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: 333-88577
NORTHERN BORDER PIPELINE COMPANY
(Exact name of registrant as specified in its charter)
TEXAS 74-2684967
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)
1111 SOUTH 103rd STREET, OMAHA, NEBRASKA 68124-1000
(Address of principal executive offices) (zip code)
Registrant's telephone number, including area code: 402-398-7700
___________________
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
None
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 No X
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. X
Aggregate market value of the voting and non-voting common
equity held by non-affiliates of the registrant on March 1, 2000,
was $0.
<PAGE>
NORTHERN BORDER PIPELINE COMPANY
TABLE OF CONTENTS
Page No.
Part I
Item 1. Business 1
Item 2. Properties 12
Item 3. Legal Proceedings 13
Item 4. Submission of Matters to a Vote of Security
Holders 13
Part II
Item 5. Market for Registrant's Common Equity and
Related Stockholder Matters 14
Item 6. Selected Financial Data 15
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations 16
Item 7a. Quantitative and Qualitative Disclosures About
Market Risk 21
Item 8. Financial Statements and Supplementary Data 21
Item 9. Changes in and Disagreements With Accountants
on Accounting and Financial Disclosure 21
Part III
Item 10. Partnership Management 22
Item 11. Executive Compensation 24
Item 12. Security Ownership of Certain Beneficial Owners
and Management 29
Item 13. Certain Relationships and Related Transactions 29
Part IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K. 32
<PAGE>
PART I
Item 1. Business
General
Northern Border Pipeline Company is a general partnership
formed in 1978. The general partners are Northern Border
Partners, L.P. and TC PipeLines, LP, both of which are
publicly traded partnerships. Each of Northern Border
Partners and TC PipeLines holds its interest in us, 70% and
30% of voting power, respectively, through a subsidiary
limited partnership. The general partners of Northern
Border Partners and its subsidiary 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 general partner of TC PipeLines and its
subsidiary limited partnership is TC PipeLines GP, Inc., a
subsidiary of TransCanada PipeLines Limited.
We own 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. Our pipeline system connects with multiple
pipelines, which provides shippers with access to the
various natural gas markets served by those pipelines.
Our 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 our
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 we
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 we
transported was produced in the western Canadian sedimentary
basin located in the provinces of Alberta, British Columbia
and Saskatchewan.
We transport natural gas for shippers under a tariff
regulated by the Federal Energy Regulatory Commission. We
generate revenues from individual transportation contracts
with our shippers that provide for the receipt and delivery
of natural gas at points along our pipeline system. The
tariff allows us an opportunity to recover from our shippers
our cost of service, including operations and maintenance
costs, taxes other than income taxes, interest, depreciation
and amortization, an allowance for income taxes and a
regulated return on equity. Shippers contract to pay for a
proportionate share of those costs through a mileage-based
charge for the amount of capacity contracted. The shippers
are obligated to pay the charge regardless of the amount of
natural gas they transport. We do not own the natural gas
that we transport and therefore we do not assume any natural
gas commodity price risk.
Our management is overseen by a four-member management
committee. Three representatives are designated by Northern
Border Partners, with each of its general partners selecting
one representative; one representative is designated by TC
PipeLines. Under our partnership agreement, each of
Northern Plains, Pan Border and Northwest Border has the
right to select one of Northern Border Partners'
representatives on the management committee. 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
Northern Border Partners' 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. Northern
Plains and Pan Border are subsidiaries of Enron Corp.
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."
Our pipeline system is operated by Northern Plains
pursuant to an operating agreement. As of December 31,
1999, Northern Plains employed approximately 190 individuals
located at its headquarters in Omaha, Nebraska and at
locations along the pipeline route. Northern Plains'
employees are not represented by any labor union and are not
covered by any collective bargaining agreements.
The Pipeline System
With the completion of The Chicago Project in December
1998, we own 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 our pipeline was initially
completed in 1982. Our pipeline was expanded and/or
extended in 1991, 1992 and 1998.
Our 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.
Our 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 our 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.
Our 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, our 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. Our 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 our pipeline system.
Interconnects
Our pipeline system connects with multiple pipelines which
provides our shippers with access to the various natural gas
markets served by those pipelines. Our 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 our pipeline system.
The Ventura, Iowa interconnect with Northern Natural Gas
Company functions as a large market center, where natural
gas transported on our 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
Our 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 our cost of service.
As of December 31, 1999, our 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 us. Subject to the necessary approvals, this
arrangement is expected to go into effect in the second quarter
of 2000.
Some of our shippers are affiliated with the general
partners of Northern Border Partners and TC PipeLines.
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
Our 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 our 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.
Our business depends in part on the level of demand for
western Canadian natural gas in the markets our 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 our pipeline system.
Demand for western Canadian natural gas to serve other
markets also influences the ability and willingness of
shippers to use our pipeline system to meet demand in the
market that our pipeline serves.
A variety of factors could affect the demand for natural
gas in the markets that our 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 our pipeline system
or how significant that adverse effect could be.
Future Demand and Competition
In October 1998, we applied to the FERC for approval of
Project 2000 to expand and extend our pipeline system into
Indiana. If constructed, Project 2000 will
strategically position us to move natural gas east of
Chicago and will place us 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, we amended
our application to the FERC to reflect these changes.
Numerous parties have filed to intervene in this proceeding.
Several parties have protested this application asking that
the FERC deny our request for rolled-in rate treatment for
the new facilities and that we 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, our amended
application to construct facilities to expand our system was
filed based upon rolled-in rate treatment. On December 17,
1999, we 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 our application. On March 16, 2000, the FERC issued an
order granting our application for a certificate to
construct and operate the proposed facilities and finding
that our project meets the requirements of the new policy
statement. The FERC approved our request for rolled-in rate
treatment based upon our proposed project costs. Upon acceptance
of our 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, our
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, we are negotiating with the project
shippers 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.
We compete 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. Our 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, we 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 our 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 our customers.
Natural gas is also produced in the United States and
transported by competing pipeline systems to the same
destinations as our pipeline system.
FERC Regulation
General
We are 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 our
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, we hold certificates of public convenience
and necessity issued by the FERC covering our 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. Our books and
records are periodically audited under Section 8.
The FERC regulates our 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
Our 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
our 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.
We may not charge or collect more than our cost of service
under our tariff on file with the FERC.
Our investment in our pipeline system is reflected in
various accounts referred to collectively as our 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. Our 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.
We bill 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.
We also provide 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, we credit all revenue from the
interruptible transportation service to the cost of service
for the benefit of our firm shippers.
In our 1995 rate case, we 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, our 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, we may
continue to calculate our allowance for income taxes as a
part of our cost of service in the manner we have
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, we implemented a
project cost containment mechanism for The Chicago Project.
The purpose of the project cost containment mechanism was to
limit our ability to include cost overruns for The Chicago
Project in our 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.
We have 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. Our
notification to the FERC and our shippers in June 1999 in
our 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 our calculation of the
project cost containment mechanism in October 1999. The
independent accountants concluded we 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, we filed a rate case wherein we proposed,
among other things, to increase our allowed equity rate of
return to 15.25%. The total annual cost of service increase
due to our proposed changes is approximately $30 million. A
number of our 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 our proposed changes but also several
issues raised by intervenors including the appropriateness
of our cost of service tariff, our depreciation schedule and
our creditworthiness standards. Several parties, including
ourselves, 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 our 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, we filed our June 1999 final report and the
independent accountants' report on the calculation of the
project cost containment mechanism. While we had not
proposed in this case to change the depreciation rates
approved in our last rate case, the order also provided that
we have the burden of proving that our 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 we have been a transportation only pipeline
since inception, implementation was easily met. Capacity
release provisions were adopted which allowed our 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 us
as a result of the temporary release. The releasing shipper
is not relieved of its obligations under its contract.
Shippers on our 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.
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. We have 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 twelve 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 our 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,
the Compensation and Liability Act of 1980, the Clean Air
Act, the Clean Water Act, the Natural Gas Pipeline Safety
Act of 1969, and the Pipeline Safety Act of 1992. Although
we believe that our operations and facilities comply 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 these costs and
liabilities. We have ongoing environmental and safety audit
programs.
Item 2. Properties
We hold the right, title and interest in our pipeline
system. We own all of our material equipment and personal
property and lease office space in Omaha, Nebraska. With
respect to real property, our pipeline system falls into two
basic categories: (a) parcels which we own in fee, including
nearly all of the compressor stations, meter stations and
pipeline field office sites; and (b) parcels where our
interest derives from leases, easements, rights-of-way,
permits or licenses from landowners or governmental
authorities permitting the use of the land for the
construction and operation of our pipeline system. The
right to construct and operate the pipeline across some
property was obtained through exercise of the power of
eminent domain. We continue to have the power of eminent
domain in each of the states in which we operate our
pipeline system, although we 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.
While it is unclear if we have the right of eminent domain
over tribal lands, we have the right of eminent domain over
allotted lands.
In 1980, we 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
the right and privilege to construct and operate our
pipeline on certain tribal lands, for a term of 15 years,
renewable for an additional 15-year term at our option
without additional rental. We continue to operate this
portion of the pipeline located on tribal lands in
accordance with our 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, we 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 on March 25, 1981, for and on
behalf of individual Indian owners, expired on March 31,
1996. Before the termination date, we undertook efforts to
obtain voluntary consents from individual Indian owners for
a new right-of-way, and we filed applications with the
Bureau of Indian Affairs 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 Bureau of Indian Affairs 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 our
favor on the tracts in question.
Item 3. Legal Proceedings
In addition to the condemnation actions and matters
related to FERC regulation, various legal actions that have
arisen in the ordinary course of business are pending. In
our opinion, none of these proceedings would reasonably be
expected to have a material adverse impact on our financial
position, results of operations or cash flows.
Item 4. Submission of Matters to a Vote of Security Holders
There were no matters submitted to a vote of security
holders during 1999.
<PAGE>
PART II
Item 5. Market for the Registrant's Common Equity and
Related Stockholder Matters
The general partnership interests of Northern Border
Pipeline Company are not traded in an established public
market. See Item 12. "Security Ownership of Certain
Beneficial Owners and Management".
The payment of distributions to our general partners is
restricted under the terms of the 1997 Pipeline Credit
Agreement and the 1992 Note Purchase Agreement. See Note 4,
"Credit Facilities and Long-Term Debt", in the Notes to
Financial Statements referred to in Item 8. "Financial
Statements and Supplementary Data." Under the most
restrictive covenants, approximately $132 million of
partners' capital could be distributed as of December 31,
1999.
<PAGE>
<TABLE>
Item 6. Selected Financial Data
(in thousands, except other financial and operating data)
<CAPTION>
Year Ended December 31,
1999 1998 1997 1996 1995
<S> <C> <C> <C> <C> <C>
INCOME DATA:
Operating revenues, net $ 298,347 $ 196,600 $ 186,050 $ 201,943 $ 206,497
Operations and
maintenance 38,708 29,447 28,522 26,974 25,573
Depreciation and
amortization 51,908 40,989 38,708 46,979 47,081
Taxes other than
income 30,320 21,381 22,393 24,390 23,886
Regulatory credit -- (8,878) -- -- --
Operating income 177,411 113,661 96,427 103,600 109,957
Interest expense, net 60,214 25,541 29,360 32,670 35,106
Other income (expense) 1,363 12,111 5,705 2,913 (316)
Net income to partners $ 118,560 $ 100,231 $ 72,772 $ 73,843 $ 74,535
CASH FLOW DATA:
Net cash provided by
operating activities $ 171,466 $ 103,777 $ 115,328 $136,808 $ 127,429
Capital expenditures 101,678 651,169 152,070 18,597 8,310
Distributions to
partners 127,163 61,205 99,322 102,845 98,517
BALANCE SHEET DATA
(AT END OF PERIOD):
Property, plant
and equipment, net $1,731,394 $1,714,523 $1,100,890 $937,859 $ 957,587
Total assets 1,796,691 1,790,889 1,147,120 974,137 1,011,361
Long-term debt,
including current
maturities 900,459 862,000 459,000 377,500 410,000
Partners' capital 834,835 843,438 581,412 526,962 555,964
OTHER FINANCIAL DATA:
Ratio of earnings to
fixed charges (1) 3.0 3.2 3.2 3.2 3.1
OPERATING DATA:
Natural gas delivered
(millions of cubic
feet) 834,833 608,187 621,262 630,148 614,617
Average throughput
(millions of cubic
feet per day) 2,353 1,706 1,735 1,755 1,717
<FN>
(1) "Earnings" means the sum of pre-tax income from continuing
operations and fixed charges. "Fixed charges" means the sum of (a)
interest expensed and capitalized; (b) amortized premiums, discounts
and capitalized expenses related to indebtedness; and (c) an estimate
of interest within rental expenses.
</TABLE>
<PAGE>
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 $101.7 million (52%) for the
year ended December 31, 1999, as compared to the same period in
1998, due primarily to additional revenue from the 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. Our 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.
We are generally allowed an opportunity to collect from our
shippers a return on unrecovered rate base as well as recover
that rate base through depreciation and amortization. The return
amount we collect from our shippers declines as the rate base is
recovered. The Chicago Project increased our 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 $9.3 million (31%)
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 $10.9 million
(27%) 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%. We 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 (42%) 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, we recorded a regulatory
credit of $8.9 million. During the construction of The Chicago
Project, we 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. We are allowed to recover from our
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 $34.7 million (136%) for the
year ended December 31, 1999, as compared to the same period in
1998, due to an increase in interest expense of $15.8 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 $10.7 million (89%) 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.
Year ended December 31, 1998 Compared With the Year ended
December 31, 1997
Operating revenues, net increased $10.6 million (6%) for the
year ended December 31, 1998, as compared to the results for 1997
due primarily to returns on higher levels of invested equity.
Depreciation and amortization expense increased $2.3 million
(6%) for the year ended December 31, 1998, as compared to 1997,
primarily due to facilities that were placed in service in 1998.
For the year ended December 31, 1998, we recorded a regulatory
credit of approximately $8.9 million. During the construction of
The Chicago Project, we 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. We are
allowed to recover from our 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 decreased $3.8 million (13%) for the year
ended December 31, 1998, as compared to the results for 1997, due
to an increase in interest expense of $11.5 million offset by an
increase in the amount of interest expense capitalized of $15.3
million. The increase in interest expense was 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 increase in interest expense capitalized
primarily relates to expenditures for The Chicago Project.
Other income increased $6.4 million (112%) for the year ended
December 31, 1998, as compared to 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 expenditures for The Chicago Project.
Other income for 1997 included $4.8 million received for
vacating certain microwave frequency bands. The amounts received
were a one-time occurrence and we do not expect to receive any
material payments for vacating microwave frequency bands in the
future.
Liquidity and Capital Resources
General
In August 1999, we 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 we 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, we 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 maturing in June 2002 to be used
for the retirement of our 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 31, 1999, the three-year revolving credit
facility converted to a term loan maturing in June 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, we 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. We anticipate borrowing on
the Pipeline Credit Agreement to repay the Series A Notes.
Short-term liquidity needs will be met by internal sources and
through the revolving credit facility discussed above. Long-term
capital needs may be met through the ability to issue long-term
indebtedness.
Cash Flows From Operating Activities
Cash flows provided by operating activities increased $67.7
million to $171.5 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 $11.6
million to $103.8 million for the year ended December 31, 1998 as
compared to 1997 primarily related to a $25.4 million reduction
for changes in accounts payable, exclusive of accruals for The
Chicago Project. In addition, for the year ended December 31,
1998, there was a $7.4 million reduction for changes in
over/under recovered cost of service. These reductions were
partially offset by the effect of the refund activity of 1997
discussed below. The over/under recovered cost of service is the
difference between estimated billings to our 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, we collected
$40.4 million subject to refund as a result of the rate case.
Cash Flows From Investing Activities
Capital expenditures of $101.7 million for the year ended
December 31, 1999 included $85.5 million for The Chicago Project
and $2.5 million for Project 2000. The remaining capital
expenditures for 1999 are primarily related to renewals and
replacements of existing facilities. For the same period in
1998, capital expenditures were $651.2 million, which included
$638.7 million for The Chicago Project and $11.7 million for
linepack gas purchased from our shippers. Linepack gas is the
natural gas required to fill the pipeline system. The cost of
the linepack gas is included in our 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 for renewals and
replacements of existing facilities. We currently anticipate
funding our 2000 capital expenditures primarily by using
internal sources.
Cash Flows From Financing Activities
Cash flows used in financing activities were $89.9 million for
the year ended December 31, 1999, as compared to cash flows
provided by financing activities of $564.8 million for the same
period in 1998. During the year ended December 31, 1998, our
general partners contributed $223.0 million to finance a portion
of the capital expenditures for The Chicago Project.
Distributions paid to the general partners increased $66.0
million to $127.2 million for the year ended December 31, 1999 as
compared to the same period of 1998. The distributions for 1999
were impacted by increased earnings and included distributions
for 13 months activity, rather than 12 months, resulting from a
change in the timing of distribution payments. The distributions
for 1998 were impacted by a rate case refund during the fourth
quarter of 1997 and by the change in the timing of distribution
payments. 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 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 million for the
year ended December 31, 1999 as compared to advances of $403
million for the same period in 1998. Payments on our credit
agreement were $263 million for the year ended December 31, 1999.
Cash flows provided by financing activities increased $512.4
million to $564.8 million for the year ended December 31, 1998,
as compared to the same period in 1997. Financing activities for
1998 include borrowings under the Pipeline Credit Agreement of
$403.0 million and were used primarily for capital expenditures
related to The Chicago Project. Contributions received from our
general partners increased $142.0 million to $223.0 million and
were used to fund a portion of the capital expenditures.
Distributions to the general partners decreased $38.1 million to
$61.2 million primarily due to a change in the timing of
distribution payments. Distributions for 1998 were also reduced
due to the impact of the rate case refund during the fourth
quarter of 1997.
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 8 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 Item 1. "Business - Future Demand and
Competition" and elsewhere regarding our efforts to pursue
opportunities to further increase the capacity of our
pipeline system;
* the discussion under Item 1. "Business - Shippers" regarding
potential contract extensions;
* the discussion under Item 1. "Business - FERC Regulation -
Cost of service tariff" regarding a project cost containment
mechanism related to The Chicago Project; and
* the discussion in Item 1. "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;
* our success in sustaining our positions in such proceedings,
or the success of intervenors in opposing our positions;
* our ability to replace our 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 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 55% 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, annual interest expense would
increase by approximately $4.0 million. This amount has been
determined by considering the impact of the hypothetical interest
rates on variable rate borrowings and interest rate swap
agreements outstanding as of December 31, 1999. Our tariff
provides the pipeline an opportunity to recover, among other
items, interest expense. We believe that under our current
tariff we would be allowed to recover any increase in interest
expense, and that there would not be any material impact on our
annual earnings and cash flow from a hypothetical one percentage
point increase in interest rates.
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.
<PAGE>
PART III
Item 10. Partnership Management
Northern Border Pipeline Company is overseen by the management
committee, which is composed of the following individuals:
Larry L. DeRoin, Chairman(1)
Stanley C. Horton(1)
Garry P. Mihaichuk(2)
Cuba Wadlington, Jr.(1)
__________
(1) Designated by Northern Border Partners.
(2) Designated by TC PipeLines.
Larry L. DeRoin (58) has been a member of our management
committee since 1985 and has been Chairman since 1988. Mr.
DeRoin was named Chief Executive Officer of Northern Border
Partners in July 1993. Mr. DeRoin has been the President and a
director of Northern Plains, an Enron subsidiary and our
operator, since 1985.
Stanley C. Horton (50) has been a member of our management
committee since December 1998. Mr. Horton is the Chairman and
Chief Executive Officer of the Gas Pipeline Group of Enron Corp.
and has held that position since January 1997. Prior to that,
Mr. Horton served as Co-Chairman and Chief Executive Officer of
Enron Operations Corp. (1996-1997) and President and Chief
Operating Officer of Enron Operations Corp. (1993-1996). He is a
director of EOTT Energy Corp., the general partner of EOTT Energy
Partners, L.P.
Garry P. Mihaichuk (46) has been a member of our management
committee since September 1999. He was appointed a director of
TC PipeLines GP, Inc. (the general partner of TC PipeLines LP) in
August 1999 and in October 1999 also became its President and
Chief Executive Officer. Mr. Mihaichuk's principal occupation is
Senior Vice President and President, Transmission of TransCanada
PipeLines Limited, and he has held that position since August
1999. Mr. Mihaichuk was Senior Vice-President and President,
International of TransCanada from July 1996 to August 1999.
Prior to July 1996, he served as Senior Vice President for Amoco
Corporation and Chairman of Amoco Orient Company.
Cuba Wadlington, Jr. (56) has been a member of our management
committee since 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.
Day-to-day management and operations are the responsibility of
the operator, Northern Plains, as set forth in the operating
agreement. We have no employees or executive officers. Officers
and employees of Northern Plains provide services to our
operations and we reimburse Northern Plains for such costs. We
do not compensate members of the management committee for their
services.
There is also an audit and compensation committee composed of
members appointed by the management committee. The audit and
compensation committee, consisting of Messrs. Mihaichuk and
Wadlington, oversees the annual audit process and confers with
Arthur Andersen LLP, our independent public accountants. The
committee is also responsible for setting up guidelines for
compensation to be paid to the executive officers of Northern
Plains, each of whom spends at least a portion of his or her time
on our operations, for which Northern Plains is reimbursed as
indicated above. Currently, there is one vacancy on the
committee.
Item 11. Executive Compensation
Executive Disclosure
Jerry L. Peters (42) has served as Treasurer of Northern Plains
since October 1998, Vice President of Finance for Northern Plains
since July 1994 and director of Northern Plains since August
1994. He has been associated with Northern Plains since 1985.
The following table summarizes information regarding
compensation paid or accrued during each of the last
three fiscal years to Messrs. Larry L. DeRoin and Jerry L. Peters
(the "Named Officers") by Northern Plains, our operator. Messrs.
DeRoin and Peters are both employees of Northern Plains, but contribute
services to our operations, for which we reimburse Northern
Plains. Northern Plains is an affiliate of Enron.
<TABLE>
<CAPTION>
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)
<S> <C> <C> <C> <C> <C> <C> <C>
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 $ -
__________
<FN>
(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 $93,365. Dividend
equivalents for all restricted stock awards accrue from date of
grant and are paid upon vesting.
(4) The amounts shown include the value of Enron Common Stock
allocated to employees' special subaccounts under Enron's
Employee Stock Ownership Plan, matching contributions to
employees' Enron Corp. Savings Plan, and imputed income on
life insurance benefits.
</TABLE>
Stock Option Grants During 1999
The following table sets forth information with respect to grants of
stock options pursuant to Enron's stock plans to the Named Officers
reflected in the Summary Compensation Table. No stock appreciation
rights were granted during 1999.
<TABLE>
<CAPTION>
Individual Grants Potential Realizable
% of Total Value at Assumed
Options/SARs Exercise Annual Rate of
Options/SARs Granted to or Base Stock Price Appreciation
Granted Employees in Price Expiration For Option Term (4)
Name (#) (1) Fiscal Year ($/Sh) Date 0% (3) 5% 10%
<S> <C> <C> <C> <C> <C> <C> <C>
Jerry L. Peters 9,070 (2) 0.03% $32.6875 01/25/06 $ - $120,696 $281,272
______________________
<FN>
(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.
</TABLE>
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:
<TABLE>
<CAPTION>
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
<S> <C> <C> <C> <C> <C> <C>
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
</TABLE>
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.
<TABLE>
<CAPTION>
Estimated
Current Credited Current Estimated
Credited Years of Compensation Annual Benefit
Years of Service Covered Payable Upon
Service at Age 65 By Plans Retirement
<S> <C> <C> <C> <C>
Mr. DeRoin 32.3 39.0 $266,367 $138,575
Mr. Peters 14.9 37.8 $132,933 $ 75,167
________
<FN>
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.
</TABLE>
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. Beneficial Ownership Of Partnership Interests
The following table sets forth the beneficial ownership of
general partnership interests of Northern Border Pipeline
Company. There are no limited partnership interests.
Name of Beneficial Owner General Partnership
Interest
Northern Border Partners,
L.P.(1) 70%
TC PipeLines, LP(2) 30%
__________
(1) The address of Northern Border Partners, L.P. is 1400
Smith Street, Houston, Texas 77002. Northern Border Partners
holds its 70% general partnership interest through Northern
Border Intermediate Limited Partnership, a subsidiary limited
partnership. Northern Border Partners has three general
partners: Northern Plains Natural Gas Company, Pan Border Gas
Company and Northwest Border Pipeline Company. Northern
Plains and Pan Border are wholly-owned subsidiaries of Enron
Corp. and Northwest Border is a wholly-owned subsidiary of The
Williams Companies, Inc.
(2) The address of TC PipeLines, LP is Four Greenspoint
Plaza, 16945 Northchase Drive, Houston, Texas 77060. TC
PipeLines holds its 30% general partnership interest through
TC PipeLines Intermediate Limited Partnership, a subsidiary
limited partnership. TC PipeLines has one general partner, TC
PipeLines GP, Inc., a wholly-owned subsidiary of TransCanada
PipeLines Limited.
Item 13. Certain Relationships And Related Transactions
We have extensive ongoing relationships with our general partners
and certain of their affiliates. Since 1980, Northern Plains, an
affiliate of Enron, has acted and will continue to act as the
operator of our pipeline system pursuant to the terms of the
operating agreement with Northern Plains. The initial term of
the operating agreement expires in 2007. The operating agreement
will continue in effect thereafter on a year-to-year basis unless
terminated by us or Northern Plains upon six months written
notice by either party. The operator is entitled to
reimbursement for all reasonable costs, including overhead and
administrative expenses, incurred by it and its affiliates in
connection with the performance of its responsibilities as
operator. In addition, we have agreed to indemnify the operator
against any claims and liabilities arising out of the good faith
performance by the operator of its responsibilities under our
partnership agreement, to the extent the operator is acting
within the scope of its authority and in the course of our
business. For the year ended December 31, 1999, the aggregate
amount paid and reimbursed to Northern Plains, for its services
as operator, was approximately $29.7 million.
Enron Engineering & Construction Company, 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 Enron Engineering. The
project management agreement provided for the appointment of
Enron Engineering as project manager of The Chicago Project.
Pursuant to the agreement, Enron Engineering's responsibilities
included (1) the provision of adequate and qualified manpower
necessary for the work contemplated by the project; (2)
procurement of required equipment and materials and the services
for installation; (3) management and monitoring of performance of
vendors and contractors; and (4) obtaining all permits necessary
for the work as required by federal, state or local authorities.
Northern Plains compensated Enron Engineering for costs incurred
in performing the required work on The Chicago Project. Through
December 31, 1999, approximately $16.8 million has been paid to
Enron Engineering for project management of The Chicago Project.
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 terms of all such related transactions are no less
favorable to us than those we would expect to negotiate with
unrelated third parties on an arm's length basis.
Our interests could conflict with the interests of our general
partners or their affiliates, and in such case the members of our
management committee will generally have a fiduciary duty to
resolve such conflicts in a manner that is in our best interest.
Unless otherwise provided for in a partnership agreement, the
laws of 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. These rules apply to our management committee. Because
of the competing interests identified above, the Northern Border
Pipeline Company Partnership Agreement contains provisions that
modify certain of these fiduciary duties. For example:
* The partnership agreement provides that we indemnify the
members of our management committee and Northern Plains, as
the operator, against all actions if such actions were in
good faith and within the scope of their authority in the
course of our business. It also provides that such persons
will not be liable for any liabilities incurred by us as a
result of such acts.
* The partnership agreement states that our general partners
will not be liable to third persons for our losses, deficits,
liabilities or obligations (unless our assets have been
exhausted).
* The partnership agreement requires that any contract entered
into on our behalf must contain a provision limiting the
claims of persons to our assets and expressly waiving any
rights of such persons to proceed against our general
partners individually.
* The partnership agreement relieves Northern Border Partners
and TC PipeLines, their affiliates and their transferees from
any duty to offer business opportunities to us, except that
neither our general partners or their affiliates may pursue
Project 2000 or any other opportunity relating to expansion
or improvements of our pipeline system as it existed on
January 15, 1999.
<PAGE>
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 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 Northern Border Partners, L.P.'s Form
S-1, SEC File No. 33-66158 ("Form S-1")).
* 4.1 Indenture, dated as of August 17, 1999,
between the registrant and Bank One Trust
Company, NA, successor to The First
National Bank of Chicago, as trustee.
(Exhibit 4.1 to Northern Border Pipeline
Company's Form S-4 Registration
Statement, Registration No. 333-88577
("Form S-4")).
* 4.2 Registration Rights Agreement, dated as
of August 17, 1999, by and among the
registrant and Banc of America Securities
LLC, Lehman Brothers Inc., A.G. Edwards &
Sons, Inc. and Salomon Smith Barney Inc.,
as Initial Purchasers. (Exhibit No. 4.2
to Form S-4).
*10.1 Operating Agreement between Northern
Border Pipeline Company and Northern
Plains Natural Gas Company, dated
February 28, 1980 (Exhibit 10.3 to Form S-
1).
*10.2 Note Purchase Agreement between Northern
Border Pipeline Company and the parties
listed therein, dated July 15, 1992
(Exhibit 10.6 to Form S-1).
*10.3 Supplemental Agreement to the Note
Purchase Agreement dated as of June 1,
1995 (Exhibit 10.6.1 to Northern Border
Partners L.P.'s Form 10-K for the year
ended December 31, 1995, SEC File No. 1-12202
("1995 10-K")).
*10.4 Guaranty made by Panhandle Eastern
Pipeline Company, dated October 31, 1992
(Exhibit 10.9 to Form S-1).
*10.5 Northern Border Pipeline Company U.S.
Shippers Service Agreement between
Northern Border Pipeline Company and
Enron Gas Marketing, Inc., dated June 22,
1990 (Exhibit 10.10 to Form S-1).
*10.6 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 Northern Border
Partners L.P.'s Form 10-K for the year
ended December 31, 1993, SEC File No. 1-12202
("1993 10-K")).
*10.7 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
Northern Border Partners, L.P.'s Form 10-K
for the year ended December 31, 1994,
SEC File No. 1-12202 ("1994 10-K")).
*10.8 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).
*10.9 Amended Exhibit A to Northern Border
Pipeline Company U.S. Shipper Service
Agreement effective April l, 1998
(Exhibit 10.10.4 to Northern Border
Partners, L.P.'s Form 10-K for the year
ended December 31, 1997, SEC File No. 1-12202
("1997 10-K")).
*10.10 Guaranty made by Northern Natural Gas
Company, dated October 7, 1993 (Exhibit
10.11.1 to 1993 10-K).
*10.11 Guaranty made by Northern Natural Gas
Company, dated October 7, 1993 (Exhibit
10.11.2 to 1993 10-K)
*10.12 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).
*10.13 Amendment to Northern Border Pipeline
Company Service Agreement extending the
term effective November 1, 1995 (Exhibit
10.13.1 to 1995 10-K).
*10.14 Seventh Supplement Amending Northern
Border Pipeline Company General
Partnership Agreement (Exhibit 10.15 to
Form S-1).
*10.15 Eighth Supplement Amending Northern
Border Pipeline Company General
Partnership Agreement. (Exhibit 10.15 of
Form S-4).
*10.16 Form of Conveyance, Contribution and
Assumption Agreement among Northern
Plains Natural Gas Company, Northwest
Border Pipeline Company, Pan Border Gas
Company, Northern Border Partners, L.P.,
and Northern Border Intermediate Limited
Partnership (Exhibit 10.16 to Form S-1).
*10.17 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).
*10.18 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
Northern Border Partners, L.P. Form S-3,
SEC File No 333-40601 ("Form S-3")).
*10.19 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).
*10.20 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).
*10.21 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).
*10.22 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).
*10.23 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).
*10.24 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).
*10.25 Northern Border Pipeline Company
Agreement among Northern Plains Natural
Gas Company, Pan Border Gas Company,
Northwest Border Pipeline Company,
TransCanada Border PipeLine Ltd.,
TransCan Northern Ltd., Northern Border
Intermediate Limited Partnership,
Northern Border Partners, L.P., and the
Management Committee of Northern Border
Pipeline, dated as of March 17, 1999.
(Exhibit No. 10.21 to Northern Border
Partners, L.P.'s Form 10-K for the year
ended December 31, 1998, SEC File No. 1-12202
("1998 10-K")).
*10.26 Form of Contribution, Conveyance and
Assumption Agreement among TC PipeLines,
LP and certain other parties. (Exhibit
10.2 to TC PipeLines, LP's Form S-1, SEC
File No. 333-69947 ("TC Form S-1")).
*10.27 Amended Exhibit A to Northern Border
Pipeline Company U.S. Shippers Service
Agreement between Northern Border
Pipeline Company and Western Gas
Marketing extending the term effective
April 2, 1999 (Exhibit 10.11.1 to TC Form
S-1).
*10.28 Amended Exhibit A to Northern Border
Pipeline Company U.S. Shippers Service
Agreement between Northern Border
Pipeline Company and Enron Capital &
Trade Resources Corp. effective November 1,
1998 (Exhibit 10.15.1 to TC Form S-1).
*10.29 Amended Exhibit A to Northern Border
Pipeline Company U.S. Shippers Service
Agreement between Northern Border
Pipeline Company and Enron Capital &
Trade Resources Corp. effective April 2,
1999 (Exhibit 10.16.1 to TC Form S-1).
*10.30 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
October 10, 1996, with Amended Exhibit A
effective April 2, 1999 (Exhibit 10.19 to
TC Form S-1).
*10.31 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
October 5, 1998, with Amended Exhibit A
effective April 2, 1999 (Exhibit 10.20 to
TC Form S-1).
*10.32 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
October 5, 1998, with Amended Exhibit A
effective April 2, 1999 (Exhibit 10.21 to
TC Form S-1).
*10.33 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
October 5, 1998, with Amended Exhibit A
effective April 2, 1999 (Exhibit 10.22 to
TC Form S-1).
*10.34 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
October 5, 1998, with Amended Exhibit A
effective April 2, 1999 (Exhibit 10.23 to
TC Form S-1).
*10.35 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
December 18, 1998 (Exhibit 10.24 to TC
Form S-1).
*10.36 Northern Border Pipeline Company U.S.
Shippers Service Agreement between
Northern Border Pipeline Company and Pan-
Alberta Gas (U.S.) Inc., dated October 1,
1993, with Amended exhibit A effective
June 22, 1998 (Exhibit 10.25 to TC Form S-1).
*10.37 Northern Border Pipeline Company U.S.
Shippers Service Agreement between
Northern Border Pipeline Company and Pan-
Alberta Gas (U.S.) Inc. (successor to
Natgas U.S. Inc.), dated October 6, 1989,
with Amended Exhibit A effective April 2,
1999 (Exhibit 10.26 to TC Form S-1).
*10.38 Northern Border Pipeline Company U.S.
Shippers Service Agreement between
Northern Border Pipeline Company and Pan-
Alberta Gas (U.S.) Inc., dated October 1,
1992, with Amended Exhibit A effective
June 22, 1998 (Exhibit 10.27 to TC Form S-1).
*10.39 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).
27 Financial Data Schedule.
*99.1 Northern Plains Natural Gas Company Phantom
Unit Plan (Exhibit 99.1 to Northern Border
Partners, L.P.'s 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.
<PAGE>
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 PIPELINE COMPANY
(A Texas General partnership)
BY: Northern Plains Natural Gas
Company, As Operator
By: JERRY L. PETERS
Jerry L. Peters
Vice President, Finance and
Treasurer
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 President, Northern Plains Natural
Larry L. DeRoin Gas Company (functional equivalent to
the registrant's principal executive
officer) and Management Committee Member March 28, 2000
JERRY L. PETERS Vice President, Finance and
Jerry L. Peters Treasurer, Northern Plains Natural
Gas Company (functional equivalent to
the registrant's principal financial
and accounting officer) March 28, 2000
STANLEY C. HORTON Management Committee Member March 28, 2000
Stanley C. Horton
GARRY P. MIHAICHUK Management Committee Member March 28, 2000
Garry P. Mihaichuk
CUBA WADLINGTON, JR. Management Committee Member March 28, 2000
Cuba Wadlington, Jr.
<PAGE>
NORTHERN BORDER PIPELINE COMPANY
INDEX TO FINANCIAL STATEMENTS
Page No.
Financial Statements
Report of Independent Public Accountants F-2
Balance Sheet - December 31, 1999 and 1998 F-3
Statement of Income - Years Ended
December 31, 1999, 1998 and 1997 F-4
Statement of Cash Flows - Years Ended F-5
December 31, 1999, 1998 and 1997
Statement of Changes in Partners' Capital - F-6
Years Ended December 31, 1999, 1998 and 1997
Notes to Financial Statements F-7 through
F-16
Financial Statements Schedule
Report of Independent Public Accountants on Schedule S-1
Schedule II - Valuation and Qualifying Accounts S-2
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Northern Border Pipeline Company:
We have audited the accompanying balance sheet of Northern Border
Pipeline Company (a Texas partnership) as of December 31, 1999
and 1998, and the related 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 Pipeline Company as of December 31, 1999 and
1998, and the results of its operations and its 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
<PAGE>
<TABLE>
NORTHERN BORDER PIPELINE COMPANY
BALANCE SHEET
(In Thousands)
<CAPTION>
December 31,
ASSETS 1999 1998
<S> <C> <C>
CURRENT ASSETS
Cash and cash equivalents $ 17,310 $ 37,389
Accounts receivable 21,929 16,434
Related party receivables 5,120 2,470
Materials and supplies, at cost 3,645 3,360
Under recovered cost of service 3,068 2,781
Total current assets 51,072 62,434
NATURAL GAS TRANSMISSION PLANT
In service 2,363,291 2,302,457
Construction work in progress 4,730 1,530
Total property, plant and equipment 2,368,021 2,303,987
Less: Accumulated provision for
depreciation and amortization 636,627 589,464
Property, plant and equipment, net 1,731,394 1,714,523
OTHER ASSETS 14,225 13,932
Total assets $1,796,691 $1,790,889
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES
Current maturities of long-term debt $ 66,000 $ --
Accounts payable 5,588 44,042
Accrued taxes other than income 26,290 19,828
Accrued interest 16,504 11,763
Accumulated provision for rate refunds 2,317 --
Total current liabilities 116,699 75,633
LONG-TERM DEBT, NET OF CURRENT MATURITIES 834,459 862,000
RESERVES AND DEFERRED CREDITS 10,698 9,818
PARTNERS' CAPITAL 834,835 843,438
Total liabilities and partners' capital $1,796,691 $1,790,889
<FN>
The accompanying notes are an integral part of these financial
statements.
</TABLE>
<PAGE>
<TABLE>
NORTHERN BORDER PIPELINE COMPANY
STATEMENT OF INCOME
(In Thousands)
<CAPTION>
Year Ended December 31,
1999 1998 1997
<S> <C> <C> <C>
OPERATING REVENUES
Operating revenues $300,664 $196,600 $226,019
Provision for rate refunds (2,317) -- (39,969)
Operating revenues, net 298,347 196,600 186,050
OPERATING EXPENSES
Operations and maintenance 38,708 29,447 28,522
Depreciation and amortization 51,908 40,989 38,708
Taxes other than income 30,320 21,381 22,393
Regulatory credit -- (8,878) --
Operating expenses 120,936 82,939 89,623
OPERATING INCOME 177,411 113,661 96,427
INTEREST EXPENSE
Interest expense 60,312 44,542 33,020
Interest expense capitalized (98) (19,001) (3,660)
Interest expense, net 60,214 25,541 29,360
OTHER INCOME
Allowance for equity funds used
during construction 101 10,237 1,400
Other income, net 1,262 1,874 4,305
Other income 1,363 12,111 5,705
NET INCOME TO PARTNERS $118,560 $100,231 $ 72,772
<FN>
The accompanying notes are an integral part of these financial
statements.
</TABLE>
<PAGE>
<TABLE>
NORTHERN BORDER PIPELINE COMPANY
STATEMENT OF CASH FLOWS
(In Thousands)
<CAPTION>
Year Ended December 31,
1999 1998 1997
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income to partners $ 118,560 $ 100,231 $ 72,772
Adjustments to reconcile net income to
partners to net cash provided by
operating activities:
Depreciation and amortization 51,962 41,005 38,715
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 (2,112) (18,471) 16,389
Other 840 354 1,079
Total adjustments 52,906 3,546 42,556
Net cash provided by operating activities 171,466 103,777 115,328
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for property, plant
and equipment, net (101,678) (651,169) (152,070)
CASH FLOWS FROM FINANCING ACTIVITIES:
Contributions from partners -- 223,000 81,000
Distributions to partners (127,163) (61,205) (99,322)
Issuance of long-term debt, net 289,026 403,000 209,000
Retirement of long-term debt (263,000) -- (127,500)
Proceeds received upon termination of
interest rate forward agreements 12,896 -- --
Long-term debt financing costs (1,626) -- (744)
Repayment of note payable -- -- (10,000)
Net cash provided by (used in)
financing activities (89,867) 564,795 52,434
NET CHANGE IN CASH AND CASH EQUIVALENTS (20,079) 17,403 15,692
Cash and cash equivalents-beginning of year 37,389 19,986 4,294
Cash and cash equivalents-end of year $ 17,310 $ 37,389 $ 19,986
Changes in components of working capital:
Accounts receivable $ (8,145) $ (1,567) $ 1,927
Materials and supplies (285) 317 170
Accounts payable (4,598) (10,769) 14,587
Accrued taxes other than income 6,462 (466) (674)
Accrued interest 4,741 1,396 14
Over/under recovered cost of service (287) (7,382) 365
Total $ (2,112) $(18,471) $ 16,389
<FN>
The accompanying notes are an integral part of these financial
statements.
</TABLE>
<PAGE>
<TABLE>
NORTHERN BORDER PIPELINE COMPANY
STATEMENT OF CHANGES IN PARTNERS' CAPITAL
(In Thousands)
<CAPTION>
TC Northern
TransCanada PipeLines Border
Border TransCan Intermediate Intermediate Total
PipeLine Northern Limited Limited Partners'
Ltd. Ltd. Partnership Partnership Capital
<S> <C> <C> <C> <C> <C>
Partners' Capital at
December 31, 1996 $ 31,618 $ 126,471 $ -- $368,873 $ 526,962
Net income to partners 4,366 17,466 -- 50,940 72,772
Contributions received 4,860 19,440 -- 56,700 81,000
Distributions paid (5,959) (23,838) -- (69,525) (99,322)
Partners' Capital at
December 31, 1997 34,885 139,539 -- 406,988 581,412
Net income to partners 6,014 24,055 -- 70,162 100,231
Contributions received 13,380 53,520 -- 156,100 223,000
Distributions paid (3,673) (14,689) -- (42,843) (61,205)
Partners' Capital at
December 31, 1998 50,606 202,425 -- 590,407 843,438
Net income to partners 2,930 11,715 20,923 82,992 118,560
Distributions paid (5,206) (20,819) (12,124) (89,014) (127,163)
Ownership transfer (48,330) (193,321) 241,651 -- --
Partners' Capital at
December 31, 1999 $ -- $ -- $250,450 $584,385 $ 834,835
<FN>
The accompanying notes are an integral part of these financial
statements.
</TABLE>
<PAGE>
NORTHERN BORDER PIPELINE COMPANY
NOTES TO FINANCIAL STATEMENTS
1. ORGANIZATION AND MANAGEMENT
Northern Border Pipeline Company (Northern Border Pipeline) is
a general partnership, formed in 1978, pursuant to the Texas
Uniform Partnership Act. The ownership percentages of the
partners in Northern Border Pipeline (Partners) at December 31,
1999 and 1998, are as follows:
Partner 1999 1998
Northern Border Intermediate Limited Partnership 70 70
TC PipeLines Intermediate Limited Partnership 30 --
TransCan Northern Ltd. -- 24
TransCanada Border PipeLine Ltd. -- 6
Net income and distributions are allocated to the Partners
based on ownership percentage. Effective May 28, 1999,
TransCanada Border PipeLine Ltd. and TransCan Northern Ltd.
transferred their combined 30% ownership interest in Northern
Border Pipeline to TC PipeLines Intermediate Limited
Partnership (TC PipeLines) in connection with an initial public
offering of limited partner interests in TC PipeLines, LP. In
accordance with the partnership agreement, net income and
distributions were prorated at the effective date of the
ownership transfer.
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 Northern Border
Intermediate Limited Partnership (Partnership) and one
representative from TC PipeLines. The Partnership's
representatives selected by its general partners, 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, a wholly-owned subsidiary of
The Williams Companies, Inc., have 35%, 22.75% and 12.25%,
respectively, of the voting interest on the Management
Committee. The representative designated by TC PipeLines votes
the remaining 30% interest. 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 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).
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(A) Use of Estimates
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 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 5).
(C) Income Taxes
Income taxes are the responsibility of the Partners and
are not reflected in these financial statements. However,
the Northern Border Pipeline FERC 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.
(D) 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, approximately $3.5 million and
$37.4 million, respectively, of project costs incurred but
not paid for The Chicago Project were recorded in accounts
payable and natural gas transmission plant on the balance
sheet and were excluded from the change in accounts payable
and capital expenditures for property, plant and equipment,
net on the statement of cash flows.
Maintenance and repairs are charged to operations in the
period incurred. The provision for depreciation and
amortization of the transmission line is an integral part
of Northern Border Pipeline's FERC tariff. The effective
depreciation 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 5).
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.
(E) 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.
(F) 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.
(G) 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.
(H) Risk Management
Financial instruments are used by Northern Border
Pipeline in the management of its 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.
3. 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.
4. CREDIT FACILITIES AND LONG-TERM DEBT
Detailed information on long-term debt is as follows:
<TABLE>
<CAPTION>
December 31,
(Thousands of dollars) 1999 1998
<S> <C> <C>
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) --
Total 900,459 862,000
Less: Current maturities of long-term debt 66,000 --
Long-term debt $834,459 $862,000
</TABLE>
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 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.
Interest paid, net of amounts capitalized, during the years
ended December 31, 1999, 1998 and 1997 was $55.5 million, $23.8
million and $29.0 million, respectively.
Aggregate required repayments of long-term debt are as follows:
$66 million, $41 million, $517 million and $65 million for
2000, 2001, 2002 and 2003, respectively. There are no required
repayment obligations for 2004.
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 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. 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.
Northern Border Pipeline presently intends to maintain the
current schedule of maturities for the senior notes and the
interest rate swap agreements which will result in no gains or
losses on their respective repayment. The carrying value of
Northern Border Pipeline's variable rate debt approximates the
fair value since the interest rates are periodically adjusted
to current market conditions.
5. 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, Northern Border Pipeline 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 Northern
Border Pipeline 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 Northern Border Pipeline.
Environmental Matters
Northern Border Pipeline 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. Northern Border Pipeline believes
that the resolution of these issues will not have a material
adverse impact on Northern Border Pipeline's results of
operations or financial position.
6. CAPITAL EXPENDITURE PROGRAM
Total capital expenditures for 2000 are estimated to be $25
million. This includes approximately $10 million for Project
2000 (see Note 5) 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.
7. QUARTERLY FINANCIAL DATA (Unaudited)
<TABLE>
<CAPTION>
Operating Operating Net Income
(In thousands) Revenues, net Income to Partners
<S> <C> <C> <C>
1999
First Quarter $73,635 $44,271 $30,315
Second Quarter 73,022 43,788 28,933
Third Quarter 73,925 44,017 29,127
Fourth Quarter 77,765 45,335 30,185
1998
First Quarter $47,504 $24,939 $20,262
Second Quarter 48,851 27,509 24,844
Third Quarter 49,121 28,829 26,945
Fourth Quarter 51,124 32,384 28,180
</TABLE>
8. 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. Northern Border
Pipeline does not plan to adopt SFAS No. 133 early. Northern
Border Pipeline believes that SFAS No. 133 will not have a
material impact on its financial position or results of
operations.
9. SUBSEQUENT EVENTS
Northern Border Pipeline makes distributions to it general
partners approximately one month following the end of the
quarter. The distribution computed for the fourth quarter of
1999 of approximately $30.9 million is payable February 2,
2000.
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS ON SCHEDULE
To Northern Border Pipeline Company:
We have audited in accordance with generally accepted auditing
standards, the financial statements of Northern Border Pipeline
Company 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 Pipeline Company
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
<PAGE>
<TABLE>
SCHEDULE II
NORTHERN BORDER PIPELINE COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
(In Thousands)
<CAPTION>
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
<S> <C> <C> <C> <C> <C>
Reserve for
regulatory issues
1999 $6,726 $650 $-- $-- $7,376
1998 $6,726 $ -- $-- $-- $6,726
1997 $5,953 $773 $-- $-- $6,726
</TABLE>
<PAGE>
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: 333-88577
NORTHERN BORDER PIPELINE COMPANY
(Exact name of registrant as specified in its charter)
TEXAS 74-2684967
(State or other jurisdiction (I.R.S. Employer Identification No.)
of incorporation or organization)
1111 SOUTH 103rd STREET, OMAHA, NEBRASKA 68124-1000
(Address of principal executive offices) (zip code)
Registrant's telephone number, including area code: 402-398-7700
<PAGE>
EXHIBIT INDEX
* 3.1 Northern Border Pipeline Company General
Partnership Agreement between Northern
Plains Natural Gas Company, Northwest
Border Pipeline Company, Pan Border Gas
Company, TransCanada Border Pipeline Ltd.
and TransCan Northern Ltd., effective March
9, 1978, as amended (Exhibit 10.2 to
Northern Border Partners, L.P.'s Form S-1,
SEC File No. 33-66158 ("Form S-1")).
* 4.1 Indenture, dated as of August 17, 1999,
between the registrant and Bank One Trust
Company, NA, successor to The First
National Bank of Chicago, as trustee.
(Exhibit 4.1 to Northern Border Pipeline
Company's Form S-4 Registration Statement,
Registration No. 333-88577 ("Form S-4")).
* 4.2 Registration Rights Agreement, dated as of
August 17, 1999, by and among the
registrant and Banc of America Securities
LLC, Lehman Brothers Inc., A.G. Edwards &
Sons, Inc. and Salomon Smith Barney Inc.,
as Initial Purchasers. (Exhibit No. 4.2 to
Form S-4).
*10.1 Operating Agreement between Northern Border
Pipeline Company and Northern Plains
Natural Gas Company, dated February 28,
1980 (Exhibit 10.3 to Form S-1).
*10.2 Note Purchase Agreement between Northern
Border Pipeline Company and the parties
listed therein, dated July 15, 1992
(Exhibit 10.6 to Form S-1).
*10.3 Supplemental Agreement to the Note Purchase
Agreement dated as of June 1, 1995 (Exhibit
10.6.1 to Northern Border Partners L.P.'s
Form 10-K for the year ended December 31,
1995, SEC File No. 1-12202 ("1995 10-K")).
*10.4 Guaranty made by Panhandle Eastern Pipeline
Company, dated October 31, 1992 (Exhibit
10.9 to Form S-1).
*10.5 Northern Border Pipeline Company U.S.
Shippers Service Agreement between Northern
Border Pipeline Company and Enron Gas
Marketing, Inc., dated June 22, 1990
(Exhibit 10.10 to Form S-1).
*10.6 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 Northern Border
Partners L.P.'s Form 10-K for the year
ended December 31, 1993, SEC File No. 1-
12202 ("1993 10-K")).
*10.7 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
Northern Border Partners, L.P.'s Form 10-K
for the year ended December 31, 1994, SEC
File No. 1-12202 ("1994 10-K")).
*10.8 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).
*10.9 Amended Exhibit A to Northern Border
Pipeline Company U.S. Shipper Service
Agreement effective April l, 1998 (Exhibit
10.10.4 to Northern Border Partners, L.P.'s
Form 10-K for the year ended December 31,
1997, SEC File No. 1-12202 ("1997 10-K")).
*10.10 Guaranty made by Northern Natural Gas
Company, dated October 7, 1993 (Exhibit
10.11.1 to 1993 10-K).
*10.11 Guaranty made by Northern Natural Gas
Company, dated October 7, 1993 (Exhibit
10.11.2 to 1993 10-K)
*10.12 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).
*10.13 Amendment to Northern Border Pipeline
Company Service Agreement extending the
term effective November 1, 1995 (Exhibit
10.13.1 to 1995 10-K).
*10.14 Seventh Supplement Amending Northern Border
Pipeline Company General Partnership
Agreement (Exhibit 10.15 to Form S-1).
*10.15 Eighth Supplement Amending Northern Border
Pipeline Company General Partnership
Agreement. (Exhibit 10.15 of Form S-4).
*10.16 Form of Conveyance, Contribution and
Assumption Agreement among Northern Plains
Natural Gas Company, Northwest Border
Pipeline Company, Pan Border Gas Company,
Northern Border Partners, L.P., and
Northern Border Intermediate Limited
Partnership (Exhibit 10.16 to Form S-1).
*10.17 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).
*10.18 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 Northern Border
Partners, L.P. Form S-3, SEC File No 333-
40601 ("Form S-3")).
*10.19 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).
*10.20 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).
*10.21 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).
*10.22 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).
*10.23 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).
*10.24 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).
*10.25 Northern Border Pipeline Company Agreement
among Northern Plains Natural Gas Company,
Pan Border Gas Company, Northwest Border
Pipeline Company, TransCanada Border
PipeLine Ltd., TransCan Northern Ltd.,
Northern Border Intermediate Limited
Partnership, Northern Border Partners,
L.P., and the Management Committee of
Northern Border Pipeline, dated as of March
17, 1999. (Exhibit No. 10.21 to Northern
Border Partners, L.P.'s Form 10-K for the
year ended December 31, 1998, SEC File No.
1-12202 ("1998 10-K")).
*10.26 Form of Contribution, Conveyance and
Assumption Agreement among TC PipeLines, LP
and certain other parties. (Exhibit 10.2 to
TC PipeLines, LP's Form S-1, SEC File No.
333-69947 ("TC Form S-1")).
*10.27 Amended Exhibit A to Northern Border
Pipeline Company U.S. Shippers Service
Agreement between Northern Border Pipeline
Company and Western Gas Marketing extending
the term effective April 2, 1999 (Exhibit
10.11.1 to TC Form S-1).
*10.28 Amended Exhibit A to Northern Border
Pipeline Company U.S. Shippers Service
Agreement between Northern Border Pipeline
Company and Enron Capital & Trade Resources
Corp. effective November 1, 1998 (Exhibit
10.15.1 to TC Form S-1).
*10.29 Amended Exhibit A to Northern Border
Pipeline Company U.S. Shippers Service
Agreement between Northern Border Pipeline
Company and Enron Capital & Trade Resources
Corp. effective April 2, 1999 (Exhibit
10.16.1 to TC Form S-1).
*10.30 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 October 10, 1996,
with Amended Exhibit A effective April 2,
1999 (Exhibit 10.19 to TC Form S-1).
*10.31 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 October 5, 1998,
with Amended Exhibit A effective April 2,
1999 (Exhibit 10.20 to TC Form S-1).
*10.32 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 October 5, 1998,
with Amended Exhibit A effective April 2,
1999 (Exhibit 10.21 to TC Form S-1).
*10.33 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 October 5, 1998,
with Amended Exhibit A effective April 2,
1999 (Exhibit 10.22 to TC Form S-1).
*10.34 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 October 5, 1998,
with Amended Exhibit A effective April 2,
1999 (Exhibit 10.23 to TC Form S-1).
*10.35 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 December 18, 1998
(Exhibit 10.24 to TC Form S-1).
*10.36 Northern Border Pipeline Company U.S.
Shippers Service Agreement between Northern
Border Pipeline Company and Pan-Alberta Gas
(U.S.) Inc., dated October 1, 1993, with
Amended exhibit A effective June 22, 1998
(Exhibit 10.25 to TC Form S-1).
*10.37 Northern Border Pipeline Company U.S.
Shippers Service Agreement between Northern
Border Pipeline Company and Pan-Alberta Gas
(U.S.) Inc. (successor to Natgas U.S.
Inc.), dated October 6, 1989, with Amended
Exhibit A effective April 2, 1999 (Exhibit
10.26 to TC Form S-1).
*10.38 Northern Border Pipeline Company U.S.
Shippers Service Agreement between Northern
Border Pipeline Company and Pan-Alberta Gas
(U.S.) Inc., dated October 1, 1992, with
Amended Exhibit A effective June 22, 1998
(Exhibit 10.27 to TC Form S-1).
*10.39 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).
27 Financial Data Schedule.
*99.1 Northern Plains Natural Gas Company Phantom
Unit Plan (Exhibit 99.1 to Northern Border
Partners, L.P.'s Form S-8 Registration No.
333-66949).
*Indicates exhibits incorporated by reference as
indicated; all other exhibits are filed herewith.
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> DEC-31-1999
<CASH> 6,320
<SECURITIES> 10,990
<RECEIVABLES> 27,049
<ALLOWANCES> 0
<INVENTORY> 3,645
<CURRENT-ASSETS> 51,072
<PP&E> 2,368,021
<DEPRECIATION> 636,627
<TOTAL-ASSETS> 1,796,691
<CURRENT-LIABILITIES> 116,699
<BONDS> 834,459
0
0
<COMMON> 0
<OTHER-SE> 834,835
<TOTAL-LIABILITY-AND-EQUITY> 1,796,691
<SALES> 0
<TOTAL-REVENUES> 298,347
<CGS> 0
<TOTAL-COSTS> 120,936
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 60,214
<INCOME-PRETAX> 118,560
<INCOME-TAX> 0
<INCOME-CONTINUING> 118,560
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 118,560
<EPS-BASIC> 0
<EPS-DILUTED> 0
</TABLE>
