management Committee. These representatives are
also designated by our general partners.
Our interests could conflict with the interests of our
general partners or their affiliates, and in such case the
members of the Partnership Policy Committee will generally have a
fiduciary duty to resolve such conflicts in a manner that is in
our best interest. Northern Border Pipeline's interests could
conflict with the our interest or the interest of TC PipeLines
and their affiliates, and in such case our representatives on the
Northern Border Management Committee will generally have a
fiduciary duty to resolve such conflicts in a manner that is in
the best interest of Northern Border Pipeline. Our fiduciary
duty as a general partner of Northern Border Pipeline may
restrict the Partnership from taking actions that might be in our
best interest but in conflict with the fiduciary duty that our
representatives or we owe to TC PipeLines.
Unless otherwise provided for in a partnership agreement,
the laws of Delaware and Texas generally require a general
partner of a partnership to adhere to fiduciary duty standards
under which it owes its partners the highest duties of good
faith, fairness and loyalty. Similar rules apply to persons
serving on the Partnership Policy Committee or the Northern
Border Management Committee. Because of the competing interests
identified above, our Partnership Agreement and the partnership
agreement for Northern Border Pipeline contain provisions that
modify certain of these fiduciary duties. For example:
* The Partnership Agreement states that the general partners,
their affiliates and their officers and directors will not be
liable for damages to the Partnership, its limited partners or
their assignees for errors of judgment or for any acts or
omissions if the general partners and such other persons acted in
good faith.
* The Partnership Agreement allows the general partners and
the Partnership Policy Committee to take into account the
interests of parties in addition to our interest in resolving
conflicts of interest.
* The Partnership Agreement provides that the general partners
will not be in breach of their obligations under the Partnership
Agreement or their duties to us or our unitholders if the
resolution of a conflict is fair and reasonable to us. The
latitude given in the Partnership Agreement in connection with
resolving conflicts of interest may significantly limit the
ability of a unitholder to challenge what might otherwise be a
breach of fiduciary duty.
* The Partnership Agreement provides that a purchaser of
Common Units is deemed to have consented to certain conflicts of
interest and actions of the general partners and their affiliates
that might otherwise be prohibited and to have agreed that such
conflicts of interest and actions do not constitute a breach by
the general partners of any duty stated or implied by law or
equity.
* Our Audit Committee will, at the request of a general
partner or a member of the Partnership Policy Committee, review
conflicts of interest that may arise between a general partner
and its affiliates (or the member of the Partnership Policy
Committee designated by it), on the one hand, and the unitholders
or us, on the other. Any resolution of a conflict approved by
the Audit Committee is conclusively deemed fair and reasonable to
us.
* We entered into an amendment to the partnership agreement
for Northern Border Pipeline that relieves us and TC PipeLines,
their affiliates and their transferees from any duty to offer
business opportunities to Northern Border Pipeline, with certain
exceptions.
We are required to indemnify the members of the Partnership
Policy Committee and general partners, their affiliates and their
respective officers, directors, employees, agents and trustees to
the fullest extent permitted by law against liabilities, costs
and expenses incurred by any such person who acted in good faith
and in a manner reasonably believed to be in, or (in the case of
a person other than one of the general partners) not opposed to,
the Partnership's best interests and with respect to any criminal
proceedings, had no reasonable cause to believe the conduct was
unlawful.
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K
(a)(1) and (2) Financial Statements and Financial Statement Schedules
See "Index to Financial Statements" set forth on page F-1.
(a)(3) Exhibits
* 3.1 Form of Amended and Restated Agreement of
Limited Partnership of Northern Border
Partners, L.P. (Exhibit 3.1 No. 2 to the
Partnership's Form S-1 Registration
Statement, Registration No. 33-66158
("Form S-1")).
* 3.2 Form of Amended and Restated Agreement of
Limited Partnership For Northern Border
Intermediate Limited Partnership (Exhibit
10.1 to Form S-1).
* 4.1 Indenture, dated as of June 2, 2000,
between the registrants and Bank One
Trust Company, N.A. (Exhibit 4.1 to the
Partnership's Quarterly Report on Form 10-Q
for the quarterly period ended June 30,
2000 ("June 2000 10-Q")).
* 4.2 First Supplemental Indenture, dated as of
September 14, 2000, between the
registrants and Bank One Trust Company,
N.A.(Exhibit 4.2 to Form S-4 Registration
Statement, Registration No. 333-46212
("NBP Form S-4")).
4.3 Indenture, dated as of March 21, 2001,
between Northern Border Partners, L.P.
and Northern Border Intermediate Limited
Partnership and Bank One Trust Company,
N.A., Trustee.
4.4 Registration Rights Agreement dated March
21, 2001 by and among Northern Border
Partners, L.P., Northern Border
Intermediate Limited Partnership, Banc of
America Securities LLC, SunTrust
Equitable Securities Corporation, Banc
One Capital Markets, Inc. and BMO Nesbitt
Burns Corp.
* 4.5 Indenture, dated as of August 17, 1999,
between Northern Border Pipeline Company
and Bank One Trust Company, NA, successor
to The First National Bank of Chicago, as
trustee. (Exhibit No. 4.1 to Northern
Border Pipeline Company's Form S-4
Registration Statement, Registration No.
333-88577 ("NB Form S-4").
*10.1 Northern Border Pipeline Company General
Partnership Agreement between Northern
Plains Natural Gas Company, Northwest
Border Pipeline Company, Pan Border Gas
Company, TransCanada Border Pipeline Ltd.
and TransCan Northern Ltd., effective
March 9, 1978, as amended (Exhibit 10.2
to Form S-1).
*10.2 Operating Agreement between Northern
Border Pipeline Company and Northern
Plains Natural Gas Company, dated
February 28, 1980 (Exhibit 10.3 to Form S-1).
*10.3 Administrative Services Agreement between
NBP Services Corporation, Northern Border
Partners, L.P. and Northern Border
Intermediate Limited Partnership (Exhibit
10.4 to Form S-1).
*10.4 Note Purchase Agreement between Northern
Border Pipeline Company and the parties
listed therein, dated July 15, 1992
(Exhibit 10.6 to Form S-1).
*10.4.1 Supplemental Agreement to the Note
Purchase Agreement dated as of June 1,
1995 (Exhibit 10.6.1 to the Partnership's
Annual Report on Form 10-K for the year
ended December 31, 1995 ("1995 10-K")).
*10.5 Guaranty made by Panhandle Eastern
Pipeline Company, dated October 31, 1992
(Exhibit 10.9 to Form S-1).
*10.6 Northern Border Pipeline Company U.S.
Shippers Service Agreement between
Northern Border Pipeline Company and
Enron Gas Marketing, Inc., dated June 22,
1990 (Exhibit 10.10 to Form S-1).
*10.6.1 Amended Exhibit A to Northern Border
Pipeline Company U.S. Shippers Service
Agreement between Northern Border
Pipeline Company and Enron Gas Marketing,
Inc. (Exhibit 10.10.1 to the
Partnership's Annual Report on Form 10-K
for the year ended December 31, 1993
("1993 10-K")).
*10.6.2 Amended Exhibit A to Northern Border
Pipeline U.S. Shippers Service Agreement
between Northern Border Pipeline Company
and Enron Gas Marketing, Inc., effective
November 1, 1994 (Exhibit 10.10.2 to the
Partnership's Annual Report on Form 10-K
for the year ended December 31, 1994).
*10.6.3 Amended Exhibit A's to Northern Border
Pipeline Company U.S. Shipper Service
Agreement effective, August 1, 1995 and
November 1, 1995 (Exhibit 10.10.3 to 1995
10-K).
*10.6.4 Amended Exhibit A to Northern Border
Pipeline Company U.S. Shipper Service
Agreement effective April l, 1998
(Exhibit 10.10.4 to the Partnership's
Annual Report on Form 10-K for the year
ended December 31, 1997 ("1997 10-K")).
*10.7 Guaranty made by Northern Natural Gas
Company, dated October 7, 1993 (Exhibit
10.11.1 to 1993 10-K).
*10.8 Guaranty made by Northern Natural Gas
Company, dated October 7, 1993 (Exhibit
10.11.2 to 1993 10-K).
*10.9 Northern Border Pipeline Company U.S.
Shippers Service Agreement between
Northern Border Pipeline Company and
Western Gas Marketing Limited, as agent
for TransCanada PipeLines Limited, dated
December 15, 1980 (Exhibit 10.13 to Form
S-1).
*10.9.1 Amendment to Northern Border Pipeline
Company Service Agreement extending the
term effective November 1, 1995 (Exhibit
10.13.1 to 1995 10-K).
*10.10 Form of Seventh Supplement Amending
Northern Border Pipeline Company General
Partnership Agreement (Exhibit 10.15 to
Form S-1).
*10.11 Northern Border Pipeline Company U.S.
Shippers Service Agreement between
Northern Border Pipeline Company and
Transcontinental Gas Pipe Line
Corporation, dated July 14, 1983, with
Amended Exhibit A effective February 11,
1994 (Exhibit 10.17 to 1995 10-K).
*10.12 Form of Credit Agreement among Northern
Border Pipeline Company, The First
National Bank of Chicago, as
Administrative Agent, The First National
Bank of Chicago, Royal Bank of Canada,
and Bank of America National Trust and
Savings Association, as Syndication
Agents, First Chicago Capital Markets,
Inc., Royal Bank of Canada, and
BancAmerica Securities, Inc, as Joint
Arrangers and Lenders (as defined
therein) dated as of June 16, 1997
(Exhibit 10(c) to Amendment No. 1 to Form
S-3, Registration Statement No. 333-40601
("Form S-3")).
*10.13 Northern Border Pipeline Company U.S.
Shippers Service Agreement between
Northern Border Pipeline Company and
Enron Capital & Trade Resources Corp.
dated October 15, 1997 (Exhibit 10.21 to
1997 10-K).
*10.14 Northern Border Pipeline Company U.S.
Shippers Service Agreement between
Northern Border Pipeline Company and
Enron Capital & Trade Resources Corp.
dated October 15, 1997 (Exhibit 10.22 to
1997 10-K).
*10.15 Northern Border Pipeline Company U.S.
Shippers Service Agreement between
Northern Border Pipeline Company and
Enron Capital & Trade Resources Corp.
dated August 5, 1997 with Amendment dated
September 25, 1997 (Exhibit 10.25 to 1997
10-K).
*10.16 Northern Border Pipeline Company U.S.
Shippers Service Agreement between
Northern Border Pipeline Company and
Enron Capital & Trade Resources Corp.
dated August 5, 1997 (Exhibit 10.26 to
1997 10-K).
*10.17 Northern Border Pipeline Company U.S.
Shippers Service Agreement between
Northern Border Pipeline Company and
TransCanada Gas Services Inc., as agent
for TransCanada PipeLines Limited dated
August 5, 1997 (Exhibit 10.27 to 1997
10-K).
*10.18 Project Management Agreement by and
between Northern Plains Natural Gas
Company and Enron Engineering &
Construction Company, dated March 1, 1996
(Exhibit No. 10.39 to NB Form S-4).
*10.19 Eighth Supplement Amending Northern
Border Pipeline Company General
Partnership Agreement (Exhibit 10.15 to
NB Form S-4).
10.20 Revolving Credit Agreement, dated as of
March 21, 2001, between Northern Border
Partners, L.P., SunTrust Bank,
Administrative Agent, Bank of Montreal
and Bank of America, N.A., Co-Syndication
Agents and Bank One, NA, Documentation
Agent and Lenders (as defined therein).
*10.21 Northern Border Pipeline Company U.S.
Shippers Service Agreement between
Northern Border Pipeline Company and Pan-
Alberta Gas (US) Inc., dated October 1,
1993, with Amended Exhibit A effective
June 22, 1998 (Exhibit 10.36 to Northern
Border Pipeline Company Annual Report on
Form 10-K for the year ended December 31,
1999 ("NB Pipeline 1999 10-K")).
*10.22 Northern Pipeline Company U.S. Shippers
Service Agreement between Northern Border
Pipeline Company and Pan-Alberta Gas (US)
Inc.,(successor to Natgas U.S. Inc.)
dated October 6, 1989, with Amended
Exhibit A effective April 2, 1999
(Exhibit 10.37 to NB Pipeline 1999 10-K).
*10.23 Northern Border Pipeline Company U.S.
Shippers Service Agreement between
Northern Border Pipeline Company and Pan-
Alberta Gas (U.S.) Inc., dated October l,
1992, with Amended Exhibit A effective
June 22, 1998 (Exhibit 10.38 to NB
Pipeline 1999 10-K).
10.24 Purchase and Sale Agreement, dated as of
September 21, 2000 by and between Enron
North America Corp. and NBP Energy
Pipeline, L.L.C.(now known as Crestone
Energy Ventures, L.L.C.).
10.25 Master Services Agreement, dated as of
September 21, 2000 between NBP Energy
Pipelines, L.L.C.,(now known as Crestone
Energy Ventures, L.L.C.) and Enron North
America Corp.
10.26 Acquisition Agreement, dated as of March
14, 2001, among Northern Border Partners,
L.P., Northern Border Intermediate
Limited Partnership, Bear Paw
Investments, LLC, Bear Paw Energy, LLC
and Sellers (defined therein).
21 The subsidiaries of Northern Border
Partners, L.P. are Northern Border
Intermediate Limited Partnership;
Northern Border Pipeline Company; and
Crestone Energy Ventures, L.L.C.
23.01 Consent of Arthur Andersen LLP.
*99.1 Northern Border Phantom Unit Plan
(Exhibit 99.1 to Amendment No. 1 to Form
S-8, Registration No. 333-66949).
*Indicates exhibits incorporated by reference as
indicated; all other exhibits are filed herewith.
(b)Reports
The Partnership filed a Current Report on Form 8-K,
dated November 2, 2000, reporting the public
offering of up to 2,156,250 common units
representing limited partner interests and
including exhibits.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned,
thereunto duly authorized on this 29th day of March, 2001.
NORTHERN BORDER PARTNERS, L.P.
(A Delaware Limited Partnership)
By: WILLIAM R. CORDES
William R. Cordes
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons
in the capacities and on the dates indicated.
Signature Title Date
WILLIAM R. CORDES Chief Executive Officer and March 29, 2001
William R. Cordes Chairman of the Partnership
Policy Committee
(Principal Executive Officer)
STANLEY C. HORTON Member of Partnership Policy March 29, 2001
Stanley C. Horton Committee
CUBA WADLINGTON, JR. Member of Partnership Policy March 29, 2001
Cuba Wadlington, Jr. Committee
JERRY L. PETERS Chief Financial and March 29, 2001
Jerry L. Peters Accounting Officer
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
INDEX TO FINANCIAL STATEMENTS
Page No.
Consolidated Financial Statements
Report of Independent Public Accountants F-2
Consolidated Balance Sheet - December 31, 2000 and 1999 F-3
Consolidated Statement of Income - Years Ended F-4
December 31, 2000, 1999 and 1998
Consolidated Statement of Cash Flows - Years Ended F-5
December 31, 2000, 1999 and 1998
Consolidated Statement of Changes in Partners' Capital -
Years Ended December 31, 2000, 1999 and 1998 F-6
Notes to Consolidated Financial Statements F-7 through
F-26
Financial Statements Schedule
Report of Independent Public Accountants on Schedule S-1
Schedule II - Valuation and Qualifying Accounts S-2
Report of Independent Public Accountants
To Northern Border Partners, L.P.:
We have audited the accompanying consolidated balance sheet of
Northern Border Partners, L.P. (a Delaware limited partnership)
and Subsidiaries as of December 31, 2000 and 1999, and the
related consolidated statements of income, cash flows and changes
in partners' capital for each of the three years in the period
ended December 31, 2000. These financial statements are the
responsibility of the Company's management. Our responsibility
is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with auditing standards
generally accepted in the United States. Those standards require
that we plan and perform the audit to obtain reasonable assurance
about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as
well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the financial statements referred to above
present fairly, in all material respects, the financial position
of Northern Border Partners, L.P. and Subsidiaries as of December
31, 2000 and 1999, and the results of their operations and their
cash flows for each of the three years in the period ended
December 31, 2000, in conformity with accounting principles
generally accepted in the United States.
ARTHUR ANDERSEN LLP
Omaha, Nebraska,
January 22, 2001
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(In Thousands)
December 31,
ASSETS 2000 1999
CURRENT ASSETS
Cash and cash equivalents $ 35,363 $ 22,927
Accounts receivable 31,538 24,946
Related party receivables 9,079 5,292
Materials and supplies, at cost 5,736 4,410
Under recovered cost of service -- 3,068
Total current assets 81,716 60,643
TRANSMISSION PLANT
Property, plant and equipment 2,454,918 2,410,133
Less: Accumulated provision for
depreciation and amortization 722,842 664,777
Property, plant and equipment, net 1,732,076 1,745,356
INVESTMENTS AND OTHER ASSETS
Investments in unconsolidated affiliates 221,625 31,895
Goodwill 28,405 9,076
Other 18,898 16,467
Total investments and other assets 268,928 57,438
Total assets $2,082,720 $1,863,437
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES
Current maturities of long-term debt $ 44,464 $ 183,617
Accounts payable 35,413 8,279
Accrued taxes other than income 28,493 26,608
Accrued interest 15,635 17,608
Accumulated provision for rate refunds 4,726 2,317
Total current liabilities 128,731 238,429
LONG-TERM DEBT, net of current maturities 1,127,498 848,369
MINORITY INTERESTS IN PARTNERS' CAPITAL 248,098 250,450
RESERVES AND DEFERRED CREDITS 6,119 10,920
COMMITMENTS AND CONTINGENCIES (NOTE 9)
PARTNERS' CAPITAL
General Partners 11,445 10,305
Common Units 560,829 504,964
Total partners' capital 572,274 515,269
Total liabilities and partners' capital $2,082,720 $1,863,437
The accompanying notes are an integral part of these consolidated
financial statements.
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF INCOME
(In Thousands, Except Per Unit Amounts)
Year Ended December 31,
2000 1999 1998
OPERATING REVENUES
Operating revenues $363,688 $321,280 $217,592
Provision for rate refunds (23,956) (2,317) --
Operating revenues, net 339,732 318,963 217,592
OPERATING EXPENSES
Operations and maintenance 62,097 53,451 44,770
Depreciation and amortization 60,699 54,842 43,885
Taxes other than income 28,634 30,952 22,012
Regulatory credit -- -- (8,878)
Operating expenses 151,430 139,245 101,789
OPERATING INCOME 188,302 179,718 115,803
INTEREST EXPENSE
Interest expense 81,881 67,807 49,923
Interest expense capitalized (386) (98) (19,001)
Interest expense, net 81,495 67,709 30,922
OTHER INCOME
Allowance for equity funds used
during construction 305 101 10,237
Equity earnings (losses) of
unconsolidated affiliates (647) -- --
Other income, net 8,374 4,461 2,971
Other income 8,032 4,562 13,208
MINORITY INTERESTS IN NET INCOME 38,119 35,568 30,069
NET INCOME TO PARTNERS $ 76,720 $ 81,003 $ 68,020
NET INCOME PER UNIT $ 2.50 $ 2.70 $ 2.27
NUMBER OF UNITS USED IN COMPUTATION 29,665 29,347 29,345
The accompanying notes are an integral part of these consolidated
financial statements.
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
(In Thousands)
Year Ended December 31,
2000 1999 1998
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income to partners $ 76,720 $ 81,003 $ 68,020
Adjustments to reconcile net income to partners
to net cash provided by operating activities:
Depreciation and amortization 61,054 54,895 43,899
Minority interests in net income 38,119 35,568 30,069
Provision for rate refunds 25,082 2,317 --
Rate refunds paid (22,673) -- --
Allowance for equity funds used
during construction (305) (101) (10,237)
Reserves and deferred credits (4,801) 1,077 (24)
Regulatory credit -- -- (9,105)
Changes in components of working capital (2,279) (1,482) (19,243)
Other (1,302) 91 470
Total adjustments 92,895 92,365 35,829
Net cash provided by operating activities 169,615 173,368 103,849
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for property, plant
and equipment, net (19,721) (102,270) (652,194)
Acquisition of businesses (229,505) (31,895) --
Investments in unconsolidated affiliates (8,766) -- --
Net cash used in investing activities (257,992) (134,165) (652,194)
CASH FLOWS FROM FINANCING ACTIVITIES:
Cash distributions
General and limited partners (80,411) (73,160) (68,876)
Minority Interests (40,471) (38,149) (18,362)
Contributions received from Minority Interests -- -- 66,900
Issuance of partnership interests, net 60,696 -- 7,554
Issuance of long-term debt, net 431,148 313,526 498,000
Retirement of long-term debt (304,817) (270,805) (2,523)
Increase in cash overdraft 22,437 -- --
Proceeds received upon termination of derivatives 15,005 12,896 --
Long-term debt financing costs (2,774) (1,626) (63)
Net cash provided by (used in)
financing activities 100,813 (57,318) 482,630
NET CHANGE IN CASH AND CASH EQUIVALENTS 12,436 (18,115) (65,715)
Cash and cash equivalents-beginning of year 22,927 41,042 106,757
Cash and cash equivalents-end of year $ 35,363 $ 22,927 $ 41,042
Changes in components of working capital:
Accounts receivable $ (8,502) $ (8,691) $ (1,628)
Materials and supplies (1,313) (221) 269
Accounts payable 4,755 (3,897) (11,830)
Accrued taxes other than income 1,686 6,468 (368)
Accrued interest (1,973) 5,146 1,696
Over/under recovered cost of service 3,068 (287) (7,382)
Total $ (2,279) $ (1,482) $ (19,243)
The accompanying notes are an integral part of these consolidated
financial statements.
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' CAPITAL
(In Thousands)
Total
General Common Subordinated Partners'
Partners Units Units Capital
Partners' Capital at December 31, 1997 $10,015 $394,587 $ 96,126 $500,728
Net income to partners 1,359 52,077 14,584 68,020
Issuance of partnership interests, net 151 7,457 (54) 7,554
Distributions paid (1,377) (52,733) (14,766) (68,876)
Partners' Capital at December 31, 1998 10,148 401,388 95,890 507,426
Subordinated Units converted to
Common Units -- 95,890 (95,890) --
Net income to partners 1,710 79,293 -- 81,003
Distributions paid (1,553) (71,607) -- (73,160)
Partners' Capital at December 31, 1999 10,305 504,964 -- 515,269
Net income to partners 2,566 74,154 -- 76,720
Issuance of partnership interests, net 1,214 59,482 -- 60,696
Distributions paid (2,640) (77,771) -- (80,411)
Partners' Capital at December 31, 2000 $11,445 $560,829 $ -- $572,274
The accompanying notes are an integral part of these consolidated
financial statements.
NORTHERN BORDER PARTNERS, L. P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND MANAGEMENT
Northern Border Partners, L.P., a Delaware limited partnership,
through a subsidiary limited partnership, Northern Border
Intermediate Limited Partnership, a Delaware limited partnership,
collectively referred to herein as the Partnership, owns a 70%
general partner interest in Northern Border Pipeline Company
(Northern Border Pipeline). The remaining 30% general partner
interest in Northern Border Pipeline is owned by TC PipeLines
Intermediate Limited Partnership (TC PipeLines). Black Mesa
Holdings, Inc. (Black Mesa) and Crestone Energy Ventures, L.L.C.
(Crestone Energy Ventures)(formerly NBP Energy Pipelines, L.L.C.)
are wholly-owned subsidiaries of the Partnership.
Northern Plains Natural Gas Company (Northern Plains), a wholly-
owned subsidiary of Enron Corp. (Enron), Pan Border Gas Company (Pan
Border), a wholly-owned subsidiary of Northern Plains, and Northwest
Border Pipeline Company (Northwest Border), a wholly-owned
subsidiary of The Williams Companies, Inc. serve as the General
Partners of the Partnership and collectively own a 2% general
partner interest in the Partnership. In December 1998, Northern
Plains acquired Pan Border from a subsidiary of Duke Energy
Corporation. At the closing of the acquisition, Pan Border's sole
asset consisted of its general partner interest in the Partnership.
The General Partners or their affiliates also own common units
representing, in the aggregate, an effective 13.5% limited partner
interest in the Partnership at December 31, 2000 (see Note 8).
The Partnership is managed by or is under the direction of a
committee (Partnership Policy Committee) consisting of one person
appointed by each General Partner. The members appointed by
Northern Plains, Pan Border and Northwest Border have 50%, 32.5% and
17.5%, respectively, of the voting interest on the Partnership
Policy Committee. The Partnership has entered into an
administrative services agreement with NBP Services Corporation (NBP
Services), a wholly-owned subsidiary of Enron, pursuant to which NBP
Services provides certain administrative, operating and management
services for the Partnership and is reimbursed for its direct and
indirect costs and expenses.
Northern Border Pipeline is a general partnership, formed in 1978,
pursuant to the Texas Uniform Partnership Act. Northern Border
Pipeline owns a 1,214-mile natural gas transmission pipeline system
extending from the United States-Canadian border near Port of
Morgan, Montana, to a terminus near Manhattan, Illinois.
Northern Border Pipeline is managed by a Management Committee that
includes three representatives from the Partnership (one
representative appointed by each of the General Partners of the
Partnership) and one representative from TC PipeLines. The
Partnership's representatives selected by Northern Plains, Pan
Border and Northwest Border have 35%, 22.75% and 12.25%,
respectively, of the voting interest on the Northern Border Pipeline
Management Committee. The representative designated by TC PipeLines
votes the remaining 30% interest. The day-to-day management of
Northern Border Pipeline's affairs is the responsibility of Northern
Plains (the Operator), as defined by the operating agreement between
Northern Border Pipeline and Northern Plains. Northern Border
Pipeline is charged for the salaries, benefits and expenses of the
Operator. For the years ended December 31, 2000, 1999 and 1998,
Northern Border Pipeline reimbursed the Operator approximately $31.7
million, $29.7 million and $30.0 million, respectively.
Additionally, Northern Border Pipeline utilizes Enron affiliates for
management on pipeline expansion and extension projects.
The Northern Border Pipeline partnership agreement provides that
distributions to Northern Border Pipeline's partners are to be made
on a pro rata basis according to each partner's capital account
balance. The Northern Border Pipeline Management Committee
determines the amount and timing of such distributions. Any changes
to, or suspension of, the cash distribution policy of Northern
Border Pipeline requires the unanimous approval of the Northern
Border Pipeline Management Committee.
Crestone Energy Ventures owns a 49% common membership interest and a
100% class A share interest in Bighorn Gas Gathering, L.L.C.
(Bighorn); a 33% interest in Fort Union Gas Gathering, L.L.C. (Fort
Union); and a 35% interest in Lost Creek Gathering, L.L.C. (Lost
Creek). Crestone Gathering Services, L.L.C. (Crestone Gathering
Services) is a wholly-owned subsidiary of Crestone Energy Ventures.
Crestone Energy Ventures acquired its interests in Fort Union, Lost
Creek, Crestone Gathering Services and a portion of Bighorn in
September 2000 (see Note 3). Collectively, Crestone Gathering
Services, Bighorn, Fort Union and Lost Creek own over 300 miles of
gas gathering facilities in Wyoming. The gathering facilities
interconnect to the interstate gas pipeline grid serving gas markets
in the Rocky Mountains, the Midwest and California. NBP Services
provides certain administrative and management services for Crestone
Energy Ventures.
Black Mesa, through a wholly-owned subsidiary, owns a 273-mile, 18-
inch diameter coal slurry pipeline that originates at a coal mine in
Kayenta, Arizona and ends at the 1,500 megawatt Mohave Power Station
located in Laughlin, Nevada.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(A) Principles of Consolidation and Use of Estimates
The consolidated financial statements include the assets,
liabilities and results of operations of the Partnership and its
majority-owned subsidiaries. The Partnership operates through a
subsidiary limited partnership of which the Partnership is the
sole limited partner and the General Partners are the sole
general partners. The 30% ownership of Northern Border Pipeline
by TC PipeLines is accounted for as a minority interest.
All significant intercompany items have been eliminated in
consolidation.
The preparation of financial statements in conformity with
accounting principles generally accepted in the United States
requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues
and expenses during the reporting period. Actual results could
differ from those estimates.
(B) Government Regulation
Northern Border Pipeline is subject to regulation by the
Federal Energy Regulatory Commission (FERC). Northern Border
Pipeline's accounting policies conform to Statement of Financial
Accounting Standards (SFAS) No. 71, "Accounting for the Effects
of Certain Types of Regulation." Accordingly, certain assets
that result from the regulated ratemaking process are recorded
that would not be recorded under generally accepted accounting
principles for nonregulated entities. At December 31, 2000 and
1999, Northern Border Pipeline has reflected regulatory assets
of approximately $12.4 million and $12.1 million, respectively,
in Other Assets on the consolidated balance sheet. Northern
Border Pipeline is recovering the regulatory assets from its
shippers over varying time periods, which range from four to 43
years.
(C) Revenue Recognition
Northern Border Pipeline transports gas for shippers under a tariff
regulated by the FERC. The tariff specifies the calculation of
amounts to be paid by shippers and the general terms and conditions
of transportation service on the pipeline system. Northern Border
Pipeline's revenues are derived from agreements for the receipt and
delivery of gas at points along the pipeline system as specified in
each shipper's individual transportation contract. Northern Border
Pipeline does not own the gas that it transports, and therefore it
does not assume the related natural gas commodity risk. See Notes 4
and 5 for a further discussion of Northern Border Pipeline's tariff
and transportation agreements.
(D) Cash and Cash Equivalents
Cash equivalents consist of highly liquid investments with
original maturities of three months or less. The carrying
amount of cash and cash equivalents approximates fair value
because of the short maturity of these investments.
(E) Income Taxes
Income taxes are the responsibility of the partners and are
not reflected in these financial statements. However, the
Northern Border Pipeline tariff establishes the method of
accounting for and calculating income taxes and requires
Northern Border Pipeline to reflect in its financial records the
income taxes which would have been paid or accrued if Northern
Border Pipeline were organized during the period as a
corporation. As a result, for purposes of determining
transportation rates in calculating the return allowed by the
FERC, partners' capital and rate base are reduced by the amount
equivalent to the net accumulated deferred income taxes. Such
amounts were approximately $326 million and $316 million at
December 31, 2000 and 1999, respectively, and are primarily
related to accelerated depreciation and other plant-related
differences.
(F) Property, Plant and Equipment and Related Depreciation and
Amortization
Property, plant and equipment is stated at original cost. The
original cost of utility property retired is charged to
accumulated depreciation and amortization, net of salvage and
cost of removal. No retirement gain or loss is included in
income except in the case of extraordinary retirements or sales.
Maintenance and repairs are charged to operations in the
period incurred. The provision for depreciation and
amortization of the transmission line is an integral part of
Northern Border Pipeline's FERC tariff. The effective
depreciation rates applied to Northern Border Pipeline's
transmission plant in 2000, 1999 and 1998 were 2.25%, 2.0% and
2.5%, respectively. Based upon the rate case settlement
discussed in Note 4, Northern Border Pipeline will continue to
use a 2.25% depreciation rate. The effective depreciation rate
applied to Crestone Energy Venture's gathering facilities was
3.33%. Composite rates are applied to all other functional
groups of property having similar economic characteristics.
(G) Allowance for Funds Used During Construction
The allowance for funds used during construction (AFUDC)
represents the estimated costs, during the period of
construction, of funds used for construction purposes. For
regulated activities, Northern Border Pipeline is permitted to
earn a return on and recover AFUDC through its inclusion in rate
base and the provision for depreciation.
(H) Investments in Unconsolidated Affiliates
The investments in unconsolidated affiliates are accounted for
by the equity method. The excess of the Partnership's
investments in unconsolidated affiliates over the underlying
equity in the fair value of the net assets acquired is being
amortized on a straight-line basis over 30 years. During 2000,
the Partnership recorded amortization expense of $2.2 million
related to its investments in unconsolidated affiliates, which
is reflected as a component of equity earnings (losses) of
unconsolidated affiliates in the Partnership's consolidated
statement of income. See Note 7 for details on the
Partnership's investments in unconsolidated affiliates and
related equity earnings (losses).
(I) Goodwill
Goodwill consists of the excess of cost over fair value of the
net assets acquired in business acquisitions and is being
amortized using a straight-line method over 30 years. During
2000, 1999 and 1998, the Partnership recorded amortization
expense of $0.5 million, $0.3 million and $0.3 million,
respectively. This amortization expense is reflected as a
component of depreciation and amortization in the Partnership's
consolidated statement of income.
(J) Risk Management
Financial instruments are used in the management of the
Partnership's interest rate 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. As a result, Northern Border
Pipeline has entered into various interest rate swap agreements
with major financial institutions which hedge interest rate risk
by effectively converting certain of its floating rate debt to
fixed rate debt. Northern Border Pipeline does not use these
instruments for trading purposes. The cost or benefit of the
interest rate swap agreements is recognized currently as a
component of interest expense.
(K) Reclassifications
Certain reclassifications have been made to the consolidated
financial statements for prior years to conform with the current
year presentation.
3. BUSINESS ACQUISITIONS
In December 1999, Crestone Energy Ventures purchased a 39%
common membership interest in Bighorn for approximately $31.9
million and in June 2000, Crestone Energy Ventures purchased 80% of
class A shares in Bighorn for approximately $20.8 million.
In September 2000, Crestone Energy Ventures 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, for approximately $208.7 million. The
acquisition included the purchase of a 100% interest in Enron
Midstream Services, L.L.C., now known as Crestone Gathering
Services, a 33% interest in Fort Union and a 35% interest in Lost
Creek. The purchase of Crestone Gathering Services increased
Crestone Energy Venture's ownership in Bighorn to a 49% common
membership interest and a 100% interest in the class A shares.
The Partnership has accounted for these acquisitions using the
purchase method of accounting. The purchase price has been
allocated based upon the estimated fair value of the assets and
liabilities acquired as of the acquisition date. The excess of the
purchase price over the fair value of the Crestone Gathering
Services net assets acquired is reflected as goodwill on the
consolidated balance sheet. The investments in Bighorn, Fort Union
and Lost Creek are being reflected in investments in unconsolidated
affiliates on the consolidated balance sheet. See Note 7 for
additional discussion of the Partnership's investments in
unconsolidated affiliates.
The following is a summary of the effects of the acquisitions
made in 2000 and 1999 on the Partnership's consolidated financial
position (amounts in thousands):
2000 1999
Current assets $ 1,949 $ --
Property, plant and equipment 29,789 --
Investments in unconsolidated
affiliates 179,079 31,895
Goodwill 18,887 --
Current liabilities (199) --
$229,505 $31,895
If the acquisitions made in 2000 had occurred at the beginning
of 2000, the Partnership's 2000 consolidated operating revenues
would have been $343 million, net income to partners would have
been $65 million and net income per unit would have been $2.00.
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.
Bighorn's ownership structure consists of common membership
interests, which represents approximately 93.8% of its
capitalization, and non-voting class A and class B shares, each of
which represents approximately 3.1% of the total capitalization.
Both of the non-voting classes of shares are subject to certain
distribution preferences as well as limitations based on the
cumulative number of wells connected to the Bighorn system at the
end of each calendar year. These shares will receive an income
allocation equal to the cash distributions received and are not
entitled to any other allocations of income or distributions of
cash. During 1999 and 2000, no income allocation or cash
distribution was made to the non-voting shares. Ownership of these
shares does not affect the amount of capital contributions that are
required to be made to the operations of Bighorn by the owners of
the common membership interests.
4. RATES AND REGULATORY ISSUES
Rate Case
Northern Border Pipeline's revenue is derived from agreements with
various shippers for the transportation of natural gas. It
transports gas under a 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 current 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. Under the cost
of service tariff, Northern Border Pipeline billed on an estimated
basis for a six-month cycle. Any net excess or deficiency resulting
from the comparison of the actual cost of service determined for the
period in accordance with the FERC tariff to the estimated billing
was accumulated, including carrying charges thereon, and was either
billed to or credited back to the shippers. Revenues reflected
actual cost of service. An amount equal to differences between
billing estimates and the actual cost of service, including carrying
charges, was reflected in current assets or current liabilities.
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.
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 will pay 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.
From December 1, 1999, through and including December 31, 2000, the
rates were based upon an annual revenue level of $307 million. For
periods after December 31, 2000, the rates are based upon an annual
revenue level of $305 million. 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 of its pipeline from near
Harper, Iowa to a point near Manhattan, Illinois. Northern Border
Pipeline had placed into service the facilities for The Chicago
Project in December 1998. Under the settlement, both Northern
Border Pipeline and its existing shippers will not be able to seek
rate changes until November 1, 2005, at which time Northern Border
Pipeline must file a new rate case.
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. At
December 31, 2000, Northern Border Pipeline had estimated its
remaining refund obligation through the end of 2000 to be
approximately $4.7 million, which is expected to be paid in the
first quarter of 2001. Northern Border Pipeline's operating
revenues for 2000 reflect the significant terms of the approved
settlement.
Certificate application
In October 1998, Northern Border Pipeline filed a certificate
application with the FERC to seek approval to expand and extend its
pipeline system into Indiana (Project 2000). When completed,
Project 2000 will 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, of which $10.8 million had been incurred
through December 31, 2000.
5. TRANSPORTATION AGREEMENTS
Northern Border Pipeline's operating revenues are collected pursuant
to the FERC tariff through firm transportation service agreements
(firm service agreements). The firm service agreements extend for
various terms with termination dates that range from October 2001 to
December 2013. Northern Border Pipeline also has interruptible
service agreements with numerous other shippers as a result of its
self-implementing blanket transportation authority. Under the
approved settlement of Northern Border Pipeline's rate case
discussed in Note 4, in certain situations, Northern Border Pipeline
will reduce the billings for the firm service agreements by one half
of the revenues received from the interruptible service agreements
through October 31, 2003. After October 31, 2003, all revenues from
interruptible transportation service will be retained by Northern
Border Pipeline.
Northern Border Pipeline's largest shipper, Pan-Alberta Gas (U.S.)
Inc. (PAGUS), is presently obligated for approximately 25.5% of the
contracted firm capacity through three firm service agreements which
expire in October 2003. Financial guarantees exist through October
2001 for approximately 16.3% of the contracted firm capacity of
PAGUS, including 10.5% guaranteed by Northern Natural Gas Company, a
wholly-owned subsidiary of Enron. The remaining obligation of PAGUS
is supported by various credit support arrangements, including among
others, a letter of credit, an escrow account and an upstream
capacity transfer agreement. Operating revenues from the PAGUS firm
service agreements and interruptible service agreements for the
years ended December 31, 2000, 1999 and 1998 were $65.0 million,
$76.6 million and $87.3 million, respectively.
TransCanada Energy Marketing USA, Inc. (TransCanada Energy), an
affiliate of TC PipeLines, has firm service agreements representing
approximately 11.4% of contracted capacity. The firm service
agreements for TransCanada Energy extend for various terms with
termination dates that range from October 2003 to December 2008.
Other shippers affiliated with the partners of Northern Border
Pipeline have firm service agreements representing approximately
7.1% of contracted capacity. These firm service agreements extend
for various terms with termination dates that range from January
2002 to May 2009. Operating revenues from the affiliated firm
service agreements and interruptible service agreements for the
years ended December 31, 2000, 1999, and 1998 were $58.5 million,
$52.5 million and $22.4 million, respectively.
Crestone Energy Ventures and Crestone Gathering Services
(collectively Crestone) provide gas gathering and administrative
services to third parties, ENA, and the Partnership's unconsolidated
affiliates. Crestone's total revenues from affiliates for the year
ended December 31, 2000, were $7.3 million.
Black Mesa's operating revenue is derived from a pipeline
transportation agreement (Pipeline Agreement) with the coal supplier
for the Mohave Power Station that expires in December 2005. The
pipeline is the sole source of fuel for the Mohave plant. Under the
terms of the Pipeline Agreement, Black Mesa receives a monthly
demand payment, a per ton commodity payment and a reimbursement for
certain other expenses.
6. CREDIT FACILITIES AND LONG-TERM DEBT
Detailed information on long-term debt is as follows:
December 31,
(In thousands) 2000 1999
Northern Border Pipeline
1992 Pipeline Senior Notes - average 8.49%
and 8.43% at December 31, 2000 and 1999,
respectively, due from 2000 to 2003 $ 184,000 $ 250,000
Pipeline Credit Agreement
Term loan, due 2002 424,000 439,000
Five-year revolving credit facility 45,000 --
1999 Pipeline Senior Notes - 7.75%,
due 2009 200,000 200,000
Northern Border Partners, L.P.
Partnership Senior Notes - 8 7/8%,
due 2010 250,000 --
Partnership Credit Agreements -
Three-year revolving credit facility 26,300 --
Credit agreements - average 6.78%,
due 2000 -- 114,500
Black Mesa
10.7% Note agreement,
due quarterly to 2004 13,910 17,027
Unamortized proceeds from termination
of derivatives 26,046 12,397
Unamortized debt premium (discount) 2,706 (938)
Total 1,171,962 1,031,986
Less: Current maturities of long-term debt 44,464 183,617
Long-term debt $1,127,498 $ 848,369
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 3). 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 (see Note 3). The Partnership Senior Notes were
subsequently exchanged in a registered offering for notes with
substantially identical terms.
The Partnership entered into 10-year interest rate swap agreements
with an aggregate notional principal amount of $150 million in June
2000. The interest rate swap agreements were terminated in December
2000 and resulted in proceeds to the Partnership of approximately
$15.0 million. The proceeds are being amortized against interest
expense over the 10-year life of the terminated interest rate swap
agreements.
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. 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 December 31, 2000, the
average effective interest rate on the Partnership Credit Agreements
was 8.92%
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 (1999 Pipeline Senior Notes). Also in
August 1999, Northern Border Pipeline received approximately $12.9
million from the termination of interest rate forward agreements,
which is being amortized against interest expense over the life of
the 1999 Pipeline Senior Notes. The interest rate forward
agreements, which had an aggregate notional amount of $150 million,
had been executed in September 1998 to hedge the interest rate on a
planned issuance of fixed rate debt in 1999. The proceeds from the
private offering, net of debt discounts and issuance costs, and the
termination of the interest rate forward agreements were used to
reduce existing indebtedness under a June 1997 credit agreement.
In June 1997, Northern Border Pipeline entered into a credit
agreement (Pipeline Credit Agreement) with certain financial
institutions to borrow up to an aggregate principal
amount of $750 million. The Pipeline Credit Agreement is comprised
of a $200 million five-year revolving credit facility to be used for
the retirement of a previously existing bank loan agreement and for
general business purposes, and a $550 million three-year revolving
credit facility to be used for the construction of The Chicago
Project. Effective March 1999, in accordance with the provisions of
the Pipeline Credit Agreement, Northern Border Pipeline converted
the three-year revolving credit facility to a term loan maturing in
June 2002. The Pipeline Credit Agreement permits Northern Border
Pipeline 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, subject to
certain parameters. Northern Border Pipeline is required to pay a
facility fee on the remaining aggregate principal commitment amount
of $624 million.
At December 31, 2000 and 1999, Northern Border Pipeline had an
outstanding interest rate swap agreement with a notional amount of
$40 million, which will terminate in November 2001. Under the
agreement, Northern Border Pipeline makes payments to counterparties
at fixed rates and in return receives payments at variable rates
based on the London Interbank Offered Rate. At December 31, 2000
and 1999, Northern Border Pipeline was in a payable position
relative to its counterparties. The average effective interest rate
of Northern Border Pipeline's variable rate debt, taking into
consideration the interest rate swap agreement, was 7.06% and 6.73%
at December 31, 2000 and 1999, respectively.
Interest paid, net of amounts capitalized, during the years ended
December 31, 2000, 1999 and 1998 was $84.2 million, $62.5 million
and $28.7 million, respectively.
Aggregate repayments of long-term debt required for the next five
years are as follows: $44 million, $551 million, $96 million, and
$2 million for 2001, 2002, 2003, and 2004, respectively. There are
no scheduled debt maturities for 2005.
Certain of Northern Border Pipeline's long-term debt and credit
arrangements contain requirements as to the maintenance of minimum
partners' capital and debt to capitalization ratios which restrict
the incurrence of other indebtedness by Northern Border Pipeline and
also place certain restrictions on distributions to the partners of
Northern Border Pipeline. Under the most restrictive of the
covenants, as of December 31, 2000 and 1999, respectively, $136
million and $132 million of partners' capital of Northern Border
Pipeline could be distributed. 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. The
Partnership Credit Agreements, as amended, require the maintenance
of a ratio of debt to total capital, excluding the nonrecourse debt
of subsidiaries, of no more than 45% currently and gradually
decreasing to 35% by September 30, 2001.
The following estimated fair values of financial instruments
represent the amount at which each instrument could be exchanged in
a current transaction between willing parties. Based on quoted
market prices for similar issues with similar terms and remaining
maturities, the estimated fair value of the 1992 Pipeline Senior
Notes was approximately $191 million and $273 million at December
31, 2000 and 1999, respectively. The estimated fair value of the
1999 Pipeline Senior Notes was approximately $213 million and $201
million at December 31, 2000 and 1999, respectively. The estimated
fair value of the Partnership Senior Notes was approximately $271
million at December 31, 2000. The estimated fair value of the Black
Mesa note agreement was approximately $15 million and $18 million at
December 31, 2000 and 1999, respectively. At December 31, 2000 and
1999, the estimated fair value which would be payable to terminate
the interest rate swap agreement, taking into account current
interest rates, was approximately $1 million. The Partnership
presently intends to maintain the current schedule of maturities for
the 1992 Pipeline Senior Notes, 1999 Pipeline Senior Notes,
Partnership Senior Notes, the Black Mesa note agreement and the
interest rate swap agreement that will result in no gains or losses
on their respective repayment. The fair value of the Pipeline
Credit Agreement and Partnership Credit Agreements approximates the
carrying value since the interest rates are periodically adjusted to
reflect current market conditions.
7. UNCONSOLIDATED AFFILIATES
The Partnership's investments in unconsolidated affiliates which are
accounted for by the equity method is as follows:
Net
Ownership December 31,
(In thousands) Interest 2000 1999
Bighorn (a) $ 83,562 $31,895
Fort Union 33% 69,872 --
Lost Creek 35% 68,191 --
$221,625(b) $31,895
(a) As discussed in Note 3, the Partnership's common membership
interest in Bighorn increased from 39% at December 31, 1999 to 49% at
December 31, 2000. The Partnership also held 100% of the non-voting
class A shares of Bighorn at December 31, 2000.
(b) At December 31, 2000 and 1999, the unamortized excess of the
Partnership's investments in unconsolidated affiliates was $189.5
million and $20.0 million, respectively.
The Partnership's equity earnings (losses) of unconsolidated
affiliates is as follows:
(In thousands) 2000(a)
Bighorn $(1,394)
Fort Union 285
Lost Creek 462
$ (647)
(a) Initial investments in unconsolidated affiliates began in late
December 1999.
Summarized combined financial information of the Partnership's
unconsolidated affiliates is presented below:
December 31,
(In thousands) 2000 1999(b)
Balance sheet
Current assets (a) $ 15,202 $ 1,770
Property, plant and equipment, net 160,558 32,619
Other noncurrent assets 1,329 --
Current liabilities 4,509 1,912
Long-term debt 99,364 --
Other noncurrent liabilities 4,008 --
Owners' equity 69,208 32,477
(a) Includes $434 thousand receivable from the Partnership at
December 31, 2000.
(b) Includes only balances from Bighorn.
(In thousands) 2000 (a)
Income statement
Operating revenues $8,598
Operating expenses 3,871
Net income 4,116
Distributions paid to
the Partnership $ 933
(a) Includes entire year results for Bighorn, which was acquired in
late December 1999, and results for Fort Union and Lost Creek after
they were acquired in September 2000.
8. PARTNERS' CAPITAL
At December 31, 2000, partners' capital consisted of 31,503,563
common units representing an effective 98% limited partner interest
in the Partnership (including 13.5% held collectively by the General
Partners or their affiliates) and a 2% general partner interest. At
December 31, 1999, partners' capital consisted of 29,347,313 common
units representing an effective 98% limited partner interest in the
Partnership (including 14.5% held collectively by the General
Partners or their affiliates) and a 2% general partner interest.
Effective January 19, 1999, the Partnership converted its 6,420,000
outstanding subordinated units into an equal number of common units
since the Partnership Policy Committee determined the subordination
period ended as a result of satisfying the criteria set forth in the
partnership agreement.
In November 2000, the Partnership sold, through an underwritten
public offering, 2,156,250 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 $60.7 million
and were primarily used to repay amounts borrowed under the
Partnership Credit Agreements.
In January 1998, the Partnership sold, through an underwritten
public offering, 225,000 common units. The units sold in 1998
resulted from the underwriters exercise of an over-allotment option
to purchase a limited number of additional common units after an
offering of common units in December 1997. The net proceeds, of the
public offering and the associated general partners' capital
contributions, was approximately $7.6 million.
The Partnership will make distributions to its partners with respect
to each calendar quarter in an amount equal to 100% of its Available
Cash. "Available Cash" generally consists of all of the cash
receipts of the Partnership adjusted for its cash disbursements and
net changes to cash reserves. Available Cash will generally be
distributed 98% to the Unitholders and 2% to the General Partners.
Partnership income is allocated to the General Partners and the
limited partners in accordance with their respective partnership
percentages, after giving effect to any priority income allocations
for incentive distributions that are allocated 100% to the General
Partners. As an incentive, the General Partners' percentage
interest in quarterly distributions is increased after certain
specified target levels are met (see Note 10). At the time the
quarterly distributions exceed $0.605 per unit, the General Partners
receive 15% of the excess. As the quarterly distributions are
increased above $0.715 per unit, the General Partners receive
increasing percentages in excess of the targets reaching a maximum
of 50% of the excess of the highest target level.
9. COMMITMENTS AND CONTINGENCIES
Firm Transportation Obligations and Other Commitments
Crestone Energy Ventures has firm transportation agreements with
Fort Union and Lost Creek. Under these agreements, Crestone Energy
Ventures must make specified minimum payments each month. At
December 31, 2000, the estimated aggregate amounts of such required
future payments were $8.2 million annually for 2001 through 2005 and
$35.7 million for later years.
At December 31, 2000, the Partnership is a guarantor on a
construction loan outstanding of an unconsolidated affiliate of
approximately $23.1 million. The Partnership has also guaranteed
the performance of an unconsolidated affiliate in connection with a
credit agreement that expires in September 2009. At December 31,
2000, the guarantee was $2.9 million.
Capital expenditure and investment program
Total capital expenditures for 2001 are estimated to be $176
million. This includes approximately $81 million for Northern
Border Pipeline's Project 2000 (see Note 4), $79 million for
Crestone Energy Ventures gathering facilities and approximately $16
million for renewals and replacements of the existing facilities.
Crestone Energy Ventures also estimates that it will be required to
make additional investments in its unconsolidated affiliates of
approximately $22 million in 2001 to support their capital
expenditure projects. Funds required to meet the capital
requirements for 2001 are anticipated to be provided primarily from
debt borrowings and internal sources.
Environmental Matters
The Partnership is not aware of any material contingent liabilities
with respect to compliance with applicable environmental laws and
regulations.
Other
Various legal actions that have arisen in the ordinary course of
business are pending. The Partnership believes that the resolution
of these issues will not have a material adverse impact on the
Partnership's results of operations or financial position.
10. 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 units outstanding. The General Partners'
allocation is equal to an amount based upon their combined 2%
general partner interest, adjusted to reflect an amount equal to
incentive distributions. Net income per unit was determined as
follows:
(In thousands, except Year ended December 31,
per unit amounts) 2000 1999 1998
Net income to partners $76,720 $81,003 $68,020
Net income allocated to General Partners (1,534) (1,620) (1,359)
Adjustment to reflect incentive distributions (1,032) (90) --
(2,566) (1,710) (1,359)
Net income allocable to units $74,154 $79,293 $66,661
Weighted average units outstanding 29,665 29,347 29,345
Net income per unit $ 2.50 $ 2.70 $ 2.27
11. ACCOUNTING PRONOUNCEMENTS
In 1998, the Financial Accounting Standards Board (FASB) 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 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 and its
subsidiaries will adopt SFAS No. 133 beginning January 1, 2001. The
adoption of SFAS No. 133, as amended, will not have a material
impact on the Partnership's financial position or results of
operations.
12. GEOGRAPHIC AND BUSINESS SEGMENT INFORMATION
The Partnership's business is divided into operating segments,
defined as components of the enterprise about which financial
information is available and evaluated regularly by the
Partnership's executive management and the Partnership Policy
Committee in deciding how to allocate resources to an individual
segment and in assessing performance of the segment.
The Partnership's reportable segments are strategic business units
that offer different services. They are managed separately because
each business requires different marketing strategies. The
accounting policies of the segments are the same as those described
in the summary of significant accounting policies in Note 2. 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) and operating
income. Interest expense on the Partnership's debt is not allocated
to the segments. Therefore, management believes that EBITDA is the
dominant measurement of segment performance.
Gas
Interstate Coal Gathering
(In thousands) Pipeline Slurry (a) Other(b) Total
2000
Revenues from
external customers $ 311,022 $ 21,170 $ 7,540 $ -- $ 339,732
Depreciation and
amortization 57,328 2,977 394 -- 60,699
Operating income (loss) 184,167 4,355 2,019 (2,239) 188,302
Interest expense, net 65,161 1,677 -- 14,657 81,495
Equity earnings
(losses) of
unconsolidated
affiliates -- -- (647) -- (647)
Other income, net 8,058 32 -- 589 8,679
EBITDA 249,553 7,364 4,007 (1,650) 259,274
Capital expenditures 15,523 386 3,812 -- 19,721
Identifiable assets 1,768,505 29,605 58,230 4,755 1,861,095
Investments in
unconsolidated
affiliates -- -- 221,625 -- 221,625
Total assets $1,768,505 $ 29,605 $279,855 $ 4,755 $2,082,720
1999
Revenues from
external customers $ 298,347 $ 20,616 $ -- $ -- $ 318,963
Depreciation and
amortization 51,908 2,934 -- -- 54,842
Operating income (loss) 177,411 3,670 -- (1,363) 179,718
Interest expense, net 60,214 1,997 -- 5,498 67,709
Other income, net 1,363 (39) -- 3,238 4,562
EBITDA 230,682 6,565 -- 1,875 239,122
Capital expenditures 101,678 592 -- -- 102,270
Identifiable assets 1,796,691 32,075 -- 2,776 1,831,542
Investments in
unconsolidated
affiliates -- -- 31,895 -- 31,895
Total assets $1,796,691 $ 32,075 $ 31,895 $ 2,776 $1,863,437
1998
Revenues from
external customers $ 196,600 $ 20,992 $ -- $ -- $ 217,592
Depreciation and
amortization 40,989 2,896 -- -- 43,885
Operating income (loss) 113,661 3,631 -- (1,489) 115,803
Interest expense, net 25,541 2,281 -- 3,100 30,922
Other income, net 12,111 640 -- 457 13,208
EBITDA 166,761 7,167 -- (1,032) 172,896
Capital expenditures 651,169 1,025 -- -- 652,194
Identifiable assets 1,790,889 34,421 -- 456 1,825,766
Total assets $1,790,889 $ 34,421 $ -- $ 456 $1,825,766
(a) Gas gathering operating results commence from the date of
acquisition in September 2000 (see Note 4) except for equity earnings of
Bighorn, which commenced in January 2000.
(b) Includes other items not allocable to segments.
13. QUARTERLY FINANCIAL DATA (Unaudited)
(In thousands, except Operating Operating Net Income Net Income
per unit amounts) Revenues, net Income to Partners per Unit
2000
First Quarter $81,517 $45,171 $17,966 $0.59
Second Quarter 82,536 44,747 18,042 0.60
Third Quarter 83,550 48,216 20,338 0.66
Fourth Quarter 92,129 50,168 20,374 0.65
1999
First Quarter $78,895 $44,961 $21,631 $0.72
Second Quarter 78,012 44,255 20,561 0.69
Third Quarter 79,046 44,728 19,357 0.65
Fourth Quarter 83,010 45,774 19,454 0.65
14. SUBSEQUENT EVENTS
On January 18, 2001, the Partnership declared a cash distribution of
$0.70 per unit ($2.80 per unit on an annualized basis) for the
quarter ended December 31, 2000. The distribution is payable
February 14, 2001, to unitholders of record at January 31, 2001.
Report of Independent Public Accountants on Schedule
To Northern Border Partners, L.P.:
We have audited in accordance with auditing standards generally accepted
in the United States, the consolidated financial statements of Northern
Border Partners, L.P. and Subsidiaries included in this Form 10-K and
have issued our report thereon dated January 22, 2001. Our audits were
made for the purpose of forming an opinion on the basic financial
statements taken as a whole. The schedule of Northern Border Partners,
L.P. and Subsidiaries listed in Item 14 of Part IV of this Form 10-K is
the responsibility of the Company's management and is presented for
purposes of complying with the Securities and Exchange Commission's
rules and is not part of the basic financial statements. This schedule
has been subjected to the auditing procedures applied in the audits of
the basic financial statements and, in our opinion, fairly states in all
material respects the financial data required to be set forth therein in
relation to the basic financial statements taken as a whole.
ARTHUR ANDERSEN LLP
Omaha, Nebraska,
January 22, 2001
SCHEDULE II
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
(In Thousands)
Column A Column B Column C Column D Column E
Additions Deductions
Balance at Charged to Charged For Purpose For
Beginning Costs and to Other Which Reserves Balance at
Description of Year Expenses Accounts Were Created End of Year
Reserve for
regulatory issues
2000 $7,376 $1,800 $-- $7,376 $1,800
1999 $6,726 $ 650 $-- $ -- $7,376
1998 $6,726 $ -- $-- $ -- $6,726
UNITED STATES SECURITIES AND EXCHANGE
COMMISSION
WASHINGTON, D.C. 20549
_______________________
EXHIBITS TO
F O R M 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 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 (I.R.S. Employer
of incorporation Identification No.)
or organization)
1400 Smith Street, Houston, Texas 77002-7369
(Address of principal executive offices)(zip code)
Registrant's telephone number, including area code: 713-853-6161
___________________
EXHIBIT INDEX
* 3.1 Form of Amended and Restated
Agreement of Limited Partnership of
Northern Border Partners, L.P.
(Exhibit 3.1 No. 2 to the
Partnership's Form S-1 Registration
Statement, Registration No. 33-66158
("Form S-1")).
* 3.2 Form of Amended and Restated
Agreement of Limited Partnership
For Northern Border Intermediate
Limited Partnership (Exhibit 10.1 to
Form S-1).
* 4.1 Indenture, dated as of June 2, 2000,
between the registrants and Bank One
Trust Company, N.A. (Exhibit 4.1 to
the Partnership's Quarterly Report
on Form 10-Q for the quarterly
period ended June 30, 2000 ("June
2000 10-Q")).
* 4.2 First Supplemental Indenture, dated
as of September 14, 2000, between
the registrants and Bank One Trust
Company, N.A.(Exhibit 4.2 to Form S-4
Registration Statement, Registration No.
333-46212 ("NBP Form S-4")).
4.3 Indenture, dated as of March 21,
2001, between Northern Border
Partners, L.P. and Northern Border
Intermediate Limited Partnership and
Bank One Trust Company, N.A.,
Trustee.
4.4 Registration Rights Agreement dated
March 21, 2001 by and among Northern
Border Partners, L.P., Northern
Border Intermediate Limited
Partnership, Banc of America
Securities LLC, SunTrust Equitable
Securities Corporation, Banc One
Capital Markets, Inc. and BMO
Nesbitt Burns Corp.
* 4.5 Indenture, dated as of August 17,
1999, between Northern Border
Pipeline Company and Bank One Trust
Company, NA, successor to The First
National Bank of Chicago, as
trustee. (Exhibit No. 4.1 to
Northern Border Pipeline Company's
Form S-4 Registration Statement,
Registration No. 333-88577 ("NB Form
S-4").
*10.1 Northern Border Pipeline Company
General Partnership Agreement
between Northern Plains Natural Gas
Company, Northwest Border Pipeline
Company, Pan Border Gas Company,
TransCanada Border Pipeline Ltd. and
TransCan Northern Ltd., effective
March 9, 1978, as amended (Exhibit
10.2 to Form S-1).
*10.2 Operating Agreement between Northern
Border Pipeline Company and Northern
Plains Natural Gas Company, dated
February 28, 1980 (Exhibit 10.3 to
Form S-1).
*10.3 Administrative Services Agreement
between NBP Services Corporation,
Northern Border Partners, L.P. and
Northern Border Intermediate Limited
Partnership (Exhibit 10.4 to Form S-1).
*10.4 Note Purchase Agreement between
Northern Border Pipeline Company and
the parties listed therein, dated
July 15, 1992 (Exhibit 10.6 to Form
S-1).
*10.4.1 Supplemental Agreement to the Note
Purchase Agreement dated as of June 1,
1995 (Exhibit 10.6.1 to the
Partnership's Annual Report on Form
10-K for the year ended December 31,
1995 ("1995 10-K")).
*10.5 Guaranty made by Panhandle Eastern
Pipeline Company, dated October 31,
1992 (Exhibit 10.9 to Form S-1).
*10.6 Northern Border Pipeline Company
U.S. Shippers Service Agreement
between Northern Border Pipeline
Company and Enron Gas Marketing,
Inc., dated June 22, 1990 (Exhibit
10.10 to Form S-1).
*10.6.1 Amended Exhibit A to Northern Border
Pipeline Company U.S. Shippers
Service Agreement between Northern
Border Pipeline Company and Enron
Gas Marketing, Inc. (Exhibit 10.10.1
to the Partnership's Annual Report
on Form 10-K for the year ended
December 31, 1993 ("1993 10-K")).
*10.6.2 Amended Exhibit A to Northern Border
Pipeline U.S. Shippers Service
Agreement between Northern Border
Pipeline Company and Enron Gas
Marketing, Inc., effective November 1,
1994 (Exhibit 10.10.2 to the
Partnership's Annual Report on Form
10-K for the year ended December 31,
1994).
*10.6.3 Amended Exhibit A's to Northern
Border Pipeline Company U.S. Shipper
Service Agreement effective, August 1,
1995 and November 1, 1995
(Exhibit 10.10.3 to 1995 10-K).
*10.6.4 Amended Exhibit A to Northern Border
Pipeline Company U.S. Shipper
Service Agreement effective April l,
1998 (Exhibit 10.10.4 to the
Partnership's Annual Report on Form
10-K for the year ended December 31,
1997 ("1997 10-K")).
*10.7 Guaranty made by Northern Natural
Gas Company, dated October 7, 1993
(Exhibit 10.11.1 to 1993 10-K).
*10.8 Guaranty made by Northern Natural
Gas Company, dated October 7, 1993
(Exhibit 10.11.2 to 1993 10-K).
*10.9 Northern Border Pipeline Company
U.S. Shippers Service Agreement
between Northern Border Pipeline
Company and Western Gas Marketing
Limited, as agent for TransCanada
PipeLines Limited, dated December
15, 1980 (Exhibit 10.13 to Form S-1).
*10.9.1 Amendment to Northern Border
Pipeline Company Service Agreement
extending the term effective
November 1, 1995 (Exhibit 10.13.1 to
1995 10-K).
*10.10 Form of Seventh Supplement Amending
Northern Border Pipeline Company
General Partnership Agreement
(Exhibit 10.15 to Form S-1).
*10.11 Northern Border Pipeline Company
U.S. Shippers Service Agreement
between Northern Border Pipeline
Company and Transcontinental Gas
Pipe Line Corporation, dated July
14, 1983, with Amended Exhibit A
effective February 11, 1994 (Exhibit
10.17 to 1995 10-K).
*10.12 Form of Credit Agreement among
Northern Border Pipeline Company,
The First National Bank of Chicago,
as Administrative Agent, The First
National Bank of Chicago, Royal Bank
of Canada, and Bank of America
National Trust and Savings
Association, as Syndication Agents,
First Chicago Capital Markets, Inc.,
Royal Bank of Canada, and
BancAmerica Securities, Inc, as
Joint Arrangers and Lenders (as
defined therein) dated as of
June 16, 1997 (Exhibit 10(c) to
Amendment No. 1 to Form S-3,
Registration Statement No. 333-40601
("Form S-3")).
*10.13 Northern Border Pipeline Company
U.S. Shippers Service Agreement
between Northern Border Pipeline
Company and Enron Capital & Trade
Resources Corp. dated October 15,
1997 (Exhibit 10.21 to 1997 10-K).
*10.14 Northern Border Pipeline Company
U.S. Shippers Service Agreement
between Northern Border Pipeline
Company and Enron Capital & Trade
Resources Corp. dated October 15,
1997 (Exhibit 10.22 to 1997 10-K).
*10.15 Northern Border Pipeline Company
U.S. Shippers Service Agreement
between Northern Border Pipeline
Company and Enron Capital & Trade
Resources Corp. dated August 5, 1997
with Amendment dated September 25,
1997 (Exhibit 10.25 to 1997 10-K).
*10.16 Northern Border Pipeline Company
U.S. Shippers Service Agreement
between Northern Border Pipeline
Company and Enron Capital & Trade
Resources Corp. dated August 5, 1997
(Exhibit 10.26 to 1997 10-K).
*10.17 Northern Border Pipeline Company
U.S. Shippers Service Agreement
between Northern Border Pipeline
Company and TransCanada Gas Services
Inc., as agent for TransCanada
PipeLines Limited dated August 5,
1997 (Exhibit 10.27 to 1997 10-K).
*10.18 Project Management Agreement by and
between Northern Plains Natural Gas
Company and Enron Engineering &
Construction Company, dated March 1,
1996 (Exhibit No. 10.39 to NB Form S-4).
*10.19 Eighth Supplement Amending Northern
Border Pipeline Company General
Partnership Agreement (Exhibit 10.15
to NB Form S-4).
10.20 Revolving Credit Agreement, dated as
of March 21, 2001, between Northern
Border Partners, L.P., SunTrust
Bank, Administrative Agent, Bank of
Montreal and Bank of America, N.A.,
Co-Syndication Agents and Bank One,
NA, Documentation Agent and Lenders
(as defined therein).
*10.21 Northern Border Pipeline Company
U.S. Shippers Service Agreement
between Northern Border Pipeline
Company and Pan-Alberta Gas (US)
Inc., dated October 1, 1993, with
Amended Exhibit A effective June 22,
1998 (Exhibit 10.36 to Northern
Border Pipeline Company Annual
Report on Form 10-K for the year
ended December 31, 1999 ("NB
Pipeline 1999 10-K")).
*10.22 Northern Pipeline Company U.S.
Shippers Service Agreement between
Northern Border Pipeline Company and
Pan-Alberta Gas (US) Inc.,(successor
to Natgas U.S. Inc.) dated October 6,
1989, with Amended Exhibit A
effective April 2, 1999 (Exhibit
10.37 to NB Pipeline 1999 10-K).
*10.23 Northern Border Pipeline Company
U.S. Shippers Service Agreement
between Northern Border Pipeline
Company and Pan-Alberta Gas (U.S.)
Inc., dated October l, 1992, with
Amended Exhibit A effective June 22,
1998 (Exhibit 10.38 to NB Pipeline
1999 10-K).
10.24 Purchase and Sale Agreement, dated
as of September 21, 2000 by and
between Enron North America Corp.
and NBP Energy Pipeline, L.L.C.(now
known as Crestone Energy Ventures,
L.L.C.).
10.25 Master Services Agreement, dated as
of September 21, 2000 between NBP
Energy Pipelines, L.L.C.,(now known
as Crestone Energy Ventures, L.L.C.)
and Enron North America Corp.
10.26 Acquisition Agreement, dated as of
March 14, 2001, among Northern
Border Partners, L.P., Northern
Border Intermediate Limited
Partnership, Bear Paw Investments,
LLC, Bear Paw Energy, LLC and
Sellers (defined therein).
21 The subsidiaries of Northern Border
Partners, L.P. are Northern Border
Intermediate Limited Partnership;
Northern Border Pipeline Company;
and Crestone Energy Ventures, L.L.C.
23.01 Consent of Arthur Andersen LLP.
*99.1 Northern Border Phantom Unit Plan
(Exhibit 99.1 to Amendment No. 1 to
Form S-8, Registration No. 333-
66949).
*Indicates exhibits incorporated by
reference as indicated; all other exhibits are
filed herewith.