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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, 1999
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 be 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.
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 1, 2000, was approximately $715,540,843.
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 22
Item 8. Financial Statements and Supplementary Data 23
Item 9. Changes in and Disagreements With Accountants on
Accounting and Financial Disclosure 23
Part III
Item 10. Partnership Management 24
Item 11. Executive Compensation 27
Item 12. Security Ownership of Certain Beneficial Owners
and Management 31
Item 13. Certain Relationships and Related Transactions 31
Part IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K 34
PART I
Item 1. Business
General
Northern Border Partners, L.P. through a subsidiary
limited partnership, Northern Border Intermediate Limited
Partnership, collectively referred to herein as
"Partnership", owns a 70% general partner interest in
Northern Border Pipeline Company, a Texas general
partnership ("Northern Border Pipeline"). 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. 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.
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 14.5% limited partner interest. The combined
general and limited partner interests in the Partnership of
Enron and Williams are 12.4% and 4.1%, 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").
Our 70% interest in Northern Border Pipeline represents
substantially all of our assets. Northern Border Pipeline
owns a 1,214-mile United States 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, which provides shippers with access to the
various natural gas markets served by those pipelines.
The pipeline system was initially constructed in 1982
and was expanded and/or extended in 1991, 1992 and 1998.
The most recent expansion and extension, called The Chicago
Project, was completed in late 1998, and increased the
pipeline system's ability to receive natural gas by 42% to
its current capacity of 2,373 million cubic feet per day.
In the year ended December 31, 1999, we estimate that
Northern Border Pipeline transported approximately 23% of
the total amount of natural gas imported from Canada to the
United States. Over the same period, approximately 91% 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 risk of loss from decreases in market
prices for gas transported on the pipeline system.
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 TransCanada. 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 190 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.
We also own Black Mesa Pipeline Holdings, Inc. ("Black
Mesa"). Black Mesa, through a wholly-owned subsidiary, 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
59 people are employed in the operations of Black Mesa, of
which 26 are represented by a labor union, the United Mine
Workers. The cash flow from the coal slurry pipeline
represents only about 2% of the Partnership's total cash
flow.
In addition, during 1999 through our subsidiary, NBP
Energy Pipelines, L.L.C., we purchased from CMS Field
Services, Inc. 39% of all issued and outstanding common
membership interests in Bighorn Gas Gathering, L.L.C.
("Bighorn") for $31.9 million and agreed to purchase 80% of
all issued and outstanding Preferred A Units of Bighorn in
2000 for $20.8 million. CMS Field Services, Inc. and Enron,
through one of its subsidiaries, hold the remaining
ownership interests in Bighorn. The gathering system is
managed through a management committee consisting of
representatives of the owners. CMS Field Services, Inc. is
the current project manager.
Located in northeastern Wyoming, Bighorn 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. Fort Union, in turn, offers interconnects to the
interstate gas pipeline grid serving gas markets in the
Rocky Mountains, the Midwest and California. The gathering
system consists of more than 60 miles of large diameter
gathering pipeline and went into service in late December 1999.
Approximately 40 additional miles of gathering pipeline is
currently under construction and is expected to be completed
by the end of 2000. Bighorn has long-term agreements with
CMS Oil and Gas Company and Pennaco Energy Inc. to gather
coal bed methane gas.
The Pipeline System
With the completion of The Chicago Project in December
1998, 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, 1999, of the natural gas
transported on the system, approximately 91% was produced in
Canada, approximately 5% was produced by the Dakota
Gasification plant, and approximately 4% 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 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 million
cubic feet per day 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 million
cubic feet per day 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 the Alberta
system, owned by TransCanada, and the pipeline system owned
by Transgas Limited in Saskatchewan. The Alberta system
gathers and transports approximately 19% of the total North
American natural gas production and approximately 77% 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
which provides 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;
* 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 40 shippers with
diverse operating and financial profiles. Based upon
shippers' cost of service obligations, as of December 31,
1999, 93% of the firm capacity is contracted by producers
and marketers. The remaining firm capacity is contracted to
local distribution companies (5%) and interstate pipelines
(2%). As of December 31, 1999, the termination dates of
these contracts ranged from October 31, 2001 to December 21,
2013 and the weighted average contract life, based upon
annual cost of service obligations was slightly under seven
years with at least 97% of capacity contracted through mid-
September 2003.
Based on their proportionate shares of the cost of
service, as of December 31, 1999, the five largest shippers
are: Pan-Alberta Gas (U.S.) Inc. (25.7%), TransCanada
PipeLines Limited (10.8%), PanCanadian Energy Services Inc
(7.0%), Enron North America Corp. (formerly Enron Capital &
Trade Resources Corp.) (5.7%) and PetroCanada Hydrocarbons
Inc. (4.9%). The 20 largest shippers, in total, are
responsible for an estimated 88.4% of the cost of service.
As of December 31, 1999, the largest shipper, Pan-
Alberta holds firm capacity of 690 million cubic feet per
day under three contracts with terms to October 31, 2003.
An affiliate of Enron provides guaranties for 300 million
cubic feet per day 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 million cubic feet per day, an escrow
account and an upstream capacity transfer agreement. In
January 2000, it was announced that Southern Company Energy
Marketing has agreed in principle to manage the assets of
Pan-Alberta Gas, Ltd., which would include Pan-Alberta's
contracts with Northern Border Pipeline. Subject to the
necessary approvals, this arrangement is expected to go into
effect in the second quarter of 2000.
Some of the shippers are affiliated with the general
partners of Northern Border Pipeline. TransCanada holds
contracts representing 10.8% of the cost of service. Enron
North America Corp., a subsidiary of Enron, holds contracts
representing 5.3% of the cost of service, which was 5.7% at
1999 year end. Transcontinental Gas Pipe Line Corporation,
a subsidiary of Williams, holds a contract representing 0.8%
of the cost of service. 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 and import and
export of 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 our 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
In October 1998, Northern Border Pipeline applied to
the FERC for approval of Project 2000 to expand and extend
the pipeline system into Indiana. If constructed, Project
2000 will strategically position Northern Border Pipeline
to move natural gas east of Chicago and will place it in
direct contact with major industrial natural gas consumers.
Project 2000 would afford shippers on the expanded/extended
pipeline system access to the northern Indiana industrial
zone. The proposed pipeline extension will interconnect
with Northern Indiana Public Service Company, a major
midwest local distribution company with a large industrial
load requirement, at the terminus near North Hayden, Indiana.
Permanent reassignments of contracted transportation
capacity, or "capacity releases", were negotiated between
several existing and project shippers originally included in
the October 1998 application. On March 25, 1999, Northern
Border Pipeline amended the application to the FERC to
reflect these changes. Numerous parties filed to intervene
in this proceeding. Several parties protested this application
asking that the FERC deny Northern Border Pipeline's request
for rolled-in rate treatment for the new facilities and that
Northern Border Pipeline be required to solicit indications
of interest from existing shippers for capacity releases
that would possibly eliminate the construction of certain
new facilities. "Rolled-in rate treatment," is the
combining of the cost of service of the existing system with
the cost of service related to the new facilities for
purposes of calculating a system-wide transportation charge.
On September 15, 1999, the FERC issued a policy
statement on certification and pricing of new construction
projects. The policy statement indicated a preference for
establishing the transportation charge for newly constructed
facilities on a separate, stand-alone basis, also known as
"incremental pricing." This reversed the existing
presumption in favor of rolled-in pricing when the impact of
the new capacity is not more than a 5% increase to existing
rates and results in system-wide benefits. As set forth
above, the amended application to construct facilities to
expand the system was filed based upon rolled-in rate
treatment. On December 17, 1999, Northern Border Pipeline
filed an amendment to the March 25, 1999 certificate
application to support rolled-in rate treatment in light of
FERC's new policy statement and to modify the proposed
facilities. Several parties renewed their protests of the
application. On March 16, 2000, the FERC issued an order
granting Northern Border Pipeline's application for a
certificate to construct and operate the proposed facilities
and finding that the project meets the requirements of the
new policy statement. The FERC approved Northern Border
Pipeline's request for rolled-in rate treatment based
upon the proposed project costs. Upon acceptance
of the certificate and completion of acquisition of
necessary right-of-way, permits and equipment, construction
will proceed. The revised capital expenditures for
Project 2000 are estimated to be approximately $94 million.
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 proposed Project 2000 expansion, the
pipeline system will have the ability to transport 1,484
million cubic feet per day from Ventura to Harper, Iowa, 844
million cubic feet per day from Harper to Manhattan,
Illinois, and 544 million cubic feet per day on the new
extension from Manhattan to North Hayden, Indiana.
Under precedent agreements, five project shippers
have agreed to take all of the transportation capacity,
subject to the satisfaction of specific conditions. With
the issuance of the certificate, Northern Border Pipeline
and the project shippers are negotiating to resolve those
conditions and execute transportation contracts. 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, one of
which is under construction and is described below, 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.
The Alliance Pipeline, which will transport natural gas
from the western Canadian sedimentary basin to the
midwestern United States, has received Canadian and United
States regulatory approvals and is under construction. Its
sponsors have announced their plans for the Alliance
Pipeline to be in service by late 2000. Upon its
completion, Northern Border Pipeline will compete directly
with the Alliance Pipeline.
We expect that the Alliance Pipeline would transport
for its shippers gas containing high-energy liquid
hydrocarbons. Additional facilities to extract the natural
gas liquids are being constructed near the Alliance
Pipeline's terminus in Chicago to permit Alliance to
transport natural gas with the liquids-rich element.
As a consequence of the Alliance Pipeline, there may be
a large increase in natural gas moving from the western
Canadian sedimentary basin to Chicago. There are several
additional projects proposed to transport natural gas from
the Chicago area to growing eastern markets that would
provide access to additional markets for the shippers. The
proposed projects currently being pursued by third parties
and TransCanada are targeting markets in eastern Canada and
the northeast United States. These proposed projects are in
various stages of regulatory approval. One such project,
Vector Pipeline L.P., has commenced construction.
Williams has a minority interest (14.6%) in the
Alliance Pipeline. TransCanada and other unaffiliated
companies own and operate pipeline systems which 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
destinations as the pipeline system.
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.
Cost of service tariff
The firm transportation shippers contract to pay for a
proportionate share of the pipeline system's cost of
service. During any given month, each of these shippers
pays a uniform mileage-based charge for the amount of
capacity contracted, calculated under a cost of service
tariff. The shippers are obligated to pay their
proportionate share of the cost of service regardless of the
amount of natural gas they actually transport. The cost of
service tariff is regulated by the FERC and provides an
opportunity to recover operations and maintenance costs of
the pipeline system, taxes other than income taxes,
interest, depreciation and amortization, an allowance for
income taxes and a return on equity approved by the FERC.
Northern Border Pipeline may not charge or collect more than
the cost of service under the tariff on file with the FERC.
The investment in the pipeline system is reflected in
various accounts referred to collectively as the regulated
"rate base." The cost of service includes a return, with
related income taxes, on the rate base. Over time, the rate
base declines as a result of, among other things, monthly
depreciation and amortization. The rate base currently
includes, as an additional amount, a one-time ratemaking
adjustment to reflect the receipt of a financial incentive
on the original construction of the pipeline. Since
inception, the rate base adjustment, called an incentive
rate of return, has been amortized through monthly additions
to the cost of service. The amortization continues until
November 2001 when the incentive rate of return will be
fully amortized.
Northern Border Pipeline bills the cost of service on
an estimated basis for a six month cycle. Any net excess or
deficiency between the cost of service determined for that
period according to the FERC tariff and the estimated
billing is accumulated, including carrying charges. This
amount is then either billed to or credited back to the
shippers' accounts.
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 charged to interruptible
shippers is calculated from cost of service estimates on the
basis of contracted capacity. Except for certain limited
situations, all revenue from the interruptible
transportation service is credited to the cost of service
for the benefit of the firm shippers.
In the 1995 rate case, Northern Border Pipeline reached
a settlement that was filed in a stipulation and agreement.
Although it was contested, the settlement was approved by
the FERC on August 1, 1997. In the settlement, the
depreciation rate was established at 2.5% from January 1,
1997 through the in-service date of The Chicago Project and,
at that time, it was reduced to 2.0%. Starting in the year
2000, the depreciation rate is scheduled to increase
gradually on an annual basis until it reaches 3.2% in 2002.
The settlement also determined several other cost of
service parameters. In accordance with the effective
tariff, the allowed equity rate of return is 12.0%. For at
least seven years from the date The Chicago Project was
completed, under the terms of the settlement, Northern
Border Pipeline may continue to calculate the allowance for
income taxes as a part of the cost of service in the manner
it had historically used. In addition, a settlement
adjustment mechanism of $31 million was implemented, which
effectively reduces the allowed return on rate base.
Also as agreed to in the settlement, Northern Border
Pipeline implemented a project cost containment mechanism
for The Chicago Project. 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 agreement required the budgeted
cost for The Chicago Project, which had been initially filed
with the FERC for approximately $839 million, to be adjusted
for the effects of inflation and for costs attributable to
changes in project scope, as defined in the settlement
agreement.
In the determination of The Chicago Project cost
containment mechanism, the actual cost of the project is
compared to the budgeted cost. If there is a cost overrun
of $6 million or less, the shippers will bear the actual
cost of the project through its inclusion in our rate base.
If there is a cost savings of $6 million or less, the full
budgeted cost will be included in the rate base. If there
is a cost overrun or cost savings of more than $6 million
but less than 5% of the budgeted cost, the $6 million plus
50% of the excess will be included in our rate base. All
cost overruns exceeding 5% of the budgeted cost are excluded
from the rate base.
Northern Border Pipeline has determined the budgeted cost
of The Chicago Project, as adjusted for the effects of
inflation and project scope changes, to be $897 million,
with the final construction cost estimated to be $894
million. Northern Border Pipeline's notification to the
FERC and its shippers in June 1999 in its final report
reflects the conclusion that there will be a $3 million
addition to rate base related to the project cost
containment mechanism.
The stipulation required the calculation of the project
cost containment mechanism to be reviewed by an independent
national accounting firm. The independent accountants
completed their examination of Northern Border Pipeline's
calculation of the project cost containment mechanism in
October 1999. The independent accountants concluded
Northern Border Pipeline had complied in all material
respects with the requirements of the stipulation related to
the project cost containment mechanism.
Although we believe that the computations in the final
report have been properly completed under the terms of the
stipulation, we are unable to predict at this time whether
any adjustments will be required. Later developments in the
pending rate case, discussed below, may prevent recovery of
amounts originally calculated under the project cost
containment mechanism, which may result in a non-cash charge
to write down our balance sheet transmission plant line
item, and that charge could be material to our operating
results.
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 is
approximately $30 million. A number of the shippers and
competing pipelines have 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 tariff,
the depreciation schedule and the creditworthiness standards.
Several parties, including Northern Border Pipeline, asked
for clarification or rehearing of various aspects of the June
order. On August 31, 1999, the FERC issued an order that
provided that the issue of rolled-in rate treatment of The
Chicago Project may be examined in this proceeding. Also,
since the amount of The Chicago Project costs to be included
in rate base is governed by the settlement in the previous
rate case, the FERC consolidated that proceeding with this
case and directed that the presiding Administrative Law
Judge conduct any further proceedings that may be appropriate.
Under the order issued August 31, 1999, Northern Border Pipeline
filed the June 1999 final report and the independent accountants'
report on the calculation of the project cost containment
mechanism. While Northern Border Pipeline had not proposed
in this case to change the depreciation rates approved in
the last rate case, the order also provided that it had the
burden of proving that the depreciation rates are just and
reasonable. Testimony filed by FERC staff and intervenors
has advocated positions on among other things, rate of
return on equity ranging from 9.85% to 11.5%, a depreciation
straight line rate ranging from 2.34% to 2.5%, a reduction
in rate base under the project cost containment mechanism
ranging from $31.8 million to $43.1 million, and
modification of the cost of service form of tariff to
adoption of a stated rate form of tariff with various rate
designs. A procedural schedule has been established which
calls for the hearing to commence in July 2000. At this
time, we can give no assurance as to the outcome on any of
these issues.
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. Since Northern Border Pipeline has been a
transportation only pipeline since inception, implementation
was easily met. Capacity release provisions were adopted
which allowed shippers to release all or part of their
capacity either permanently or temporarily. If a shipper
temporarily releases part or all of its firm capacity to a
third party, then that releasing shipper receives credit
against amounts due under its firm transportation contract
for revenues received by Northern Border Pipeline as a
result of the temporary release. The releasing shipper is
not relieved of its obligations under its contract.
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.
Order 636 adopted "right of first refusal" procedures,
imposed by the FERC as a condition to the pipeline's right
to abandon long-term transportation service, to govern a
shipper's continuing rights to transportation services when
its contract with the pipeline expires. The FERC's rules
require existing shippers to match any bid of up to five
years in order to renew those contracts. As discussed
below, the FERC has narrowed the scope of this right. In
the future, the right of first refusal will apply only to
maximum rate contracts for 12 or more consecutive months of
service.
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 the tariff and
internal systems so we can fully comply with the business
standards as required by these orders.
In 1998, the FERC initiated a number of proceedings to
further amend its open access regulations. In a Notice of
Proposed Rulemaking issued on July 29, 1998, the FERC
proposed changes to its regulations governing short-term
transportation services. 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.
On September 15, 1999, the FERC issued a policy
statement on certification and pricing of new construction
projects. The policy statement announces a preference for
pricing new construction incrementally. This reverses the
existing presumption in favor of rolled-in pricing when the
impact of the new capacity is not more than a 5% increase to
existing rates and results in system-wide benefits. Also,
in examining new projects, the FERC will evaluate the
efforts by the applicant to minimize adverse impact to its
existing customers, to competitor pipelines and their
captive customers, and to landowners and communities
affected by the proposed route of the pipeline. If the
public benefits outweigh any residual adverse effects, the
FERC will proceed with the environmental analysis of the
project. This policy is to be applied on a case-by-case
basis. In an order issued February 9, 2000, the FERC
addressed requests for rehearing of the policy statement and
generally affirmed the policy statement with a few changes
and clarifications.
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, Inc., 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 agreed to pay an amount of $128,000 in
penalties for all alleged violations. The EPA has
determined that a Consent Decree will be required and we are
negotiating the terms of that decree which will include
certain preventative measures, reporting requirements and
associated penalties for failure to comply.
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, 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, for a term of
15 years, renewable for an additional 15 year term at the
option of Northern Border Pipeline without additional
rental. Northern Border Pipeline continues to operate on
this portion of the pipeline located on tribal lands in
accordance with its renewal rights.
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, granted by the Bureau of Indian Affairs ("BIA") on
March 25, 1981, for and on behalf of individual Indian
owners, expired on March 31, 1996. Before the termination
date, Northern Border Pipeline undertook efforts to obtain
voluntary consents from individual Indian owners for a new
right-of-way, and Northern Border Pipeline filed
applications with the BIA for new right-of-way grants across
those tracts of allotted lands where a sufficient number of
consents from the Indian owners had been obtained. During
1999, the BIA issued formal right-of-way grants for those
tracts for which sufficient landowners consents were
obtained. Also, a condemnation action was filed in Federal
Court in the District of Montana concerning those remaining
tracts of allotted land for which a majority of consents
were not timely received. An order was entered on March 18,
1999 condemning permanent easements in favor of Northern
Border Pipeline on the tracts in question.
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 1999.
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
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
1998
First Quarter $34.3125 $32.50 $0.575
Second Quarter 35.00 31.8125 0.575
Third Quarter 34.75 31.125 0.575
Fourth Quarter 36.125 32.50 0.61
As of March 1, 2000, there were approximately 2,100
record holders of Common Units and approximately 37,900
beneficial owners of the Common Units, including Common
Units held in street name.
We currently have 29,347,313 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.
In general, 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, 2000, we declared an increase in the
distribution to $0.65 per Unit ($2.60 per Unit on an
annualized basis), payable February 14, 2000 to the general
partners and Unitholders of record at January 31, 2000.
On January 19, 1999, the 6,420,000 Subordinated Units
outstanding were converted into 6,420,000 Common Units in
accordance with their terms in a transaction that was exempt
from registration pursuant to Section 3(a)(9) of the
Securities Act of 1933.
Item 6. Selected Financial Data
(in thousands, except per Unit and operating data)
Year Ended December 31,
1999 1998 1997 1996 1995
INCOME DATA:
Operating revenues, net $ 318,963 $ 217,592 $ 198,574 $ 201,943 $ 206,497
Operations and
maintenance 53,451 44,770 37,418 28,366 26,730
Depreciation and
amortization 54,493 43,536 40,172 46,979 47,081
Taxes other than
income 30,952 22,012 22,836 24,390 23,886
Regulatory credit -- (8,878) -- -- --
Operating income 180,067 116,152 98,148 102,208 108,800
Interest expense, net 67,709 30,922 30,860 32,670 35,106
Other income 4,213 12,859 7,989 2,900 469
Minority interests
in net income 35,568 30,069 22,253 22,153 22,360
Net income to partners $ 81,003 $ 68,020 $ 53,024 $ 50,285 $ 51,803
Net income per Unit $ 2.70 $ 2.27 $ 1.97 $ 1.88 $ 1.94
Number of units used
in computation 29,347 29,345 26,392 26,200 26,200
CASH FLOW DATA:
Net cash provided by
operating activities $ 173,368 $ 103,849 $ 119,621 $ 137,534 $ 127,078
Capital expenditures 102,270 652,194 152,658 18,597 8,411
Distribution per Unit 2.44 2.30 2.20 2.20 2.20
BALANCE SHEET DATA
(AT END OF PERIOD):
Property, plant
and equipment, net $1,745,356 $1,730,476 $1,118,364 $ 937,859 $ 957,587
Total assets 1,863,437 1,825,766 1,266,917 1,016,484 1,041,339
Long-term debt,
including current
maturities 1,031,986 976,832 481,355 377,500 410,000
Minority interests in
partners' capital 250,450 253,031 174,424 158,089 166,789
Partners' capital 515,269 507,426 500,728 410,586 419,117
OPERATING DATA (unaudited):
Northern Border Pipeline:
Million cubic feet
of gas delivered 834,833 608,187 621,262 630,148 614,617
Average daily
throughput (MMcfd) 2,353 1,706 1,735 1,755 1,717
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations
Results of Operations
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 million cubic feet per day, a
42% increase, and new firm transportation agreements with 27
shippers resulted from The Chicago Project. Northern Border
Pipeline's FERC tariff provides 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 is 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 return amount Northern Border Pipeline
collects from its shippers declines as the rate base is
recovered. 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. Northern Border Pipeline is allowed to
recover from its shippers the regulatory asset that resulted from
the cost of service deferral over a ten-year period 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 (67%) 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.
Year Ended December 31, 1998 Compared With the Year Ended
December 31, 1997
Operating revenues, net increased $19.0 million (10%) for the
year ended December 31, 1998, as compared to the results for the
comparable period in 1997. Operating revenues attributable to
Northern Border Pipeline increased $10.5 million due primarily to
returns on higher levels of invested equity. Operating revenues
for Black Mesa were $21.0 million in 1998 as compared to $12.5
million in 1997, which represented seven months of revenue. On
May 31, 1997, the Partnership increased its ownership interest of
Black Mesa and began to reflect its operating results on a
consolidated basis. Prior to that time, Black Mesa was accounted
for on the equity method and included in other income.
Operations and maintenance expense increased $7.4 million
(20%) for the year ended December 31, 1998, from the comparable
period in 1997. Operations and maintenance expense for Black
Mesa was $13.8 million in 1998 as compared to $7.7 million in
1997, which represented seven months of expense.
Depreciation and amortization expense increased $3.4 million
(8%) for the year ended December 31, 1998, as compared to the
same period in 1997. Depreciation and amortization expense
attributable to Northern Border Pipeline increased $2.3 million
primarily due to facilities that were placed in service in 1998.
Depreciation and amortization expense for Black Mesa was $2.6
million in 1998 as compared to $1.5 million in 1997, which
represented seven months of expense.
For the year ended December 31, 1998, Northern Border Pipeline
recorded a regulatory credit of approximately $8.9 million.
During the construction of The Chicago Project, Northern Border
Pipeline placed certain 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 results in deferral of the cost
of service of these new facilities. Northern Border Pipeline is
allowed to recover from its shippers the regulatory asset that
resulted from the cost of service deferral over a ten-year period
commencing with the in-service date of The Chicago Project.
Interest expense, net increased slightly for the year ended
December 31, 1998, as compared to the results for the same period
in 1997, due to an increase in interest expense of $15.4 million
offset by an increase in the amount of interest expense
capitalized of $15.3 million. Interest expense attributable to
Northern Border Pipeline and the Partnership increased $14.6
million 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 remainder of the
increase in interest expense is from Black Mesa, which was $2.3
million for 1998 as compared to $1.5 million for seven months in
1997. The increase in interest expense capitalized primarily
relates to Northern Border Pipeline's expenditures for The
Chicago Project.
Other income increased $4.9 million (61%) for the year ended
December 31, 1998, as compared to the same period in 1997. The
increase was primarily due to an $8.8 million increase in the
allowance for equity funds used during construction. The
increase in the allowance for equity funds used during
construction primarily relates to Northern Border Pipeline's
expenditures for The Chicago Project.
Other income for 1997 included $4.8 million received by
Northern Border Pipeline for vacating certain microwave frequency
bands. The amount received was a one-time occurrence and
Northern Border Pipeline does not expect to receive any material
payments for vacating microwave frequency bands in the future.
Minority interests in net income increased $7.8 million (35%)
for the year ended December 31, 1998, as compared to the same
period in 1997, 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 ("Senior Notes"). The
indenture under which the 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 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,
1999, $439.0 million was outstanding under the term loan. No
funds were outstanding under the five-year revolving credit
facility.
At December 31, 1999, Northern Border Pipeline also had
outstanding $250 million of senior notes issued in a private
placement under a July 1992 note purchase agreement. The note
purchase agreement provides for four series of notes, Series A
through D, maturing between August 2000 and August 2003. The
Series A Notes with a principal amount of $66 million mature in
August 2000. Northern Border Pipeline anticipates borrowing on
the Pipeline Credit Agreement to repay the Series A Notes.
In November 1997, the Partnership entered into a credit
agreement ("Partnership Credit Agreement") with certain financial
institutions to borrow up to an aggregate principal amount of
$175 million under a revolving credit facility. The Partnership
Credit Agreement is to be used for interim funding of the
Partnership's required capital contributions to Northern Border
Pipeline for construction of The Chicago Project. The amount
available under the Partnership Credit Agreement is reduced to
the extent the Partnership issues additional limited partner
interests to fund the Partnership's capital contributions for The
Chicago Project in excess of $25 million. Public offerings of
Common Units in December 1997 and January 1998 reduced the amount
available under the Partnership Credit Agreement to $104 million.
With the conversion of Northern Border Pipeline's three-year
revolving credit facility to a term loan, the maturity date of
the Partnership Credit Agreement is November 2000. At December
31, 1999, $90 million had been borrowed on the Partnership Credit
Agreement.
In December 1999, the Partnership entered into a one-year
credit agreement ("1999 Credit Agreement") with a single
financial institution to borrow up to an aggregate principal
amount of $25 million under a revolving line of credit. The 1999
Credit Agreement is to be used for capital contributions to
Northern Border Pipeline or for acquisitions by the Partnership.
If the Partnership Credit Agreement is terminated, the 1999
Credit Agreement automatically terminates. At December 31, 1999,
$24.5 million had been borrowed on the 1999 Credit Agreement.
As indicated above, both of the Partnership's credit
facilities mature in the year 2000. The Partnership plans to
refinance these facilities with long-term credit facilities at a
level that could also be used to finance additional capital
contributions to Northern Border Pipeline and other acquisitions
by the Partnership.
In February 1999, the Partnership filed two registration
statements with the Securities and Exchange Commission ("SEC").
One registration statement was for a proposed offering of $200
million in Common Units and debt securities to be used by the
Partnership for general business purposes including repayment of
debt, future acquisitions, capital expenditures and working
capital. The other registration statement was for a proposed
offering of 3,210,000 Common Units that are presently owned by
Northwest Border, a General Partner, and PEC Midwest, L.L.C., of
which the Partnership will not receive any proceeds.
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 either through the registration statements
previously discussed or separate registrations.
Cash Flows From Operating Activities
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 provided by operating activities decreased $15.8
million to $103.8 million for the year ended December 31, 1998 as
compared to the same period in 1997 primarily related to a $36.3
million reduction for changes in components of working capital
partially offset by the effect of the refund activity in 1997
discussed below. For the year ended December 31, 1998, the
changes in components of working capital reflected a decrease in
accounts payable of $11.8 million as compared to an increase of
$14.6 million in 1997, exclusive of accruals for The Chicago
Project. In addition, the changes in components of working
capital for 1998 reflected a decrease in over recovered cost of
service of $4.6 million and an increase in under recovered cost
of service of $2.8 million. The over/under recovered cost of
service is the difference between Northern Border Pipeline's
estimated billings to its shippers, which are determined on a six-
month cycle, and the actual cost of service determined in
accordance with the FERC tariff. The difference is either billed
to or credited back to the shippers accounts. Cash flows
provided by operating activities for the year ended December 31,
1997 reflected a $52.6 million refund in October 1997 in
accordance with the stipulation approved by the FERC to settle
the November 1995 rate case. During 1997, Northern Border
Pipeline collected $40.4 million subject to refund as a result of
the rate case.
Cash Flows From Investing Activities
Capital expenditures of $102.3 million for the year ended
December 31, 1999 include $85.5 million for The Chicago Project
and $2.5 million for Project 2000. The remaining capital
expenditures for this period are primarily related to renewals
and replacements of existing facilities. For the same period in
1998, capital expenditures were $652.2 million, which included
$638.7 million for The Chicago Project and $11.7 million for
linepack gas purchased from Northern Border Pipeline's shippers.
Linepack gas is the natural gas required to fill the pipeline
system. The cost of the linepack gas is included in Northern
Border Pipeline's rate base. The remaining capital expenditures
for 1998 are primarily related to renewals and replacements of
existing facilities.
Total capital expenditures for 2000 are estimated to be $25
million, including $10 million for Project 2000. The remaining
capital expenditures planned for 2000 are primarily for renewals
and replacements of the existing facilities. Northern Border
Pipeline currently anticipates funding its 2000 capital
expenditures primarily by using internal sources.
Cash flows used for acquisition and consolidation of
businesses of $31.9 million for the year ended December 31,
1999, are related to the Partnership's acquisition of Bighorn in
December 1999. The Partnership has agreed to acquire additional
ownership in Bighorn in 2000 for $20.8 million and to make
capital contributions to Bighorn for construction of gas
gathering facilities. The Partnership's capital contributions
to Bighorn are estimated to be approximately $10 million in
2000. The Partnership anticipates financing its obligations
using the credit facilities referred to previously.
Cash Flows From Financing Activities
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 $0.575 per Unit to
$0.61 per Unit. 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. Financing activities for the year
ended December 31, 1999, included $197.4 million from the
issuance of the Senior Notes, net of associated debt discounts
and issuance costs, and $12.9 million from the termination of the
interest rate forward agreements. Advances under the Pipeline
Credit Agreement, which were primarily used to finance a portion
of the capital expenditures for The Chicago Project, were $90.0
million for the year ended December 31, 1999. Advances under the
1999 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 Partnership Credit Agreement totaled $498.0
million. During the year ended December 31, 1999, $263.0 million
and $5.0 million was repaid on the Pipeline Credit Agreement and
Partnership Credit Agreement, respectively.
Year 2000
Similar to most businesses, we rely heavily on information
systems technology to operate in an efficient and effective
manner. Much of this technology takes the form of computers and
associated hardware for data processing and analysis. In
addition, a great deal of information processing technology is
embedded in microelectronic devices. A Year 2000 problem was
anticipated which could result from the use in computer hardware
and software of two digits rather than four digits to define the
applicable year. As a result, computer programs that have date-
sensitive software may recognize a date using "00" as the year
1900 rather than the year 2000.
Before January 1, 2000, we identified, inventoried and assessed
computer software, hardware, embedded chips and third-party
interfaces. Where necessary, remediation and replacements were
identified and implemented. All of our mission-critical and non-
mission-critical systems have operated to date, with no
interruption in business operations. The Year 2000 problem has
resulted in no material costs. We will remain vigilant for Year
2000 related problems that may yet occur, due to hidden defects
in our computer hardware or software or at mission-critical
external entities. We anticipate that the Year 2000 problem will
not create material disruptions to our mission-critical
facilities or operations, and will not result in material costs.
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. See Note 10 to the 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 - Shippers" regarding
potential contract extensions;
* the discussion under "Business - FERC Regulation - Cost of
service tariff" regarding a project cost containment
mechanism related to The Chicago Project; 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;
* conditions of the capital markets and equity markets; and
* our ability to successfully implement our plan for addressing
Year 2000 issues during the periods covered by the forward
looking statements.
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, 1999,
approximately 50% of our debt portfolio, after considering the
effect of the interest rate swap agreements, is in fixed rate
debt.
If interest rates average one percentage point more than rates
in effect as of December 31, 1999, consolidated annual interest
expense would increase by approximately $5.1 million. This
amount has been determined by considering the impact of the
hypothetical interest rates on our variable rate borrowings and
interest rate swap agreements outstanding as of December 31,
1999. Approximately $4.0 million of this increase would result
from applying the hypothetical interest rates to Northern Border
Pipeline's outstanding debt portfolio. Northern Border
Pipeline's tariff provides the pipeline an opportunity to
recover, among other items, interest expense. Therefore, the
Partnership believes that under Northern Border Pipeline's
current tariff, Northern Border Pipeline would be allowed to
recover the increase in its interest expense, if it were to
occur. Thus, the estimated impact on our annual earnings and
cash flow from a hypothetical one percentage point increase in
interest rates would be a reduction of approximately $1.1 million
related to interest expense on borrowings other than by Northern
Border Pipeline.
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 two 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 and other services for the
Partnership. NBP Services uses the employees of Enron or its
affiliates who have duties and responsibilities other than those
relating to the Administrative Services Agreement. 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
December 1, 1999, Cuba Wadlington, Jr. replaced Brian E. O'Neill
as a member of the Partnership Policy Committee and the
representative on the Northern Border Management Committee
designated by Northwest Border. 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 $15,000 and
is paid $1,000 for each meeting attended.
Name Age Positions
Executive Officers:
Larry L. DeRoin 58 Chief Executive Officer
Jerry L. Peters 42 Chief Financial and Accounting
Officer
Members of Partnership Policy
Committee and Partnership's
representatives on Northern
Border Management Committee:
Larry L. DeRoin 58 Chairman
Stanley C. Horton 50 Member
Cuba Wadlington, Jr. 56 Member
Members of Audit Committee:
Daniel P. Whitty 68 Chairman
Gerald B. Smith 49 Member
Larry L. DeRoin was named Chief Executive Officer of the
Partnership and Chairman of the Partnership Policy Committee in
July 1993. Mr. DeRoin is the President of Northern Plains, an
Enron subsidiary, having held that position since January 1985,
and is a director of Northern Plains. He started his career with
another Enron Company, Northern Natural, in 1967 and has worked
in several management positions, including President of Peoples
Natural Gas Company, a former retail natural gas subsidiary of
Enron. Mr. DeRoin has been a member of the Northern Border
Management Committee since 1985 and has been Chairman since late
1988.
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 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 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.,
public companies subject to the reporting requirements of the
Securities Exchange Act of 1934.
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. 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 Equity Corp. and of EOTT
Energy Corp., both 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 Chief Executive Officer and co-founder of
Smith, Graham & Co., a fixed income investment management firm,
which was founded in 1990. He is a director of Pennzoil Quaker
Company, M.D. Anderson Cancer Center Board of Visitors, 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.
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
Other Securities
Annual Restricted Underlying
Bonus Compensation Stock Options/
Name & Position Year Salary (1) (2) Awards (3) SARs (#) (4)
Larry L. DeRoin 1999 $266,367 $225,000 $ 7,773 $ - - $10,413
Chief Executive 1998 $256,067 $250,000 $ 7,200 $125,024 19,020 $ 6,380
Officer 1997 $247,333 $200,000 $11,908 $ - 30,570 $ -
Jerry L. Peters 1999 $132,933 $100,000 $ 3,983 $ - 9,070 $ 5,260
Chief Financial and 1998 $123,225 $110,000 $ 1,214 $ 60,030 20,000 $ 1,956
Accounting Officer 1997 $118,750 $ 80,000 $ 1,200 $ - 11,430 $ -
__________
(1) Mr. Peters elected to defer all or a portion of his bonus into
the Enron Corp. Bonus Stock Option Program and/or the Northern
Plains Natural Gas Company Phantom Unit Plan for 1997, 1998 and
1999. In 1999, Mr. Peters elected to receive Northern Plains
phantom units in lieu of a portion of the cash bonus payment
for 1998 under the Northern Plains Natural Gas Company Phantom
Unit Plan. The total number of phantom units is 1,532 and the
elected holding period for this grant is January 25, 2004.
(2) Other Annual Compensation includes cash perquisite
allowances. 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 1997, 1998 and
1999 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
1997, 1998, and 1999, 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 1997, 1998 and 1999.
(3) The aggregate total of shares in unreleased Enron restricted
stock holdings and their values as of December 31, 1999, for each
of the Named Officers is: Mr. DeRoin, 4,382 shares valued at
$194,452; Mr. Peters, 2,104 shares valued at $93,365. Dividend
equivalents for all restricted stock awards accrue from date of
grant and are paid upon vesting.
(4) The amounts shown include the value of Enron Common Stock
allocated to employees' special subaccounts under Enron's
Employee Stock Ownership Plan, matching contributions to
employees' Enron Corp. Savings Plan, and imputed income on
life insurance benefits.
Stock Option Grants During 1999
The following table sets forth information with respect to grants of
stock options pursuant to Enron's stock plans to the Named Officers
reflected in the Summary Compensation Table. No stock appreciation rights
were granted during 1999.
Individual Grants Potential Realizable
% of Total Value at Assumed
Options/SARs Exercise Annual Rate of
Options/SARs Granted to or Base Stock Price Appreciation
Granted Employees in Price Expiration For Option Term (4)
Name (#) (1) Fiscal Year ($/Sh) Date 0% (3) 5% 10%
Jerry L. Peters 9,070(2) 0.03% $32.6875 01/25/06 $ - $120,696 $281,272
(1) If a "change of control" (as defined in the Enron Stock Plans) were to
occur before the options become exercisable and are exercised, the
vesting described below will be accelerated and all such outstanding
options shall be surrendered and the optionee shall receive a cash
payment by Enron in an amount equal to the value of the surrendered
options (as defined in the Enron Stock Plans).
(2) Mr. Peters elected to receive stock options in lieu of a portion of his
1998 cash bonus payment. Stock options were 100% vested on the grant
date.
(3) An appreciation in stock price, which will benefit all stockholders, is
required for optionees to receive any gain. A stock price appreciation
of zero percent would render the option without value to the optionees.
(4) The dollar amounts under these columns represent the potential
realizable value of each grant of options assuming that the market
price of 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 Common Stock.
Aggregated Stock Option/SAR Exercises During 1999 and Stock
Option/SAR Values as of December 31, 1999
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, 1999 December 31, 1999
Name Exercise (#) Realized Exercisable Unexercisable Exercisable Unexercisable
Larry L. DeRoin - $ - 124,814 17,716 $3,127,054 $344,299
Jerry L. Peters 6,010 $116,033 51,786 7,764 $1,137,908 $142,186
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. DeRoin 32.3 39.0 $266,367 $138,575
Mr. Peters 14.9 37.8 $132,933 $ 75,167
________
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, 2000
by our executive officers, members of the Partnership Policy
Committee and the Audit Committee and 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
Larry L. DeRoin 10,000 *
1111 South 103rd Street
Omaha, NE 68124-1000
Jerry L. Peters 1,300 *
1111 South 103rd Street
Omaha, NE 68124-1000
The Williams Companies, Inc.2/ 1,123,500 3.8
One Williams Center
Tulsa, OK 74101-3288
Enron Corp.2/ 3,215,453 11.0
1400 Smith Street
Houston, TX 77002
Duke Energy Corp.2/ 2,086,500 7.1
422 So. Church St.
Charlotte, NC 88242-0001
______________
* Less than 1%.
1/ All units involve sole voting and investment power.
2/ Indirect ownership through their subsidiaries.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934, as
amended, requires certain of the Partnership's executive officers
and members of the Partnership Policy Committee and any persons
who own more than 10% of the Common Units to file reports of
ownership and changes in ownership concerning the Common Units
with the SEC and to furnish the Partnership with copies of all
Section 16(a) forms they file. Based upon the Partnership's
review of the Section 16(a) filings that have been received by
the Partnership, the Partnership believes that all filings
required to be made under Section 16(a) during 1999 were timely
made, except that Cuba Wadlington, Jr. did not timely file his
Initial Statements of Beneficial Ownership of Securities on Form 3.
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 pipeline
system, certain tax, accounting and other information to the
Partnership, and (ii) NBP Services, an affiliate of Enron,
assists the Partnership in connection with the operation and
management of the Partnership pursuant to the terms of an
Administrative Services Agreement between the Partnership and NBP
Services.
In addition, Northern Border Pipeline has extensive ongoing
relationships with the general partners and certain of their
affiliates and with affiliates of TransCanada. For example,
Northern Plains, a general partner and affiliate of Enron, 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.
Enron Engineering & Construction Company ("EE&CC"), an affiliate
of Enron, provided project management for the construction of The
Chicago Project pursuant to the terms of a project management
agreement between Northern Plains and EE&CC.
In addition, as of February 1, 2000:
* Enron North America Corp., an affiliate of Enron, is one of
our transportation customers, and is obligated to pay 5.3% of
our annual cost of service;
* TransCanada Gas Services, an affiliate of TransCanada
PipeLines Limited, is one of our transportation customers and
is currently obligated to pay 10.8% of our annual cost of
service pursuant to a transportation contract wherein
TransCanada Gas Services acts as the agent of its parent,
TransCanada;
* Transco, an affiliate of Williams, is one of our
transportation customers and is currently obligated to pay
0.8% of our annual cost of service; 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 our annual cost of service.
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 TransCanada 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 TransCanada.
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")).
*10.1 Form of Amended and Restated Agreement of
Limited Partnership For Northern Border
Intermediate Limited Partnership (Exhibit
10.1 to Form S-1).
*10.2 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).
*10.3 Operating Agreement between Northern
Border Pipeline Company and Northern
Plains Natural Gas Company, dated
February 28, 1980 (Exhibit 10.3 to Form S-1).
*10.4 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).
*10.5 Note Purchase Agreement between Northern
Border Pipeline Company and the parties
listed therein, dated July 15, 1992
(Exhibit 10.6 to Form S-1).
*10.5.1 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")).
*10.6 Guaranty made by Panhandle Eastern
Pipeline Company, dated October 31, 1992
(Exhibit 10.9 to Form S-1).
*10.7 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).
*10.7.1 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")).
*10.7.2 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).
*10.7.3 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).
*10.7.4 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")).
*10.8 Guaranty made by Northern Natural Gas
Company, dated October 7, 1993 (Exhibit
10.11.1 to 1993 10-K).
*10.9 Guaranty made by Northern Natural Gas
Company, dated October 7, 1993 (Exhibit
10.11.2 to 1993 10-K).
*10.10 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).
*10.10.1 Amendment to Northern Border Pipeline
Company Service Agreement extending the
term effective November 1, 1995 (Exhibit
10.13.1 to 1995 10-K).
*10.11 Form of Seventh Supplement Amending
Northern Border Pipeline Company General
Partnership Agreement (Exhibit 10.15 to
Form S-1).
*10.12 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).
*10.13 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")).
*10.14 Form of Credit Agreement among Northern
Border Partners, L.P., Canadian Imperial
Bank of Commerce, as Agent and Lenders
(as defined therein) dated as of November 6,
1997 (Exhibit 10(d) to Amendment No. 1
to Form S-3).
*10.15 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).
*10.16 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).
*10.17 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).
*10.18 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).
*10.19 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).
*10.20 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 10.28 to 1997
10-K).
*10.21 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 ("Form S-4")).
*10.22 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 Form S-4).
*10.23 Eighth Supplement Amending Northern
Border Pipeline Company General
Partnership Agreement (Exhibit 10.15 of
Form S-4).
10.24 Credit Agreement, dated as of December 15,
1999, between Northern Border
Partners, L.P. and SunTrust Bank,
Atlanta.
21 The subsidiaries of Northern Border
Partners, L.P. are Northern Border
Intermediate Limited Partnership;
Northern Border Pipeline Company; NBP
Energy Pipelines, L.L.C.; Black Mesa
Holdings, Inc.; Black Mesa Pipeline,
Inc.; Black Mesa Pipeline Operations
L.L.C.; Black Mesa Technologies, Inc. and
Black Mesa Technologies Services L.L.C.
23.01 Consent of Arthur Andersen LLP.
27 Financial Data Schedule.
*99.1 Northern Plains Natural Gas Company
Phantom Unit Plan (Exhibit 99.1 to Form S-8,
Registration No. 333-66949).
*Indicates exhibits incorporated by reference as
indicated; all other exhibits are filed herewith.
(b)Reports
No reports on Form 8-K were filed by the Partnership
during the last quarter of 1999.
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 28th day of March, 2000.
NORTHERN BORDER PARTNERS, L.P.
(A Delaware Limited Partnership)
By: LARRY L. DEROIN
Larry L. DeRoin
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
LARRY L. DEROIN Chief Executive Officer and March 28, 2000
Larry L. DeRoin Chairman of the Partnership
Policy Committee
(Principal Executive Officer)
STANLEY C. HORTON Member of Partnership March 28, 2000
Stanley C. Horton Policy Committee
CUBA WADLINGTON, JR. Member of Partnership March 28, 2000
Cuba Wadlington, Jr. Policy Committee
JERRY L. PETERS Chief Financial and March 28, 2000
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, 1999 and 1998 F-3
Consolidated Statement of Income - Years Ended
December 31, 1999, 1998 and 1997 F-4
Consolidated Statement of Cash Flows - Years Ended
December 31, 1999, 1998 and 1997 F-5
Consolidated Statement of Changes in Partners' Capital -
Years Ended December 31, 1999, 1998 and 1997 F-6
Notes to Consolidated Financial Statements F-7 through
F-20
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, 1999 and 1998, 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, 1999. 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 generally accepted
auditing standards. 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, 1999 and 1998, and the results of their operations and their
cash flows for each of the three years in the period ended
December 31, 1999, in conformity with generally accepted
accounting principles.
ARTHUR ANDERSEN LLP
Omaha, Nebraska,
January 20, 2000
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(In Thousands)
December 31,
ASSETS 1999 1998
CURRENT ASSETS
Cash and cash equivalents $ 22,927 $ 41,042
Accounts receivable 24,946 19,077
Related party receivables 5,292 2,470
Materials and supplies, at cost 4,410 4,189
Under recovered cost of service 3,068 2,781
Total current assets 60,643 69,559
TRANSMISSION PLANT
Property, plant and equipment 2,410,133 2,345,700
Less: Accumulated provision for
depreciation and amortization 664,777 615,224
Property, plant and equipment, net 1,745,356 1,730,476
INVESTMENTS AND OTHER ASSETS
Investment in unconsolidated affiliate 31,895 --
Other 25,543 25,731
Total investments and other assets 57,438 25,731
Total assets $1,863,437 $1,825,766
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES
Current maturities of long-term debt $ 183,617 $ 2,805
Accounts payable 8,279 46,032
Accrued taxes other than income 26,608 20,140
Accrued interest 17,608 12,462
Accumulated provision for rate refunds 2,317 --
Total current liabilities 238,429 81,439
LONG-TERM DEBT, net of current maturities 848,369 974,027
MINORITY INTERESTS IN PARTNERS' CAPITAL 250,450 253,031
RESERVES AND DEFERRED CREDITS 10,920 9,843
COMMITMENTS AND CONTINGENCIES (NOTE 7)
PARTNERS' CAPITAL
General Partners 10,305 10,148
Common Units 504,964 401,388
Subordinated Units -- 95,890
Total partners' capital 515,269 507,426
Total liabilities and partners' capital $1,863,437 $1,825,766
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,
1999 1998 1997
OPERATING REVENUES
Operating revenues $321,280 $217,592 $238,543
Provision for rate refunds (2,317) -- (39,969)
Operating revenues, net 318,963 217,592 198,574
OPERATING EXPENSES
Operations and maintenance 53,451 44,770 37,418
Depreciation and amortization 54,493 43,536 40,172
Taxes other than income 30,952 22,012 22,836
Regulatory credit -- (8,878) --
Operating expenses 138,896 101,440 100,426
OPERATING INCOME 180,067 116,152 98,148
INTEREST EXPENSE
Interest expense 67,807 49,923 34,520
Interest expense capitalized (98) (19,001) (3,660)
Interest expense, net 67,709 30,922 30,860
OTHER INCOME
Allowance for equity funds used
during construction 101 10,237 1,400
Other income, net 4,112 2,622 6,589
Other income 4,213 12,859 7,989
MINORITY INTERESTS IN NET INCOME 35,568 30,069 22,253
NET INCOME TO PARTNERS $ 81,003 $ 68,020 $ 53,024
NET INCOME PER UNIT $ 2.70 $ 2.27 $ 1.97
NUMBER OF UNITS USED IN COMPUTATION 29,347 29,345 26,392
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,
1999 1998 1997
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income to partners $ 81,003 $ 68,020 $ 53,024
Adjustments to reconcile net income
to partners to net cash provided
by operating activities:
Depreciation and amortization 54,546 43,551 40,179
Minority interests in net income 35,568 30,069 22,253
Provision for rate refunds 2,317 -- 40,403
Refunds to shippers -- -- (52,630)
Allowance for equity funds used
during construction (101) (10,237) (1,400)
Regulatory credit -- (9,105) --
Changes in components of
working capital (1,482) (19,243) 17,101
Other 1,517 794 691
Total adjustments 92,365 35,829 66,597
Net cash provided by operating
activities 173,368 103,849 119,621
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for property,
plant and equipment, net (102,270) (652,194) (152,658)
Acquisition and consolidation
of businesses (31,895) -- 3,374
Other -- -- (586)
Net cash used in investing activities (134,165) (652,194) (149,870)
CASH FLOWS FROM FINANCING ACTIVITIES:
Cash distributions
General and limited partners (73,160) (68,876) (58,957)
Minority Interests (38,149) (18,362) (30,080)
Contributions received from Minority
Interests -- 66,900 24,300
Issuance of partnership interests, net -- 7,554 90,987
Issuance of long-term debt, net 313,526 498,000 209,000
Retirement of long-term debt (270,805) (2,523) (128,665)
Proceeds received upon termination of
interest rate forward agreements 12,896 -- --
Long-term debt financing costs (1,626) (63) (969)
Repayment of note payable -- -- (10,000)
Net cash provided by (used in)
financing activities (57,318) 482,630 95,616
NET CHANGE IN CASH AND CASH EQUIVALENTS (18,115) (65,715) 65,367
Cash and cash equivalents-beginning
of year 41,042 106,757 41,390
Cash and cash equivalents-end of year $ 22,927 $ 41,042 $ 106,757
Changes in components of working capital:
Accounts receivable $ (8,691) $ (1,628) $ 2,283
Materials and supplies (221) 269 460
Accounts payable (3,897) (11,830) 14,562
Accrued taxes other than income 6,468 (368) (772)
Accrued interest 5,146 1,696 203
Over/under recovered cost of service (287) (7,382) 365
Total $ (1,482) $ (19,243) $ 17,101
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, 1996 $ 8,212 $303,777 $ 98,597 $410,586
Net income to partners 1,061 39,331 12,632 53,024
Issuance of partnership interests, net 1,921 95,133 (979) 96,075
Distributions paid (1,179) (43,654) (14,124) (58,957)
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
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). Effective May 28, 1999,
TransCanada Border PipeLine Ltd. and TransCan Northern Ltd.,
both of which are wholly-owned subsidiaries of TransCanada
PipeLines Limited (TransCanada), transferred their combined 30%
ownership interest in Northern Border Pipeline to TC PipeLines
in connection with an initial public offering of limited
partner interests in TC PipeLines, LP. Black Mesa Holdings,
Inc. and Black Mesa Pipeline Operations, L.L.C. (collectively
Black Mesa), Black Mesa Technologies, Inc. (BMT) and NBP Energy
Pipelines, L.L.C. (NBP Energy) 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 14.5% limited partner interest in the Partnership at
December 31, 1999 (see Note 6).
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 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, 1999, 1998 and 1997, Northern Border
Pipeline reimbursed the Operator approximately $29.7 million,
$30.0 million and $24.6 million, respectively. Additionally,
an Enron affiliate was responsible for project management on
Northern Border Pipeline's expansion and extension of its
pipeline from near Harper, Iowa to a point near Manhattan,
Illinois (The Chicago Project).
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.
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.
NBP Energy owns a 39% common membership interest in Bighorn
Gas Gathering, L.L.C. (Bighorn). Bighorn owns a gas
gathering system in a portion of the Powder River Basin
located in Campbell and Sheridan Counties, Wyoming (see Note 3).
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, formerly held
by the TransCanada subsidiaries, is accounted for as a
minority interest. All significant intercompany items have
been eliminated in consolidation.
The preparation of financial statements in conformity
with generally accepted accounting principles 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, 1999 and 1998,
Northern Border Pipeline has reflected regulatory assets of
approximately $12.1 million and $12.8 million, respectively,
in Other Assets on the consolidated balance sheet. During
the construction of The Chicago Project, Northern Border
Pipeline placed certain 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. As required by the certificate
of public convenience and necessity issued by the FERC, Northern
Border Pipeline recorded a regulatory credit of approximately
$8.9 million in 1998, which deferred the cost of service of
these new facilities. Northern Border Pipeline is allowed to
recover the regulatory asset that resulted from the cost of
service deferral from its shippers over a ten-year period
commencing with the in-service date of The Chicago Project.
At December 31, 1999 and 1998, the unrecovered regulatory
asset related to The Chicago Project facilities was
approximately $8.2 million and $8.9 million, respectively.
The remaining regulatory asset at both December 31, 1999
and 1998, of approximately $3.9 million, relates to costs
recorded from previous expansions and extensions of the
pipeline system. Northern Border Pipeline is seeking recovery
of these amounts in its current rate proceeding (see Note 7).
(C) Revenue Recognition
Northern Border Pipeline bills the cost of service 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 that period in accordance with
the FERC tariff to the estimated billing is accumulated,
including carrying charges thereon, and is either billed to
or credited back to the shippers. Revenues reflect actual
cost of service. An amount equal to differences between
billing estimates and the actual cost of service, including
carrying charges, is reflected in current assets or current
liabilities.
(D) 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 cost of service
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 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 $316 million and $300 million at December 31,
1999 and 1998, respectively, and are primarily related to
accelerated depreciation and other plant-related
differences.
(E) 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.
(F) Property, Plant and Equipment and Related Depreciation
and Amortization
Property, plant and equipment is stated at original cost.
In December 1998, Northern Border Pipeline placed into
service the facilities for The Chicago Project. At
December 31, 1999 and 1998, respectively, approximately
$3.5 million and $37.4 million of project costs incurred
but not paid for The Chicago Project were recorded in
accounts payable and property, plant and equipment on the
consolidated balance sheet and were excluded from the
change in accounts payable and capital expenditures for
property, plant and equipment, net on the consolidated
statement of cash flows.
Maintenance and repairs are charged to operations in the
period incurred. The provision for depreciation and
amortization of Northern Border Pipeline's transmission
line is an integral part of its FERC tariff. The effective
depreciation rate applied to Northern Border Pipeline's
transmission plant in 1999, 1998, and 1997 was 2.0%, 2.5%,
and 2.5%, respectively. In 2000, the depreciation rate
increases to 2.3% and is scheduled to continue to increase
gradually on an annual basis until it reaches 3.2% in 2002.
Composite rates are applied to all other functional groups
of property having similar economic characteristics. The
depreciation rate for transmission plant is being reviewed
in Northern Border Pipeline's current rate proceeding (see
Note 7).
The original cost of 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.
(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. The rate
employed for the equity component of AFUDC is the equity
rate of return stated in Northern Border Pipeline's FERC
tariff.
(H) 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.
(I) Investment in Unconsolidated Affiliate
Investment in unconsolidated affiliate is accounted for
by the equity method.
3. ACQUISITIONS
On May 31, 1997, the Partnership exchanged 125,357 Common Units
for all of the outstanding common stock of BMT (formerly
Williams Technologies, Inc.). Effective with the acquisition
of BMT, which was recorded using the purchase method of
accounting, the Partnership increased its ownership position in
Black Mesa from the 60.5% acquired in 1996 to 71.75% and began
to reflect Black Mesa, including Black Mesa's minority
ownership interests, in the Partnership's consolidated
financial statements. Prior to this time, the Partnership's
investment in Black Mesa was accounted for using the equity
method. On December 29, 1997, the Partnership acquired the
remaining minority ownership interest in Black Mesa through the
exchange of 46,956 Common Units and cash. The following is a
summary of the effects of the acquisition of BMT and
consolidation of Black Mesa on the Partnership's consolidated
financial position in 1997 (amounts in thousands):
Cash $ 3,374
Net property, plant and equipment 18,350
Other current and noncurrent assets 10,159
Long-term debt, including
current maturities (23,520)
Other liabilities (3,090)
Minority interests (185)
Common Units $ 5,088
On December 21, 1999, NBP Energy acquired a 39% common
membership interest in Bighorn Gas Gathering, L.L.C. (Bighorn)
for approximately $31.9 million. The remaining common
membership interests in Bighorn are owned by CMS Field
Services, Inc. (CFS) (50%) and Continental Holdings Company
(1%), both of which are wholly-owned subsidiaries of CMS Energy
Corporation, and Enron Midstream Services, L.L.C. (10%), a
wholly-owned subsidiary of Enron.
In addition to the common membership interest, which represents
approximately 93.8% of the capitalization, Bighorn has two non-
voting classes of shares, each of which represents
approximately 3.1% of the total capitalization, that are
currently owned by CFS. NBP Energy has contracted to purchase
80% of one of those classes of shares ("A shares") for $20.8
million. The payment is due on or before June 15, 2000. To
secure its obligation to acquire the A shares, NBP Energy has
pledged all of its common membership interest to CFS. 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. 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 common membership
interests.
4. SHIPPER SERVICE AGREEMENTS
Operating revenues are collected pursuant to the FERC tariff
which directs that Northern Border Pipeline collect its cost of
service through firm transportation service agreements (firm
service agreements). Northern Border Pipeline's FERC tariff
provides an opportunity to recover all operations and
maintenance costs of the pipeline, taxes other than income
taxes, interest, depreciation and amortization, an allowance
for income taxes and a regulated equity return. Billings for
the firm service agreements are based on contracted volumes to
determine the allocable share of the cost of service and are
not dependent upon the percentage of available capacity
actually used.
Northern Border Pipeline's 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 contracts with numerous other shippers as
a result of its self-implementing blanket transportation
authority. Revenues received from the interruptible service
contracts are credited to the cost of service reducing the
billings for the firm service agreements.
Northern Border Pipeline's largest shipper, Pan-Alberta Gas
(U.S.) Inc. (PAGUS), is presently obligated for approximately
25.7% of the cost of service through three firm service
agreements which expire in October 2003. Financial guarantees
exist through October 2001 for approximately 16.3% of the total
cost of service related to the contracted capacity of PAGUS,
including 10.5% guaranteed by Northern Natural Gas Company, a
wholly-owned subsidiary of Enron. The remaining cost of
service 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 contracts for the years
ended December 31, 1999, 1998 and 1997 were $76.6 million,
$87.3 million and $86.8 million, respectively.
Shippers affiliated with the partners of Northern Border
Pipeline have firm service agreements representing
approximately 17.3% of the cost of service. These firm service
agreements extend for various terms with termination dates that
range from October 2003 to May 2009. Operating revenues from
the affiliated firm service agreements and interruptible
service contracts for the years ended December 31, 1999, 1998
and 1997 were $52.5 million, $22.4 million and $20.2 million,
respectively.
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.
5. CREDIT FACILITIES AND LONG-TERM DEBT
Detailed information on long-term debt is as follows:
December 31,
(In thousands) 1999 1998
Northern Border Pipeline
Senior notes - average 8.43%,
due from 2000 to 2003 $ 250,000 $250,000
Pipeline credit agreement
Term loan, due 2002 439,000 484,500
Five-year revolving credit facility -- 127,500
Senior notes - 7.75%, due 2009 200,000 --
Unamortized proceeds from termination
of interest rate forward agreements 12,397 --
Unamortized debt discount (938) --
Northern Border Partners, L.P.
Credit agreements - due 2000 114,500 95,000
Black Mesa
10.7% Note agreement,
due quarterly to 2004 17,027 19,832
Total 1,031,986 976,832
Less: Current maturities of long-term debt 183,617 2,805
Long-term debt $ 848,369 $974,027
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 (Senior Notes). Also
in August 1999, Northern Border Pipeline received approximately
$12.9 million from the termination of interest rate forward
agreements, which is included in long-term debt on the
consolidated balance sheet and is being amortized against
interest expense over the life of the 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 $639 million.
At December 31, 1999 and 1998, Northern Border Pipeline had
outstanding interest rate swap agreements with notional amounts
of $40 million and $90 million, respectively. The agreement
outstanding at December 31, 1999, will terminate in November
2001. Under the agreements, 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, 1999 and 1998,
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 agreements, was 6.73% and
6.17% at December 31, 1999 and 1998, respectively.
In November 1997, the Partnership entered into a credit
agreement (Partnership Credit Agreement) with certain financial
institutions to borrow up to an aggregate principal amount of
$175 million under a revolving credit facility. The
Partnership Credit Agreement is to be used for interim funding
of the Partnership's required capital contributions to Northern
Border Pipeline for construction of The Chicago Project. The
amount available under the Partnership Credit Agreement is
reduced to the extent the Partnership issues additional limited
partner interests to fund the Partnership's required capital
contributions for The Chicago Project in excess of $25 million.
The public offering of Common Units discussed in Note 6 reduced
the amount available under the Partnership Credit Agreement to
$104 million. With the conversion of Northern Border
Pipeline's three-year revolving credit facility to a term loan,
the maturity date of the Partnership Credit Agreement is
November 2000.
In December 1999, the Partnership entered into a one-year
credit agreement (1999 Credit Agreement) with a single
financial institution to borrow up to an aggregate principal
amount of $25 million under a revolving line of credit. The
1999 Credit Agreement is to be used for capital contributions
to Northern Border Pipeline or for acquisitions by the
Partnership. If the Partnership Credit Agreement is
terminated, the 1999 Credit Agreement automatically terminates.
Both the Partnership Credit Agreement and the 1999 Credit
Agreement 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, subject to certain parameters. The
Partnership is required to pay a commitment fee on the
aggregate undrawn principal amount under the facilities. At
December 31, 1999 and 1998, the average interest rate on the
credit agreements was 6.78% and 6.04%, respectively.
Interest paid, net of amounts capitalized, during the years
ended December 31, 1999, 1998 and 1997 was $62.5 million, $28.7
million and $31.6 million, respectively.
Aggregate repayments of long-term debt required for the next
five years are as follows: $184 million, $44 million, $521
million, $69 million and $2 million for 2000, 2001, 2002, 2003
and 2004, respectively.
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,
1999 and 1998, respectively, $132 million and $173 million of
partners' capital of Northern Border Pipeline could be
distributed. The Partnership Credit Agreement restricts
incurrence of senior indebtedness by the Partnership and
requires the maintenance of a ratio of debt to total capital,
excluding the debt of consolidated subsidiaries, of no more
than 35 percent.
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
senior notes due from 2000 to 2003 was approximately $273
million and $287 million at December 31, 1999 and 1998,
respectively. The estimated fair value of the senior notes due
2009 was approximately $201 million at December 31, 1999. The
estimated fair value of the Black Mesa note agreement was
approximately $18 million and $23 million at December 31, 1999
and 1998, respectively. At December 31, 1999 and 1998, the
estimated fair value which would be payable to terminate the
interest rate swap agreements, taking into account current
interest rates, was approximately $1 million and $3 million,
respectively. The Partnership presently intends to maintain
the current schedule of maturities for the senior notes, the
Black Mesa note agreement and the interest rate swap agreements
that will result in no gains or losses on their respective
repayment. The carrying value of the Pipeline Credit
Agreement, Partnership Credit Agreement and 1999 Credit
Agreement approximates the fair value since the interest rates
are periodically adjusted to current market conditions.
6. PARTNERS' CAPITAL
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. At December 31, 1998, partners' capital
consisted of 22,927,313 Common Units representing an effective
76.6% limited partner interest in the Partnership; 6,420,000
Subordinated Units representing an effective 21.4% 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
6,420,000 outstanding Subordinated Units were converted 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 January 1998 and December 1997, the Partnership sold,
through an underwritten public offering, 225,000 Common Units
and 2,750,000 Common Units, respectively. The units sold in
1998 resulted from the underwriters exercise of an over-
allotment option to purchase a limited number of additional
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 contributions, of approximately $7.6
million and $90.9 million in 1998 and 1997, respectively, were
used by the Partnership to fund a portion of the capital
contributions to Northern Border Pipeline for construction of
The Chicago Project.
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. The holders of Units are entitled to
receive the minimum quarterly distribution of $0.55 per Unit
per quarter if and to the extent there is sufficient Available
Cash.
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 9). 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.
7. COMMITMENTS AND CONTINGENCIES
Regulatory Proceedings
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 is approximately $30 million. A number of Northern
Border Pipeline's shippers and competing pipelines have filed
interventions and protests. In June 1999, the FERC issued an
order in which the proposed changes were suspended until
December 1, 1999, after which the proposed changes were
implemented with subsequent billings subject to refund. At
December 31, 1999, Northern Border Pipeline recorded a $2.3
million provision for rate refunds. The June order and a
subsequent clarification issued by the FERC in August 1999 set
for hearing not only Northern Border Pipeline's proposed
changes but also several issues raised by intervenors including
the appropriateness of Northern Border Pipeline's cost of
service tariff, rolled-in rate treatment of The Chicago
Project, capital project cost containment mechanism amount
recorded for The Chicago Project, depreciation schedule and
creditworthiness standards. A procedural schedule has been
established which provides for the hearing to commence in July
2000. At this time, the Partnership can give no assurance as
to the outcome on any of these issues.
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). If approved
and constructed, Project 2000 would afford shippers on the
expanded and extended pipeline system access to industrial gas
consumers in northern Indiana. As a result of permanent
releases of capacity between several existing and project
shippers originally included in the October 1998 application,
Northern Border Pipeline amended its application with the FERC
in March 1999. Numerous parties filed to intervene in
this proceeding. Several parties protested this
application asking that the FERC deny Northern Border
Pipeline's request for rolled-in rate treatment for the new
facilities and that Northern Border Pipeline be required to
solicit indications of interest from existing shippers for
capacity releases that would possibly eliminate the
construction of certain new facilities. In September 1999, the
FERC issued a policy statement on certification and pricing of
new construction projects. The policy statement announces a
preference for establishing the transportation charge for newly
constructed facilities on a separate, stand-alone basis. This
reverses the existing presumption in favor of rolled-in pricing
once certain conditions were met. In response to the policy
statement, Northern Border Pipeline amended its application
with the FERC in December 1999. The December amended
application reflects estimated capital expenditures of
approximately $94 million. Several parties renewed their
protests on this latest amended application. While Northern
Border Pipeline cannot predict when the FERC will issue its
final order on the Project 2000 amended application, Northern
Border Pipeline has requested such action by March 15, 2000.
In January 1998, Northern Border Pipeline filed an application
with the FERC to acquire the linepack gas required to operate
the pipeline from the shippers and to provide the linepack gas
in the future for its operations. The cost of the linepack gas
acquired in 1998, which is included in rate base, totaled
approximately $11.7 million.
In August 1997, Northern Border Pipeline received FERC approval
of a Stipulation and Agreement (Stipulation) filed on October
15, 1996 to settle its November 1995 rate case. In accordance
with the terms of the Stipulation, Northern Border Pipeline's
allowed equity rate of return was reduced from the requested
14.25% to 12.75% for the period June 1, 1996 to September 30,
1996 and to 12% thereafter. Additionally, Northern Border
Pipeline agreed to reduce its transmission plant depreciation
rate retroactively to June 1, 1996, and agreed to implement a
$31 million settlement adjustment mechanism (SAM) when The
Chicago Project was placed in service. The SAM effectively
reduces the allowed return on rate base. In October 1997,
Northern Border Pipeline used a combination of cash on hand and
borrowings on a revolving credit facility to pay refunds to its
shippers of approximately $52.6 million.
Also as agreed to in the Stipulation, Northern Border Pipeline
implemented a capital project cost containment mechanism
(PCCM). The purpose of the PCCM was to limit Northern Border
Pipeline's ability to include cost overruns on The Chicago
Project in rate base and to provide incentives to Northern
Border Pipeline for cost underruns. The PCCM amount is
determined by comparing the final cost of The Chicago Project
to the budgeted cost. The Stipulation required the budgeted
cost for The Chicago Project, which had been initially filed
with the FERC for approximately $839 million, to be adjusted
for the effects of inflation and project scope changes, as
defined in the Stipulation. Such adjusted budgeted cost of The
Chicago Project has been estimated to be $897 million, with the
final construction cost estimated to be $894 million. Thus,
Northern Border Pipeline's notification to the FERC and its
shippers in June 1999 reflects the conclusion that there is a
$3 million addition to rate base as a result of the PCCM. The
Stipulation required that the calculation of the PCCM be
reviewed by an independent national accounting firm. The
independent accountants completed their examination of Northern
Border Pipeline's PCCM calculation in October 1999. The
independent accountants concluded Northern Border Pipeline had
complied, in all material respects, with the requirements of
the Stipulation related to the PCCM. Northern Border Pipeline
filed its June 1999 report and the independent accountants'
report in its current rate case proceeding discussed
previously. Testimony filed by the FERC staff and intervenors
in the current rate case proceeding has proposed changes to the
PCCM computation, which would result in rate base reductions
ranging from $32 million to $43 million. Although the
Partnership believes the computation has been made in
accordance with the terms of the Stipulation, it is unable to
predict at this time whether any adjustments will be required.
Should developments in the rate case result in rate base
reductions, a non-cash charge to write down transmission plant
would result and such charge could be material to the operating
results of the Partnership.
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.
8. CAPITAL EXPENDITURE AND INVESTMENT PROGRAM
Total capital expenditures for 2000 are estimated to be $25
million. This includes approximately $10 million for Project
2000 (see Note 7) and approximately $15 million for renewals
and replacements of the existing facilities. Funds required to
meet the capital expenditures for 2000 are anticipated to be
provided primarily from internal sources.
In addition to the commitment to acquire additional ownership
in Bighorn for $20.8 million (see Note 3), the Partnership is
required to fund 39% of Bighorn's operations. For 2000, the
capital contribution to Bighorn is estimated to be
approximately $10 million. Funds required to be invested in
Bighorn are anticipated to be provided primarily from debt
borrowings.
9. 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) 1999 1998 1997
Net income to partners $81,003 $68,020 $53,024
Net income allocated to General
Partners (1,620) (1,359) (1,061)
Adjustment to reflect incentive
distributions (90) -- --
(1,710) (1,359) (1,061)
Net income allocable to Units $79,293 $66,661 $51,963
Weighted average units outstanding 29,347 29,345 26,392
Net income per unit $ 2.70 $ 2.27 $ 1.97
10. 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 must formally document, designate and
assess the effectiveness of transactions that receive hedge
accounting.
In June 1999, the FASB issued SFAS No. 137 which deferred the
effective date of SFAS No. 133 to fiscal years beginning after
June 15, 2000. A company may implement SFAS No. 133 as of the
beginning of any fiscal quarter after issuance, however, the
statement cannot be applied retroactively. The Partnership and
its subsidiaries do not plan to adopt SFAS No. 133 early. The
Partnership believes that SFAS No. 133 will not have a material
impact on its financial position or results of operations.
11. QUARTERLY FINANCIAL DATA (Unaudited)
(In thousands, except Operating Operating NetIncome Net Income
per unit amounts) Revenues, net Income to Partners per Unit
1999
First Quarter $78,895 $45,048 $21,631 $0.72
Second Quarter 78,012 44,342 20,561 0.69
Third Quarter 79,046 44,815 19,357 0.65
Fourth Quarter 83,010 45,862 19,454 0.65
1998
First Quarter $52,820 $25,650 $14,933 $0.50
Second Quarter 53,782 27,717 16,410 0.55
Third Quarter 54,442 29,722 18,042 0.60
Fourth Quarter 56,548 33,063 18,635 0.62
12. SUBSEQUENT EVENTS
On January 18, 2000, the Partnership declared an increase in
the quarterly cash distribution from $0.61 per Unit to $0.65
per Unit for the period October 1, 1999 through December 31,
1999. The distribution is payable February 14, 2000, to the
General Partners and to the Unitholders of record at
January 31, 2000.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS ON SCHEDULE
To Northern Border Partners, L.P.:
We have audited in accordance with generally accepted auditing
standards, 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 20, 2000. 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 20, 2000
SCHEDULE II
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
(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
1999 $6,726 $650 $-- $-- $7,376
1998 $6,726 $ -- $-- $-- $6,726
1997 $5,953 $773 $-- $-- $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, 1999
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 Identification No.)
of incorporation 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")).
*10.1 Form of Amended and Restated Agreement of
Limited Partnership For Northern Border
Intermediate Limited Partnership (Exhibit
10.1 to Form S-1).
*10.2 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).
*10.3 Operating Agreement between Northern
Border Pipeline Company and Northern
Plains Natural Gas Company, dated
February 28, 1980 (Exhibit 10.3 to Form S-1).
*10.4 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).
*10.5 Note Purchase Agreement between Northern
Border Pipeline Company and the parties
listed therein, dated July 15, 1992
(Exhibit 10.6 to Form S-1).
*10.5.1 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")).
*10.6 Guaranty made by Panhandle Eastern
Pipeline Company, dated October 31, 1992
(Exhibit 10.9 to Form S-1).
*10.7 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).
*10.7.1 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")).
*10.7.2 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).
*10.7.3 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).
*10.7.4 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")).
*10.8 Guaranty made by Northern Natural Gas
Company, dated October 7, 1993 (Exhibit
10.11.1 to 1993 10-K).
*10.9 Guaranty made by Northern Natural Gas
Company, dated October 7, 1993 (Exhibit
10.11.2 to 1993 10-K).
*10.10 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).
*10.10.1 Amendment to Northern Border Pipeline
Company Service Agreement extending the
term effective November 1, 1995 (Exhibit
10.13.1 to 1995 10-K).
*10.11 Form of Seventh Supplement Amending
Northern Border Pipeline Company General
Partnership Agreement (Exhibit 10.15 to
Form S-1).
*10.12 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).
*10.13 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")).
*10.14 Form of Credit Agreement among Northern
Border Partners, L.P., Canadian Imperial
Bank of Commerce, as Agent and Lenders
(as defined therein) dated as of November 6,
1997 (Exhibit 10(d) to Amendment No. 1
to Form S-3).
*10.15 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).
*10.16 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).
*10.17 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).
*10.18 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).
*10.19 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).
*10.20 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 10.28 to 1997
10-K).
*10.21 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 ("Form S-4")).
*10.22 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 Form S-4).
*10.23 Eighth Supplement Amending Northern
Border Pipeline Company General
Partnership Agreement (Exhibit 10.15 of
Form S-4).
10.24 Credit Agreement, dated as of December
15, 1999, between Northern Border
Partners, L.P. and SunTrust Bank,
Atlanta.
21 The subsidiaries of Northern Border
Partners, L.P. are Northern Border
Intermediate Limited Partnership;
Northern Border Pipeline Company; NBP
Energy Pipelines, L.L.C.; Black Mesa
Holdings, Inc.; Black Mesa Pipeline,
Inc.; Black Mesa Pipeline Operations
L.L.C.; Black Mesa Technologies, Inc. and
Black Mesa Technologies Services L.L.C.
23.01 Consent of Arthur Andersen LLP.
27 Financial Data Schedule.
*99.1 Northern Plains Natural Gas Company
Phantom Unit Plan (Exhibit 99.1 to Form S-
8, Registration No. 333-66949).
*Indicates exhibits incorporated by reference as
indicated; all other exhibits are filed herewith.