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, 1998
Commission file number: 1-12202
NORTHERN BORDER PARTNERS, L.P.
(Exact name of registrant as specified in its charter)
DELAWARE 93-1120873
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)
1400 Smith Street, Houston, Texas 77002-7369
(Address of principal executive offices)(zip code)
Registrant's telephone number, including area code: 713-853-6161
___________________
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
Common Units New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months
(or for such shorter period that the registrant was required to
file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes X No ____
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of Regulation S-K is not contained herein,
and will not be contained, to be the best of registrant's
knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. X
Aggregate market value of the Common Units held by non-
affiliates of the registrant, based on closing prices in the
daily composite list for transactions on the New York Stock
Exchange on March 1, 1999, was approximately $817,270,000.
<PAGE>
NORTHERN BORDER PARTNERS, L.P.
TABLE OF CONTENTS
Page No.
Part I
Item 1. Business 1
Item 2. Properties 8
Item 3. Litigation 9
Item 4. Submission of Matters to a Vote of Security Holders 9
Part II
Item 5. Market for Registrant's Common Units and Related
Security Holder Matters 10
Item 6. Selected Financial Data 12
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations 13
Item 7a. Quantitative and Qualitative Disclosures About
Market Risk 20
Item 8. Financial Statements 21
Item 9. Disagreements on Accounting and Financial
Disclosure 21
Part III
Item 10. Partnership Management 22
Item 11. Executive Compensation 25
Item 12. Security Ownership of Certain Beneficial Owners
and Management 31
Item 13. Certain Relationships and Related Transactions 31
Part IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K 34
<PAGE>
PART I
Item 1. Business
General
Northern Border Partners, L.P. through a subsidiary
limited partnership, Northern Border Intermediate Limited
Partnership, collectively referred to herein as
"Partnership", owns a 70% general partner interest in
Northern Border Pipeline Company, a Texas general
partnership ("Northern Border Pipeline"). The remaining
general partner interests in Northern Border Pipeline are
owned by TransCanada Border PipeLine Ltd. (6%) and TransCan
Northern Ltd. (24%), both of which are wholly-owned
subsidiaries of TransCanada PipeLines Limited
("TransCanada").
Northern Plains Natural Gas Company ("Northern
Plains"), Pan Border Gas Company ("Pan Border") and
Northwest Border Pipeline Company ("Northwest Border") serve
as the General Partners of the Partnership. Northern Plains
is a wholly-owned subsidiary of Enron Corp. ("Enron"), and
Northwest Border is a wholly-owned subsidiary of The
Williams Companies, Inc. ("Williams"). In December 1998,
Northern Plains acquired Pan Border from a subsidiary of
Duke Energy Corporation. At the closing, Pan Border's sole
asset consisted of its general partner interest in the
Partnership. The General Partners hold an aggregate 2%
general partner interest in the Partnership. The General
Partners or their affiliates also own Common Units
representing an aggregate 14.5% limited partner interest.
The combined general and limited partner interests in the
Partnership of Enron and Williams are 12.4% and 4.1%,
respectively (See "Certain Relationships and Related
Transactions"). The Partnership is managed by or under the
direction of the Partnership Policy Committee consisting of
three members, each of whom has been appointed by one of
the General Partners (See "Partnership Management").
The Partnership's 70% interest in Northern Border Pipeline
represents substantially all its assets. Northern Border Pipeline
owns a 1,214-mile U.S. interstate pipeline system (the "Pipeline System")
that transports natural gas from the Montana-Saskatchewan border
near Port of Morgan, Montana, to interconnecting pipelines
and local distribution systems in the States of North
Dakota, South Dakota, Minnesota, Iowa and Illinois, providing
shippers access to markets in the Midwest, including
Chicago. The Pipeline System has pipeline access to natural
gas reserves in the Western Canadian Sedimentary Basin
located in the Canadian provinces of Alberta, British
Columbia and Saskatchewan, as well as the Williston Basin in
the United States. The Pipeline System also has access to
production of synthetic gas from the Dakota Gasification
Plant in North Dakota. Northern Border Pipeline shippers
can arrange transportation, displacement and exchange
agreements with third parties to provide access beyond
Chicago to markets throughout the United States.
Management of Northern Border Pipeline is overseen by
the Northern Border Management Committee, which is comprised
of three representatives from the Partnership (one
designated by each General Partner) and one representative
from the TransCanada subsidiaries. The Pipeline System is
operated by Northern Plains pursuant to an operating
agreement. Northern Plains employs approximately 190
individuals located at the operating headquarters in Omaha,
Nebraska, and at various locations along the pipeline route.
Northern Plains' employees are not represented by any labor
union and are not covered by any collective bargaining
agreements.
Northern Border Pipeline transports gas for shippers
under a tariff regulated by the Federal Energy Regulatory
Commission ("FERC"). The tariff specifies the calculation
of amounts to be paid by shippers and the general terms and
conditions of transportation service on the Pipeline System.
Northern Border Pipeline's revenues are derived from
agreements for the receipt and delivery of gas at points
along the Pipeline System as specified in each shipper's
individual transportation contract. Northern Border Pipeline
does not own the gas that it transports, and therefore it
does not assume the risk of loss from decreases in market
prices for gas transported on the Pipeline System.
The Partnership also owns Black Mesa Pipeline Holdings,
Inc. ("Black Mesa"). Black Mesa, through a wholly-owned
subsidiary, owns a 273-mile, 18-inch diameter coal slurry
pipeline which originates at a coal mine in Kayenta,
Arizona. The coal slurry pipeline transports crushed coal
suspended in water. It traverses westward through northern
Arizona to the 1,500 megawatt Mohave Power Station located
in Laughlin, Nevada. The coal slurry pipeline is the sole
source of fuel for the Mohave Power Station, which consumes
an average of 4.8 million tons of coal annually. The
capacity of the pipeline is fully contracted to the coal
supplier for the Mohave Power Station through the year 2005.
The pipeline is operated by Black Mesa Pipeline Operations,
LLC, a wholly-owned subsidiary of the Partnership.
Approximately 59 people are employed in the operations of
Black Mesa, of which 26 are represented by a labor union,
the United Mine Workers. The cash flow from the coal slurry
pipeline represents only about 2% of the Partnership's total
cash flow.
The Pipeline System
The Pipeline System consists of 822-miles of 42-inch
diameter pipe designed to transport 2,373 million cubic feet
of natural gas per day ("MMcfd") from the Canadian border to
Ventura, Iowa; 30-inch diameter pipe and 36-inch diameter
pipe, each approximately 147 miles in length, designed to
transport 1,300 MMcfd from Ventura, Iowa to Harper, Iowa;
and 226 miles of 36-inch diameter pipe and 19 miles of 30-
inch diameter pipe designed to transport 645 MMcfd from
Harper, Iowa to a terminus near Manhattan, Illinois (Chicago
area). Along the pipeline, there are fifteen compressor
stations with total rated horsepower of 476,500 and
measurement facilities to support the receipt and delivery
of gas at various points along the pipeline. Other
facilities include five field offices and a microwave
communication system with 51 tower sites.
Interconnecting pipeline facilities provide Northern
Border Pipeline shippers with flexible access to natural gas
markets. The Pipeline System interconnects with the
pipeline facilities of:
* Northern Natural Gas Company ("Northern Natural"), 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;
* Interstate 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 (Chicago area) at the terminus of the Pipeline
System.
At its northern end, the Pipeline System's largest
receipt point is its connection to the Foothills Pipe Lines
(Sask.) Ltd. system in Canada, which in turn is connected to
the pipeline systems of NOVA Gas Transmission Ltd. ("NOVA")
in Alberta and of Transgas Limited in Saskatchewan. The
NOVA system gathers and transports a substantial portion of
Canadian natural gas production. The Pipeline System also
connects with the facilities of Williston Basin Interstate
Pipeline at Glen Ullin and Buford, North Dakota, facilities
of Amerada Hess Corporation at Watford City, North Dakota
and facilities of Dakota Gasification Company at Hebron,
North Dakota in the northern portion of the system.
The Pipeline System was initially constructed in 1982
with capacity additions in 1991, 1992 and 1998. A recent
expansion, called The Chicago Project, was placed into
service in December 1998 and increased the Pipeline System's
capacity by 42% to its current capacity of 2,373 MMcfd. The
estimated cost of The Chicago Project is $892 million (See
"FERC Regulation - Cost of Service Tariff").
Future Demand and Competition
Northern Border Pipeline's operations are supported by
significant supplies of natural gas in Canada. In 1998,
approximately 88% of the natural gas transported by the
Pipeline System was produced in the Western Canadian
Sedimentary Basin. Northern Border Pipeline's capacity
utilization was an average of 99% of summer design capacity
during 1998. It is estimated that the Pipeline System's
share of Canadian gas exported to the United States in
January and February 1999, the first full two months of
operations of The Chicago Project, was nearly 23%.
On November 17, 1997, Northern Border Pipeline
announced the commencement of an open season during which
prospective shippers were invited to submit requests for
capacity on a possible further expansion and extension of
the Pipeline System ("Project 2000"). From the bids
submitted, project shippers signed precedent agreements for
additional capacity from Port of Morgan, Montana to Ventura,
Iowa of 62 MMcfd and from Ventura, Iowa to Manhattan, Illinois
of 185 MMcfd and new capacity to North Hayden, Indiana of
545 MMcfd. In October 1998, Northern Border Pipeline filed
a certificate application with the FERC to construct and
operate facilities necessary to transport these volumes with
construction costs estimated to be approximately $190 million.
If approved and constructed, Project 2000 will strategically
position Northern Border Pipeline to move gas east and will
place it in direct contact with major industrial gas comsumers.
Project 2000 would afford shippers access to the northern
Indiana industrial zone, including Northern Indiana Public
Service Company, a major Midwest local distribution company
with a large industrial load requirement and total annual
system deliveries in excess of 300 billion cubic feet.
A notice to prepare an environmental assessment for this
project was issued by the FERC on January 22, 1999 to all affected
landowners and other interested parties giving those parties
the opportunity to provide comments. Northern Border
Pipeline has been advised that permanent releases of
existing capacity have been negotiated between several existing
and project shippers. If such releases are finalized,
certain proposed facilities will not be needed, reducing the
estimated construction cost to approximately $130 million, and
an amendment of the certificate application will be filed
advising FERC of these changes.
Northern Border Pipeline competes with other pipeline
companies that transport gas from the Western Canadian
Sedimentary Basin or that transport gas to end-use markets
in the Midwest. Its competitive position is affected by the
availability of Canadian natural gas for export and demand
for natural gas in the United States. Shippers of gas
produced in the Western Canadian Sedimentary Basin have
other options to transport Canadian natural gas to the
United States, including transportation on pipelines
eastward in Canada or to markets on the West Coast.
The sponsors of the Alliance Pipeline project recently
received Canadian and United States regulatory approvals for
the construction of a new pipeline to originate in western
Canada and terminate in the vicinity of Chicago, Illinois.
These sponsors have announced their plans for the pipeline
to be in service by October 2000. The new pipeline would
directly compete with Northern Border Pipeline by
transporting gas from the Western Canadian Sedimentary Basin
to the midwestern United States. Although there may be a
large increase in natural gas moving from the Western
Canadian Sedimentary Basin into the Chicago market, there are
several additional projects proposed to transport natural gas
from the Chicago area to growing eastern markets. The proposed
projects, currently being pursued by unrelated third
parties, are targeting markets in eastern Canada and the
northeast United States. None of these proposed projects
has received final regulatory approval.
Shippers
The Pipeline System serves a number of shippers with
diverse financial and business profiles. Based on shippers'
cost of service obligations, 93% of the capacity is
contracted by producers and marketers. The remaining
capacity is contracted primarily by interstate pipelines
(2%) and local distribution companies (5%). At present, the
termination dates of these contracts range from October 31,
2001 to December 21, 2013. The weighted average contract
life as of December 31, 1998 (based upon shippers' cost of
service obligations) is slightly under eight years with 97%
of capacity contracted through mid-September 2003.
Firm shippers on the Pipeline System as of December 31,
1998 that are affiliated with general partners of the
Partnership or the general partners of Northern Border
Pipeline are: Enron Capital & Trade Resources Corp.("ECT"),
a subsidiary of Enron; TransCanada Gas Services Inc., a
subsidiary of, and as agent for, TransCanada; and
Transcontinental Gas Pipe Line Corporation ("Transco"), a
subsidiary of Williams. Together those shippers currently
hold 16.9% of capacity.
Northern Border Pipeline's largest shipper, Pan-Alberta
Gas U.S. Inc. ("PAGUS"), currently holds 707 MMcfd, 26.5% of
the capacity, under three transportation contracts with terms
that have been extended to October 31, 2003. The extension of
the termination date for one of the contracts covering 150
MMcfd is subject to further FERC authorization. An
affiliate of Enron provides guaranties for 300 MMcfd, of
PAGUS' contractual obligations through October 31, 2001. In
addition, PAGUS' remaining transportation 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 150
MMcfd, an escrow account and an upstream capacity transfer
agreement.
FERC Regulation
General
FERC extensively regulates Northern Border Pipeline as
a "natural gas company" under the Natural Gas Act (the
"NGA"). Under the NGA and the Natural Gas Policy Act,
the FERC has jurisdiction over Northern Border
Pipeline with respect to virtually all aspects of its
business, including transportation of 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, the initiation and
discontinuation of services, and certain other matters.
Northern Border Pipeline, where required, holds certificates
of public convenience and necessity issued by the FERC
covering its facilities, activities and services. Under
Section 8 of the NGA, the FERC has the power to prescribe
the accounting treatment for items for regulatory purposes.
The Northern Border Pipeline books and records are
periodically audited pursuant to Section 8.
Northern Border Pipeline's rates and charges for
transportation in interstate commerce are subject to
regulation by the FERC. Natural gas companies may not
charge rates exceeding rates deemed 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. Certain types of
rates may be discounted without further FERC authorization.
Cost of Service Tariff
Northern Border Pipeline's firm transportation shippers
contract to pay for an allocable share of the cost of
service associated with the Pipeline System's capacity.
During any given month, all such shippers pay 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 allocable share of the cost of
service regardless of the amount of gas they actually
transport. The cost of service tariff is regulated by the
FERC and provides an opportunity to recover all operations
and maintenance costs of the Pipeline System, taxes other
than income taxes, interest, depreciation and amortization,
an allowance for income taxes and a regulated equity return.
Northern Border Pipeline may not charge or collect more than
its cost of service pursuant to its tariff on file with the
FERC.
Northern Border Pipeline's investment in the Pipeline
System is reflected in various accounts referred to
collectively as its 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, the monthly depreciation and
amortization. The Northern Border Pipeline rate base
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 ("IROR"), has been amortized through monthly
additions to the cost of service. As a result, the Partnership's
net income for 1998 included $9.9 million for such amortization
along with a related income tax allowance, net of the effect of
minority interests. This impact on net income is expected
to continue until November 2001 when the IROR is fully
amortized.
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 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' accounts.
Northern Border Pipeline also provides interruptible
transportation service. The maximum rate charged to
interruptible shippers is calculated from cost of service
estimates on the basis of contracted capacity. Except for
certain limited situations, all revenue from the
interruptible transportation service is credited back to the
firm shippers' accounts.
In its 1995 rate case, Northern Border Pipeline reached
a settlement that was filed in a Stipulation and Agreement
("Stipulation"). Although it was contested, it was approved
by the FERC on August 1, 1997. In the Stipulation, 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 Stipulation also determined several other cost of
service parameters. In accordance with the effective
tariff, Northern Border Pipeline's allowed equity rate of
return is 12%. For at least seven years from the date The
Chicago Project was completed, Northern Border Pipeline,
under the terms of the Stipulation, may continue to
calculate its allowance for income taxes as a part of its
cost of service in the manner it has 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 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. 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
Northern Border Pipeline's 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, that amount will be allocated 50% to Northern
Border Pipeline and 50% to its shippers (50% of the
difference between 5% of the budgeted cost and $6 million
will be included in Northern Border Pipeline's rate base,
and 50% will be excluded). All cost overruns exceeding 5%
of the budgeted cost are excluded from the rate base.
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 has been
estimated as of the December 22, 1998 in-service date to be
$889 million, with the final construction cost estimated to be
$892 million. Thus, Northern Border Pipeline's report to the FERC
and its shippers in late December 1998, reflected the
conclusion that, based on information as of that date, once
the budgeted cost has been established, there would be no
adjustment to rate base as a result of the PCCM. Northern
Border Pipeline is obligated by the Stipulation to update
its calculation of the PCCM six months after the in-service
date of The Chicago Project. The Stipulation requires the
calculation of the PCCM to be reviewed by an independent
national accounting firm. Several parties to the
Stipulation have advised the FERC that they may have
questions and desire further information about the report,
and may possibly wish to test it (or the final report) and
the conclusions contained therein in an appropriate
proceeding in the future. The parties also stated that if
it is determined that Northern Border Pipeline is not able
to include certain claimed costs for The Chicago Project in
its rate base, they reserve their rights to seek refunds,
with interest, of any overcollections. Although the
Partnership believes the initial computation has been made
pursuant to the terms of the Stipulation, it is unable to
make a definitive determination at this time whether any
adjustments will be required. Should subsequent
developments cause costs not to be recovered pursuant to the
PCCM, a non-cash charge to write down transmission plant may
result, and such charge could be material to the operating
results of the Partnership.
Northern Border Pipeline is required by the terms of its
tariff to file a rate case with the FERC by no later than
May 31, 1999 for a redetermination of its allowed equity
rate of return. The Partnership cannot predict the impact,
if any, of the outcome of the next rate case.
Proposed Regulations
In a Notice of Proposed Rulemaking ("NOPR") issued on
July 29, 1998, the FERC proposed changes to its regulations
governing short-term transportation services. Among the
proposals considered in the NOPR are:
* Auctions for short-term capacity;
* Removal of price caps for secondary market
transactions;
* Revisions to FERC's reporting requirements;
* Revisions to tariff provisions governing imbalances;
and
* Negotiated services.
In a companion Notice of Inquiry issued the same day,
the FERC requested industry comment on its pricing policies
in the existing long-term market for transportation services
and its pricing policies for new capacity. The FERC also
issued a NOPR to revise its procedures under which shippers
or others may have complaints considered by the FERC. The
Partnership cannot assess the impact on Northern Border
Pipeline of any final rules adopted by the FERC as a result
of these proceedings at this time.
The FERC also commenced proceedings to revise its
pipeline construction regulations. On September 30, 1998,
the FERC issued a NOPR to amend its regulations to reflect
current FERC policies governing the issuance of pipeline
construction certificates and to codify the filing of
certain related information. Also on September 30, 1998,
the FERC issued a NOPR that would give applicants seeking to
construct, operate or abandon natural gas services or
facilities the option of using a pre-filing collaborative
process to resolve significant issues among parties and the
pipeline. The NOPR also proposes that a significant portion
of the environmental review process could be completed as
part of the collaborative process. As part of the NOPR, the
FERC intends to examine existing landowner and pipeline
construction issues. The Partnership cannot assess the
impact on Northern Border Pipeline of any final rules
adopted by the FERC as a result of these proceedings at this
time.
Environmental and Safety Matters
The operations of the Partnership are subject to
federal, state and local laws and regulations relating to
safety and the protection of the environment which include
the Resource Conservation and Recovery Act, the
Comprehensive Environmental Response, Compensation and
Liability Act of 1980, as amended, Clean Air Act, as
amended, the Clean Water Act, as amended, the Natural Gas
Pipeline Safety Act of 1969, as amended, and the Pipeline
Safety Act of 1992. Although the Partnership believes that
its operations and facilities are in general compliance in
all material respects with applicable environmental and
safety regulations, risks of substantial costs and
liabilities are inherent in pipeline operations, and the
Partnership cannot provide any assurances that it will not
incur such costs and liabilities. Moreover, it is possible
that other developments, such as increasingly strict
environmental and safety laws, regulations and enforcement
policies thereunder, and claims for damages to property or
persons resulting from the Partnership's operations, could
result in substantial costs and liabilities to the Partnership.
If the Partnership is unable to recover such resulting costs,
cash distributions could be adversely affected.
Item 2. Properties
Northern Border Pipeline holds the right, title and
interest in the Pipeline System. With respect to real
property, the Pipeline System falls into two basic
categories: (a) parcels which Northern Border Pipeline owns
in fee, such as certain of the compressor stations,
measurement stations, pipeline field office sites, and
microwave tower sites; and (b) parcels where the interest of
Northern Border Pipeline derives from leases, easements,
rights-of-way, permits or licenses from landowners or
governmental authorities permitting the use of such land for
the construction and operation of the Pipeline System. The
right to construct and operate the pipeline across certain
property was obtained by Northern Border Pipeline through
exercise of the power of eminent domain. Northern Border
Pipeline continues to have the power of eminent domain in
each of the states in which it operates the Pipeline System,
although it may not have the power of eminent domain with
respect to Native American tribal lands.
Approximately 90 miles of the pipeline is located on
fee, allotted and tribal lands within the exterior
boundaries of the Fort Peck Indian Reservation in Montana.
Tribal lands are lands owned in trust by the United States
for the Fort Peck Tribes and allotted lands are lands owned
in trust by the United States for an individual Indian or
Indians. In 1980, Northern Border Pipeline entered into a
pipeline right-of-way lease with the Fort Peck Tribal
Executive Board, for and on behalf of the Assiniboine and
Sioux Tribes of the Fort Peck Indian Reservation. This
pipeline right-of-way lease, which was approved by the
Department of the Interior in 1981, granted to Northern
Border Pipeline the right and privilege to construct and
operate its pipeline on certain tribal lands, for a term of
15 years, renewable for an additional 15 year term at the
option of Northern Border Pipeline without additional
rental. Northern Border Pipeline notified the Bureau of
Indian Affairs ("BIA") in March 1996 that it was exercising
its option to renew the pipeline right-of-way lease for an
additional 15 year term. Northern Border Pipeline continues
to operate on this portion of the pipeline located on tribal
lands in accordance with its renewal rights.
In conjunction with obtaining a pipeline right-of-way
lease across tribal lands located within the exterior
boundaries of the Fort Peck Indian Reservation, Northern
Border Pipeline also obtained a right-of-way across allotted
lands located within the reservation boundaries. This right-
of-way, granted by the BIA on March 25, 1981, for and on
behalf of individual Indian owners, expired on March 31,
1996. Before the termination date, Northern Border Pipeline
undertook efforts to obtain voluntary consents from
individual Indian owners for a new right-of-way, and
Northern Border Pipeline filed applications with the BIA for
new right-of-way grants across those tracts of allotted
lands where a sufficient number of consents from the Indian
owners had been obtained. 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 in this
proceeding was issued by the Federal Court granting Northern
Border Pipeline continued access and possession during the
pendency of the condemnation action on the tracts in
question. A stipulation has been entered into involving all
but one tract involved in the condemnation action in which
the parties have agreed that the Court may enter an order
assessing compensation in the amount established in an
agreed upon appraisal. A hearing was held by the Court in
January 1999 in which evidence was presented on the value of
the interest being condemned. No order has been entered as
yet. Amounts ordered by the Court as compensation should be
included in Northern Border Pipeline's cost of service. To
date the BIA has not issued a formal right-of-way grant for
those tracts for which sufficient landowners consents were
obtained. It is anticipated that the issuance of such a
grant will take place in conjunction with the resolution of
the condemnation action.
Item 3. Litigation
The Partnership and its subsidiaries are not currently
parties to any legal proceedings that, individually or in
the aggregate, would reasonably be expected to have a
material adverse impact on the Partnership's results of
operations or financial position.
Item 4. Submission of Matters to a Vote of Security Holders
There were no matters submitted to a vote of security
holders during 1998.
<PAGE>
PART II
Item 5. Market for the Registrant's Common Units
and Related Security Holder Matters
The following table sets forth, for the periods
indicated, the high and low sale prices per Common Unit, as
reported on the New York Stock Exchange Composite Tape, and
the amount of cash distributions per Common Unit declared
for each quarter:
<TABLE>
<CAPTION>
Price Range Cash
High Low Distributions
<S> <C> <C> <C>
1998
First Quarter $34.3125 $32.50 $0.575
Second Quarter 35.00 31.8125 0.575
Third Quarter 34.75 31.125 0.575
Fourth Quarter 36.125 32.50 0.61
1997
First Quarter $29.125 $26.125 $0.55
Second Quarter 29.375 26.875 0.55
Third Quarter 33.25 28.50 0.55
Fourth Quarter 35.00 32.063 0.575
</TABLE>
As of March 5, 1999, there were approximately 1,656
record holders of Common Units and approximately 34,538
beneficial owners of the Common Units, including Common
Units held in street name.
The Partnership currently has 29,347,313 Common Units
outstanding, representing a 98% limited partner interest.
The Common Units are the only outstanding limited partner
interests. Thus, the Partnership's equity consists of
general partner interests representing in the aggregate a 2%
interest and Common Units representing in the aggregate a
98% limited partner interest.
In general, the General Partners are entitled to 2% of
all cash distributions, and the holders of Common Units are
entitled to the remaining 98% of all cash distributions,
except that the General Partners are entitled to incentive
distributions if the amount distributed with respect to any
quarter exceeds $0.605 per Common Unit ($2.42 annualized).
Under the incentive distribution provisions, the General
Partners are entitled to 15% of amounts distributed in
excess of $0.605 per Common Unit, 25% of amounts distributed
in excess of $0.715 per Common Unit ($2.86 annualized) and
50% of amounts distributed in excess of $0.935 per Common
Unit ($3.74 annualized). The amounts that trigger incentive
distributions at various levels are subject to adjustment in
certain events, as described in the Partnership Agreement.
On January 19, 1999, the Partnership declared an increase in
the distribution to $0.61 per Unit ($2.44 per Unit on an
annualized basis), payable February 12, 1999 to the General
Partners and Unitholders of record at January 29, 1999.
On May 31, 1997, the Partnership issued 125,357 Common
Units in a private placement, exempt pursuant to Section
4(2) of the Securities Act of 1933, to the stockholders of
Williams Technologies, Inc., an Oklahoma corporation
("WTI"), in consideration of the sale by such stockholders
to the Partnership of all of the capital stock of WTI.
On December 29, 1997, the Partnership issued 46,956
Common Units in a private placement, exempt pursuant to
Section 4(2) of the Securities Act of 1933, to Central
Pacific Resources Partnership as partial consideration for
the acquisition by the Partnership of an interest in Black
Mesa Pipeline Operations, LLC.
On January 19, 1999, the 6,420,000 Subordinated Units
outstanding were converted into 6,420,000 Common Units in
accordance with their terms in a transaction that was exempt
from registration pursuant to Section 3(a)(9) of the
Securities Act of 1933.
<PAGE>
<TABLE>
Item 6. Selected Financial Data
(in thousands, except per Unit and operating data)
<CAPTION>
Year Ended December 31,
1998 1997 1996 1995 1994
<S> <C> <C> <C> <C> <C>
INCOME DATA:
Operating revenue $ 217,592 $ 198,574 $ 201,943 $ 206,497 $ 211,580
Operations and maintenance 44,770 37,418 28,366 26,730 28,919
Depreciation and amortization 43,536 40,172 46,979 47,081 41,959
Taxes other than income 22,012 22,836 24,390 23,886 24,438
Regulatory credit (8,878) -- -- -- --
Operating income 116,152 98,148 102,208 108,800 116,264
Interest expense, net 30,922 30,860 32,670 35,106 38,375
Other income (expense) 12,859 7,989 2,900 469 (1,389)
Minority interests
in net income 30,069 22,253 22,153 22,360 23,147
Net income to partners $ 68,020 $ 53,024 $ 50,285 $ 51,803 $ 53,353
Net income per Unit $ 2.27 $ 1.97 $ 1.88 $ 1.94 $ 2.00
Number of units used
in computation 29,345 26,392 26,200 26,200 26,200
CASH FLOW DATA:
Net cash provided by
operating activities $ 103,849 $ 119,621 $ 137,534 $ 127,078 $ 121,088
Capital expenditures 652,194 152,658 18,597 8,411 2,985
Distribution per Unit 2.30 2.20 2.20 2.20 2.20
BALANCE SHEET DATA
(AT END OF PERIOD):
Net property, plant
and equipment $1,730,476 $1,118,364 $ 937,859 $ 957,587 $ 983,842
Total assets 1,825,766 1,266,917 1,016,484 1,041,339 1,083,468
Long-term debt, including
current maturities 976,832 481,355 377,500 410,000 445,000
Minority interests in
partners' capital 253,031 174,424 158,089 166,789 173,984
Partners' capital 507,426 500,728 410,586 419,117 426,130
OPERATING DATA (unaudited):
Northern Border Pipeline:
Million cubic feet
of gas delivered 619,669 633,280 633,908 615,133 597,898
Average daily throughput (MMcfd) 1,737 1,770 1,764 1,720 1,663
</TABLE>
<PAGE>
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations
Results of Operations
Year Ended December 31, 1998 Compared With the Year Ended December 31, 1997
Operating revenue increased $19.0 million for the year ended
December 31, 1998, as compared to the results for the comparable
period in 1997. Operating revenue attributable to Northern
Border Pipeline increased $10.5 million due primarily to returns
on higher levels of invested equity. Northern Border Pipeline's
FERC tariff provides an opportunity to recover all of the
operations and maintenance costs of the pipeline, taxes other
than income taxes, interest, depreciation and amortization, an
allowance for income taxes and a regulated return on equity.
Northern Border Pipeline is generally allowed to collect from its
shippers a return on unrecovered rate base as well as recover
that rate base through depreciation and amortization. The return
amount Northern Border Pipeline collects from its shippers
declines as the rate base is recovered. As a result of placing
the facilities for The Chicago Project into service, Northern
Border Pipeline added approximately $840 million to its gas plant
in service in 1998 (See "Business-The Pipeline System").
Operating revenue for Black Mesa was $21.0 million in 1998 as
compared to $12.5 million in 1997, which represented seven months
of revenue. On May 31, 1997, the Partnership increased its
ownership interest of Black Mesa and began to reflect its
operating results on a consolidated basis. Prior to that time,
Black Mesa was accounted for on the equity method and included in
other income.
Operations and maintenance expense increased $7.4 million for
the year ended December 31, 1998, from the comparable period in
1997. Operations and maintenance expense for Black Mesa was
$13.8 million in 1998 as compared to $7.7 million in 1997, which
represented seven months of expense.
Depreciation and amortization expense increased $3.4 million
for the year ended December 31, 1998, as compared to the same
period in 1997. Depreciation and amortization expense
attributable to Northern Border Pipeline increased $2.3 million
primarily due to facilities that were placed in service in 1998.
Depreciation and amortization expense for Black Mesa was $2.6
million in 1998 as compared to $1.5 million in 1997, which
represented seven months of expense.
For the year ended December 31, 1998, Northern Border Pipeline
recorded a regulatory credit of approximately $8.9 million.
During the construction of The Chicago Project, Northern Border
Pipeline placed certain new facilities into service in advance of
the December 1998 in service date to maintain gas flow at firm
contracted capacity while existing facilities were being
modified. The regulatory credit results in deferral of the cost
of service of these new facilities. Northern Border Pipeline is
allowed to recover from its shippers the regulatory asset that
resulted from the cost of service deferral over a ten-year period
commencing with the in service date of The Chicago Project.
Interest expense, net increased slightly for the year ended
December 31, 1998, as compared to the results for the same period
in 1997, due to an increase in interest expense of $15.4 million
offset by an increase in the amount of interest expense
capitalized of $15.3 million. Interest expense attributable to
Northern Border Pipeline and the Partnership increased $14.6
million due primarily to an increase in average debt outstanding,
reflecting amounts borrowed to finance a portion of the capital
expenditures for The Chicago Project. The remainder of the
increase in interest expense is from Black Mesa, which was $2.3
million for 1998 as compared to $1.5 million for seven months in
1997. The increase in interest expense capitalized primarily
relates to Northern Border Pipeline's expenditures for The
Chicago Project.
Other income increased $4.9 million for the year ended
December 31, 1998, as compared to the same period in 1997. The
increase was primarily due to an $8.8 million increase in the
allowance for equity funds used during construction. The
increase in the allowance for equity funds used during
construction primarily relates to Northern Border Pipeline's
expenditures for The Chicago Project. Other income for 1997
included $4.8 million received by Northern Border Pipeline for
vacating certain microwave frequency bands.
Minority interests in net income increased $7.8 million for
the year ended December 31, 1998, as compared to the same period
in 1997, due to increased net income for Northern Border
Pipeline.
Year Ended December 31, 1997 Compared With the Year Ended
December 31, 1996
Operating revenue decreased $3.4 million for the year ended
December 31, 1997, as compared to the results for the comparable
period in 1996. Operating revenue attributable to Northern
Border Pipeline decreased $15.9 million due primarily to lower
depreciation and amortization expense, taxes other than income
and returns on a lower rate base. Additionally, in accordance
with the Stipulation approved by the FERC to settle Northern
Border Pipeline's November 1995 rate case, the allowed equity
rate of return was 12.75% through September 30, 1996 and 12.0%
thereafter (See "Business-FERC Regulation-Cost of Service
Tariff"). These lower recoveries were partially offset by higher
operations and maintenance expense recoveries. Operating revenue
for Black Mesa was $12.5 million for 1997.
Operations and maintenance expense increased $9.1 million for
the year ended December 31, 1997, from the comparable period in
1996 due primarily to $7.7 million of expense for Black Mesa.
Operations and maintenance expense attributable to Northern
Border Pipeline increased $1.5 million for the year ended
December 31, 1997, from the comparable period in 1996 due
primarily to higher administrative expenses.
Depreciation and amortization expense decreased $6.8 million
for the year ended December 31, 1997, as compared to the same
period in 1996. Depreciation and amortization expense
attributable to Northern Border Pipeline decreased $8.3 million.
In accordance with the terms of the Stipulation, the depreciation
rate applied to Northern Border Pipeline's gross transmission
plant was 2.5% for 1997. The average depreciation rate applied
to gross transmission plant for the year ended December 31, 1996
was 3.1%. Depreciation and amortization expense for Black Mesa
was $1.5 million for 1997.
Taxes other than income decreased $1.6 million for the year
ended December 31, 1997, as compared to the results for the same
period in 1996. Taxes other than income attributable to Northern
Border Pipeline decreased $2.0 million due primarily to lower
property tax assessments received in various states where the
pipeline system operates. Taxes other than income for Black Mesa
was $0.4 million for 1997.
Interest expense, net decreased $1.8 million for the year
ended December 31, 1997, as compared to the results for the same
period in 1996, due to an increase in interest expense of $1.4
million offset by an increase in the amount of interest expense
capitalized of $3.2 million. The increase in interest expense
was due primarily to Black Mesa. The increase in interest
expense capitalized primarily relates to Northern Border
Pipeline's expenditures for The Chicago Project.
Other income increased $5.1 million for the year ended
December 31, 1997, as compared to the same period in 1996. The
increase was primarily due to $4.8 million received by Northern
Border Pipeline for vacating certain microwave frequency bands
and a $1.0 million increase in the allowance for equity funds
used during construction. The increase in the allowance for
equity funds used during construction primarily relates to
Northern Border Pipeline's expenditures for The Chicago Project.
Liquidity and Capital Resources
General
In June 1997, Northern Border Pipeline entered into a credit
agreement ("Pipeline Credit Agreement") with certain financial
institutions to borrow up to an aggregate principal amount of
$750 million. The Pipeline Credit Agreement is comprised of a
$200 million five-year revolving credit facility to be used for
the retirement of Northern Border Pipeline's bank loan agreements
and for general business purposes, and a $550 million three-year
revolving credit facility to be used for the construction of The
Chicago Project. The three-year revolving credit facility may,
if certain conditions are met, be converted to a term loan
maturing in June 2002. Northern Border Pipeline intends to, and
has the ability to, convert the three-year revolving credit
facility to a term loan in 1999. At December 31, 1998, $127.5
million and $484.5 million had been borrowed on the five-year and
three-year revolving credit facilities, respectively.
In November 1997, the Partnership entered into a credit
agreement ("Partnership Credit Agreement") with certain financial
institutions to borrow up to an aggregate principal amount of
$175 million under a revolving credit facility. The Partnership
Credit Agreement is to be used for interim funding of the
Partnership's required capital contributions to Northern Border
Pipeline for construction of The Chicago Project. The amount
available under the Partnership Credit Agreement is reduced to
the extent the Partnership issues additional limited partner
interests to fund the Partnership's capital contributions for The
Chicago Project in excess of $25 million. The public offerings
of Common Units discussed in the following paragraph reduced the
amount available under the Partnership Credit Agreement to $104
million. The maturity date of the Partnership Credit Agreement
will be November 2000 if Northern Border Pipeline converts its
$550 million three-year revolving credit facility to a term loan;
otherwise the maturity date is June 2000. At December 31, 1998,
$95 million had been borrowed on the Partnership Credit
Agreement.
In December 1997, the Partnership sold, through an
underwritten public offering, 2,750,000 Common Units. In
conjunction with the issuance of the Common Units, the
Partnership's General Partners made capital contributions to the
Partnership to maintain a 2% general partner interest in
accordance with the partnership agreements. The net proceeds of
approximately $90.9 million were used by the Partnership to fund
a portion of the capital contributions to Northern Border
Pipeline for construction of The Chicago Project. As part of the
underwritten public offering, the Partnership granted the
underwriters an over-allotment option to purchase a limited
number of additional Common Units. This option was exercised on
January 5, 1998, and the Partnership sold an additional 225,000
Common Units resulting in additional net proceeds, including the
general partners' capital contributions, of approximately $7.6
million.
In September 1998, Northern Border Pipeline executed interest
rate forward agreements with an aggregate notional amount of $150
million to hedge the interest rate for a planned issuance of
fixed rate debt during 1999. Northern Border Pipeline plans to
use the proceeds from the debt borrowing to repay amounts
borrowed on the Pipeline Credit Agreement.
In February 1999, the Partnership filed two registration
statements with the Securities and Exchange Commission ("SEC").
One registration statement was for a proposed offering of $200
million in Common Units and debt securities to be used by the
Partnership for general business purposes including repayment of
debt, future acquisitions, capital expenditures and working
capital. The other registration statement was for a proposed
offering of 3,210,000 Common Units that are presently owned by
Northwest Border, a General Partner, and Panhandle Eastern Pipe
Line Company, of which the Partnership will not receive any
proceeds.
Short-term liquidity needs will be met by internal sources and
through the lines of credit discussed above. Long-term capital
needs may be met through the ability to issue long-term
indebtedness as well as additional limited partner interests of
the Partnership either through the registration statements
previously discussed or separate registrations.
Cash Flows From Operating Activities
Cash flows provided by operating activities decreased $15.8
million to $103.8 million for the year ended December 31, 1998 as
compared to the same period in 1997 primarily related to a $36.3
million reduction for changes in other current assets and
liabilities partially offset by the effect of the refund activity
in 1997 discussed below. For the year ended December 31, 1998,
the changes in other current assets and liabilities reflected a
decrease in accounts payable of $11.8 million as compared to an
increase of $14.6 million in 1997, exclusive of accruals for The
Chicago Project. In addition, the changes in other current
assets and liabilities for 1998 reflected a decrease in over
recovered cost of service of $4.6 million and an increase in
under recovered cost of service of $2.8 million. The over/under
recovered cost of service is the difference between Northern
Border Pipeline's estimated billings to its shippers, which are
determined on a six-month cycle, and the actual cost of service
determined in accordance with the FERC tariff. The difference is
either billed to or credited back to the shippers accounts. Cash
flows provided by operating activities decreased $17.9 million to
$119.6 million for the year ended December 31, 1997 as compared
to the same period in 1996 primarily related to a $52.6 million
refund in October 1997 in accordance with the Stipulation
approved by the FERC to settle Northern Border Pipeline's
November 1995 rate case. During 1997, $40.4 million had been
collected subject to refund by Northern Border Pipeline as a
result of its rate case.
Cash Flows From Investing Activities
Capital expenditures of $652.2 million for the year ended
December 31, 1998, include $638.7 million for The Chicago
Project (See "Business-The Pipeline System") and $11.7 million
for linepack gas. The remaining $1.8 million of capital
expenditures for 1998 is primarily related to renewals and
replacements of existing facilities. For the comparable period
in 1997, capital expenditures were $152.7 million, which
included $135.7 million for The Chicago Project and $17.0
million primarily related to renewals and replacements of
Northern Border Pipeline's existing facilities.
Total capital expenditures for 1999 are estimated to be $131
million including $30 million for Project 2000 (see "Business-
Future Demand and Competition") and $85 million for The Chicago
Project. Approximately $37 million of the capital expenditures
for The Chicago Project is for construction completed in 1998.
An additional $16 million of 1999 capital expenditures is
planned for renewals and replacements of the existing
facilities. Northern Border Pipeline anticipates funding
its 1999 capital expenditures primarily by borrowing
on the Pipeline Credit Agreement and using working capital.
Funds required to meet the remainder of Northern Border
Pipeline's capital expenditures will be provided primarily
from capital contributions from the Partnership and minority
interest holders. The Partnership intends to use a combination
of proceeds from the sale of Common Units, capital contributions
from its general partners and borrowings on the Partnership Credit
Agreement to finance its capital contributions to Northern Border
Pipeline. The Partnership anticipates selling additional Common
Units to repay amounts borrowed on the Partnership Credit Agreement
to finance capital contributions for The Chicago Project.
Cash flows provided by acquisition and consolidation of
businesses of $3.4 million for the year ended December 31, 1997,
are related primarily to the consolidation of Black Mesa's cash
balance.
Cash Flows From Financing Activities
Cash flows provided by financing activities increased $387.0
million to $482.6 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 and
Partnership Credit Agreement totaling $498.0 million and were
used primarily for construction expenditures related to The
Chicago Project. In 1997, borrowings under the Pipeline Credit
Agreement totaled $209 million and were used primarily to retire
amounts related to Northern Border Pipeline's existing bank loan
agreements of $137.5 million and for construction expenditures
related to The Chicago Project. Financing activities for 1998
reflect $7.6 million in net proceeds from the issuance of 225,000
Common Units and a related capital contribution by the
Partnership's general partners in January 1998. In 1997,
financing activities reflect $90.9 million in net proceeds from
the issuance of 2,750,000 Common Units and a related capital
contribution by the Partnership's general partners in December
1997. Contributions received from minority interests increased
$42.6 million to $66.9 million and were used by Northern Border
Pipeline to fund a portion of its capital expenditures.
Distributions to minority interests decreased $11.7 million to
$18.4 million primarily due to a change in the timing of Northern
Border Pipeline's distributions.
Year 2000
The Partnership and its subsidiaries, similar to most
businesses, 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, but, in addition, a great deal
of information processing technology is embedded in
microelectronic devices. The Year 2000 problem results 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. If not
corrected, many computer applications could fail or create
erroneous results. The effects of the Year 2000 problem are
compounded because of the interdependence of computer and
telecommunication systems in the United States and throughout the
world. This interdependence is true for the Partnership, its
subsidiaries and their respective suppliers and customers.
The Partnership and its subsidiaries have developed a plan,
which will be modified as events warrant, to address Year 2000
problems (the "Plan"). The Plan is designed to take reasonable
steps to prevent mission-critical functions from being impaired
due to the Year 2000 problem. "Mission-critical" functions are
those critical functions whose loss would cause an immediate
stoppage of or significant impairment to major business areas (a
major business area is one of material importance to the
Partnership's and its subsidiaries' businesses). The Partnership
and its subsidiaries are committed to allocating the resources
necessary to implement the Plan. A core team of individuals has
been established to implement and complete the Plan (the "Y2K
Team"). The Plan includes developing a comprehensive component
inventory of computer hardware, software, embedded chips and
third-party interfaces; assessing the risk of non-compliance of
each component; identifying the impact of any component failure;
assessing Year 2000 compliance of each component; identifying and
implementing solutions for non-compliance of components; testing
of solutions implemented; and developing contingency plans for
mission-critical components and systems. As of February 1999,
computer software, hardware, embedded chips, and third-party
interfaces have been identified, inventoried, and assessed.
Where necessary, remediation, replacement, or adequate work-
arounds have been identified and implemented or are in the
process of being implemented. Testing of computer hardware,
software, and embedded systems is ongoing and is expected to be
substantially completed early in the second quarter of 1999.
The Plan recognizes that the computer, telecommunications and
other systems ("Outside Systems") of outside entities ("Outside
Entities") have the potential for major, mission-critical,
adverse effects on the conduct of the Partnership's and its
subsidiaries' businesses. The Partnership and its subsidiaries
do not have control of these Outside Systems. However, the Plan
includes an ongoing process of identifying and contacting Outside
Entities whose systems have or may have a substantial effect on
the Partnership's and its subsidiaries' ability to continue to
conduct the mission-critical aspects of their businesses without
disruption from Year 2000 problems. The Plan requires the
Partnership and its subsidiaries to attempt to inventory and
assess the extent to which these Outside Systems may not be Year
2000 compatible. The Y2K Team will attempt reasonably to
coordinate with these Outside Entities in an ongoing effort to
obtain assurances these Outside Systems will be Year 2000
compatible well before January 1, 2000.
A listing of critical Outside Entities has been developed
which includes shippers, electrical suppliers, and
interconnecting pipelines. Currently, the Y2K team is in the
process of contacting these entities to determine their Year 2000
readiness and the extent to which joint testing or mutual
contingency planning is required. The assessment of the Year
2000 readiness of Outside Entities is an important factor in the
internal contingency planning process.
The processes of inventorying, assessing, analyzing,
remediating through replacement or adequate work-arounds,
testing, and developing contingency plans for mission-critical
functions in anticipation of the year 2000 are necessarily
iterative processes. That is, the steps are repeated as the Y2K
Team learns more about the Year 2000 problem and its effects on
internal systems and on Outside Systems, and about the effects
that embedded chips may have on the Partnership's and its
subsidiaries' systems and Outside Systems. As the steps are
repeated, it is likely that new problems will be identified and
addressed. The Partnership and its subsidiaries anticipate that
they will continue with these processes through January 1, 2000
and, if necessary based on experience, into the year 2000 in
order to assess and remediate problems that reasonably can be
identified only after the start of the new century.
As part of the implementation of the Plan, the Y2K Team has
developed a contingency plan to minimize the consequences of
potential problems that have not been identified or that cannot
be remediated before January 1, 2000. The contingency plan
concentrates on those areas that are essential to continuing
business operations and/or safety of its personnel and the
public. These areas include, but are not limited to, systems
that are used to operate and control the Pipeline System and
enable the physical transportation of natural gas. The
contingency plan includes the creation of teams that will be
standing by on December 31, 1999, prepared to respond rapidly and
otherwise as necessary to mission-critical Year 2000-related
problems as soon as they become known. The composition of teams
that are assigned to deal with Year 2000 problems will vary
according to the mission-critical nature and location of the
problem. The contingency plan is dynamic and will be continually
revised as potential new problem areas are identified and areas
are remediated.
The Partnership and its subsidiaries have not incurred
material historical costs associated with the Year 2000 issues.
Further, the Partnership and its subsidiaries anticipate that
their future costs of implementing the Plan will not be material.
Although management believes its estimates are reasonable, there
can be no assurance, for the reasons stated in the following
paragraph, that the actual costs of implementing the Plan will
not differ materially from the estimated costs or that the
Partnership and its subsidiaries will not be adversely affected
by Year 2000 issues.
The extent and magnitude of the Year 2000 problem as it may
affect the Partnership and its subsidiaries, both before and for
some period after January 1, 2000, are difficult to predict or
quantify for a number of reasons. Among the most important is
the potential complexity of locating embedded microprocessors
that may be in a great variety of hardware used for process or
flow control, environmental, transportation, access,
communications and other systems. The Partnership and its
subsidiaries believe that they will be able to identify and
remediate mission-critical systems containing embedded
microprocessors or will have contingency plans to deal with these
systems. Other important difficulties relate to the lack of
control over and difficulty inventorying, assessing, remediating,
verifying and testing Outside Systems; the complexity of
evaluating all software (computer code) internal to the
Partnership and its subsidiaries that may not be Year 2000
compatible; and the potential limited availability of certain
necessary internal or external resources, including but not
limited to trained hardware and software engineers, technicians
and other personnel to perform adequate remediation, verification
and testing of internal systems or Outside Systems. Year 2000
costs are difficult to estimate accurately because of
unanticipated vendor delays, technical difficulties, the impact
of tests of Outside Systems, and similar events. There can be no
assurance for example that all Outside Systems will be adequately
remediated so that they are Year 2000 ready by January 1, 2000,
or by some earlier date, so as not to create a material
disruption to business. If, despite diligent, prudent efforts
under the Plan, there are Year 2000-related failures that create
substantial disruptions to the Partnership and its subsidiaries'
businesses, the adverse impact could be material. Moreover, the
estimated costs of pursuing the current course of action do not
take into account the costs, if any, that might be incurred as a
result of Year 2000-related failures that occur despite
implementation of the Plan, as it may be modified over time.
In a recent SEC release regarding Year 2000 disclosures,
the SEC stated that public companies must disclose the most
reasonably likely worst case Year 2000 scenario. Analysis
of the most reasonably likely worst case Year 2000 scenarios
the Partnership may face leads to contemplation of the
following possibilities: widespread failure of electrical,
gas, and similar supplies by utilities serving the
Partnership; widespread disruption of the services of
communications common carriers; similar disruption to means
and modes of transportation for the Partnership and its
employees, contractors, suppliers, and customers;
significant disruption to the Partnership's ability to gain
access to, and remain working in, office buildings and other
facilities; the failure of substantial numbers of the
Partnership's mission-critical information (computer)
hardware and software systems, including both internal
business systems and systems (such as those with embedded
chips) controlling operational facilities such as electrical
generation, transmission, and distribution systems; and the
failure of Outside Systems, the effects of which would have
a cumulative material adverse impact on the Partnership's
mission-critical systems. Among other things, the
Partnership could face substantial claims due to service
interruptions, inability to fulfill contractual obligations,
inability to account for certain revenues or obligations or
to bill shippers accurately and on a timely basis, and
increased expenses associated with litigation, stabilization
of operations following mission-critical failures, and the
execution of contingency plans. The Partnership could also
experience an inability by shippers to pay, on a timely
basis or at all, obligations owed to the Partnership. Under
these circumstances, the adverse effect on the Partnership,
and the diminution of the Partnership's revenues, would be
material, although not quantifiable at this time. The
Partnership will continue to monitor business conditions
with the aim of assessing and quantifying material adverse
effects, if any, that result or may result from the
Year 2000 problem.
Information Regarding Forward Looking Statements
Statements in this Annual Report that are not historical
information are forward looking statements within the meaning of
Section 27A of the Securities Act of 1933 and Section 21E of the
Securities Exchange Act of 1934. Such forward looking statements
include the discussions under "Business-Future Demand and
Competition" and elsewhere regarding Northern Border Pipeline's
efforts to pursue opportunities to further increase its capacity,
the discussion under "Business-Shippers" regarding potential
contract extensions, the discussion under "Business-FERC
Regulation-Cost of Service Tariff" regarding a project cost
containment mechanism related to The Chicago Project and the
discussion in "Management's Discussion and Analysis of Financial
Condition and Results of Operations-Liquidity and Capital
Resources." Although the Partnership believes that its
expectations regarding future events are based on reasonable
assumptions within the bounds of its knowledge of its business,
it can give no assurance that its goals will be achieved or that
its expectations regarding future developments will be realized.
Important factors that could cause actual results to differ
materially from those in the forward looking statements herein
include industry results, future demand for natural gas,
availability of supplies of Canadian natural gas, political and
regulatory developments that impact FERC proceedings involving
Northern Border Pipeline, Northern Border Pipeline's success in
sustaining its positions in such proceedings or the success of
intervenors in opposing Northern Border Pipeline's positions,
Northern Border Pipeline's ability to replace its rate base as it
is depreciated and amortized, developments relating to the
renewal of the pipeline right-of-way lease within the Fort Peck
Indian Reservation and right-of-way grants involving allotted
lands of the reservation, competitive developments by Canadian
and U.S. natural gas transmission peers, political and regulatory
developments in Canada, conditions of the capital markets and equity
markets, and the Partnership's ability to successfully implement the
Year 2000 Plan during the periods covered by the forward looking
statements.
Item 7a. Quantitative and Qualitative Disclosures About Market Risk
The Partnership's interest rate exposure results from its
variable rate borrowings from commercial banks. To mitigate
potential fluctuations in interest rates, the Partnership
maintains a significant portion of its consolidated debt
portfolio in fixed rate debt. The Partnership also uses interest
rate swap agreements to increase the portion of its fixed rate
debt and uses interest rate forward agreements to establish an
approximate effective borrowing rate for anticipated long-term
debt issuances.
If interest rates average one percentage point more than rates
in effect as of December 31, 1998, the Partnership's consolidated
annual interest expense would increase by approximately $6.2
million. This amount has been determined by considering the
impact of the hypothetical interest rates on the Partnership's
variable rate borrowings and interest rate swap agreements
outstanding as of December 31, 1998. Approximately $5.2 million
of this increase would result from applying the hypothetical
interest rates to Northern Border Pipeline's outstanding debt
portfolio. Northern Border Pipeline's tariff provides the
pipeline an opportunity to recover, among other items, interest
expense. Therefore, the Partnership believes that Northern
Border Pipeline would be allowed to recover the increase in its
interest expense, if it were to occur. Thus, the estimated
impact on the Partnership's annual earnings and cash flow from a
hypothetical one percentage point increase in interest rates
would be a reduction of approximately $1.0 million related to
interest expense on borrowings other than by Northern Border
Pipeline.
Item 8. Financial Statements and Supplementary Data
The information required hereunder is included in this report
as set forth in the "Index to Financial Statements" on page F-1.
Item 9. Disagreements on Accounting and Financial Disclosure
None.
Item 10. Partnership Management
The Partnership is managed by or under the direction of the
Partnership Policy Committee consisting of three members, each of
which has been appointed by one of the General Partners. The
members appointed by Northern Plains, Pan Border and Northwest
Border have 50%, 32.5% and 17.5%, respectively of the voting
power. The Partnership Policy Committee has appointed two
individuals who are neither officers nor employees of any General
Partner or any affiliate of a General Partner, to serve as a
committee of the Partnership (the "Audit Committee") with
authority and responsibility for selecting the Partnership's
independent public accountants, reviewing the Partnership's
annual audit and resolving accounting policy questions. The
Audit Committee also has the authority to review, at the request
of a General Partner, specific matters as to which a General
Partner believes there may be a conflict of interest in order to
determine if the resolution of such conflict proposed by the
Partnership Policy Committee is fair and reasonable to the
Partnership.
As is commonly the case with publicly-traded partnerships,
the Partnership does not directly employ any of the persons
responsible for managing or operating the Partnership or for
providing it with services relating to its day-to-day business
affairs. The Partnership has entered into an agreement (the
"Administrative Services Agreement") with NBP Services
Corporation ("NBP Services"), a wholly-owned subsidiary of Enron,
pursuant to which NBP Services provides tax, accounting, legal,
cash management, investor relations and other services for the
Partnership. NBP Services uses the employees of Enron or its
affiliates who have duties and responsibilities other than those
relating to the Administrative Services Agreement. In
consideration for its services under the Administrative Services
Agreement, NBP Services is reimbursed for its direct and indirect
costs and expenses, including an allocated portion of employee
time and Enron's overhead costs.
Set forth below is certain information concerning the
members of the Partnership Policy Committee, the Partnership's
representatives on the Northern Border Management Committee and
the persons designated by the Partnership Policy Committee as
executive officers of the Partnership and as Audit Committee
members. All members of the Partnership Policy Committee and the
Partnership's representatives on the Northern Border Management
Committee serve at the discretion of the General Partner that
appointed them, and the persons designated as executive officers
serve in that capacity at the discretion of the Partnership
Policy Committee. Effective December 22, 1998, Stanley C. Horton
replaced George L. Mazanec as a member of the Partnership Policy
Committee and the representative on the Northern Border
Management Committee designated by Pan Border. The members of
the Partnership Policy Committee receive no management fee or
other remuneration for serving on this Committee. The Audit
Committee members are elected, and may be removed, by the
Partnership Policy Committee. Each Audit Committee member
receives an annual fee of $15,000 and is paid $1,000 for each
meeting attended.
Name Age Positions
Executive Officers:
Larry L. DeRoin 57 Chief Executive Officer
Jerry L. Peters 41 Chief Financial and Accounting Officer
Members of Partnership Policy
Committee and Partnership's
representatives on Northern
Border Management Committee:
Larry L. DeRoin 57 Chairman
Stanley C. Horton 49 Member
Brian E. O'Neill 61 Member
Members of Audit Committee:
Daniel P. Whitty 67 Chairman
Gerald B. Smith 48 Member
Larry L. DeRoin was named Chief Executive Officer of the
Partnership and Chairman of the Partnership Policy Committee in
July 1993. Mr. DeRoin is the President of Northern Plains, an
Enron subsidiary, having held that position since January 1985,
and is a director of Northern Plains. He started his career with
another Enron Company, Northern Natural, in 1967 and has worked
in several management positions, including President of Peoples
Natural Gas Company, a former retail natural gas subsidiary of
Enron. Mr. DeRoin has been a member of the Northern Border
Management Committee since 1985 and has been Chairman since late
1988.
Stanley C. Horton was appointed to the Partnership Policy
Committee in December 1998. Mr. Horton is the Chairman and Chief
Executive Officer of Enron Gas Pipeline Group and has held that
position since January 1997. From February 1996 to January 1997,
he was Co-Chairman and Chief Operating Officer of Enron
Operations Corp. From June 1993 to February 1996, he was
President and Chief Operating Officer of Enron Pipeline and
Liquids Group. He is a director of EOTT Energy Corp., the
general partner of EOTT Energy Partners, L.P.
Brian E. O'Neill was appointed to the Partnership Policy
Committee in July 1993. Mr. O'Neill is President and Chairman of
the Board of Williams Gas Pipelines, Inc. He is President and
Chief Executive Officer of Kern River Acquisition Corporation,
Northwest Pipeline Corporation, Williams Western Pipeline
Company, Williams Natural Gas Company, Transco and Texas Gas
Transmission Corporation. He was elected to his position at Kern
River Acquisition Corporation in 1996. He was elected to his
position at Transco and Texas Gas Transmission Corporation in
1995. He was elected to his positions at Northwest Pipeline
Corporation and Williams Western Pipeline Company effective
January 1, 1994. He was elected President of Williams Natural
Gas Company in 1988. He is a director of Daniel Industries, Inc.
He has served on the Northern Border Management Committee since
April 1993.
Jerry L. Peters was named Chief Financial and Accounting
Officer in July 1994. Mr. Peters has held several management
positions with Northern Plains since 1985 and was elected
Treasurer for Northern Plains in October 1998, Vice President of
Finance for Northern Plains in July 1994, and director of
Northern Plains in August 1994. Prior to joining Northern Plains
in 1985, Mr. Peters was employed as a Certified Public Accountant
by KPMG Peat Marwick, LLP.
Daniel P. Whitty was appointed to the Audit Committee in
December 1993. Mr. Whitty is an independent financial
consultant. He is a director of Enron Equity Corp. and of EOTT
Energy Corp., both subsidiaries of Enron, and the latter of which
is the general partner of EOTT Energy Partners, L.P. He has
served as a member of the Board of Directors of Methodist
Retirement Communities Inc., and a Trustee of the Methodist
Retirement Trust. Mr. Whitty was a partner at Arthur Andersen &
Co. until his retirement on January 31, 1988.
Gerald B. Smith was appointed to the Audit Committee in
April 1994. He is Chief Executive Officer and co-founder of
Smith, Graham & Co., a fixed income investment management firm,
which was founded in 1990. He is a director of Pennzoil Quaker
State Co., Alliance Capital, Community Partners and First
Interstate Bank of Texas, N.A. From 1988 to 1990, he served as
Senior Vice President and Director of Fixed Income and Chairman
of the Executive Committee of Underwood Neuhaus & Co.
Item 11. Executive Compensation
The following table summarizes certain information regarding
compensation paid or accrued during each of Northern Plains' last
three fiscal years to the executive officers of the Partnership
(the "Named Officers") for services performed in their
capacities as executive officers of Northern Plains:
<PAGE>
<TABLE>
Summary Compensation Table
<CAPTION>
All Other
Annual Compensation Long-Term Compensation Compensation
Other Securities
Annual Restricted Underlying LTIP
Compensation Stock Options/ Payouts
Name & Position Year Salary Bonus (1) (2) Awards (3) SARs (#) (4) (5)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Larry L. DeRoin 1998 $256,067 $250,000 $ 7,200 $125,024 9,510 $ - $6,380
Chief Executive 1997 $247,333 $200,000 $11,908 $ - 15,285 $ - $ -
Officer 1996 $239,667 $144,000 $ 6,900 $ - 18,220 $56,250 $1,102
Jerry L. Peters 1998 $123,225 $110,000 $ 1,214 $ 60,030 10,000 $ - $1,956
Chief Financial and 1997 $118,750 $ 47,500 $ 1,200 $ - 5,715 $ - $ -
Accounting Officer 1996 $114,525 $ 28,000 $ - $ - 5,045 $ - $ 767
<FN>
(1) For 1996 and 1997, Mr. Peters' bonus awards were $48,000 and
$80,000, respectively. The bonuses detailed exclude amounts
deferred into the Bonus Stock Option Program. Mr. Peters
received a grant of 3,215 options during 1997 in lieu of a
$20,000 cash bonus payment for 1996 and 4,435 options during
1998 in lieu of a $32,500 cash bonus payment for 1997. The
1998 amount reflects the full bonus earned, including deferrals.
(2) Includes "Perquisites and Other Personal Benefits" if value
is greater than the lesser of $50,000 or 10% of reported salary
and bonus. Also, under Enron's 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
1996, 1997 and 1998 was the minimum rate of 12%. No interest has
been reported as Other Annual Compensation under Enron's 1985
Deferral Plan for participating Named Officers because the
crediting rates during 1996, 1997 and 1998, did not exceed 120%
of the long-term Applicable Federal Rate ("AFR") of 14.38% in
effect at the time the 1985 Deferral Plan was implemented.
Interest has been reported as Other Annual Compensation under
Enron's 1994 Deferral Plan during 1996 for the participating Named
Officers because the crediting rate of 9% exceeded 120% of the
AFR of 7.29% in effect at the time the 1994 Deferral Plan was
implemented. Beginning January 1, 1996, Enron's 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 Enron's 1994 Deferral Plan during 1996, 1997 and
1998. Other Annual Compensation also includes cash perquisite
allowances.
(3) The aggregate total of shares in unreleased Enron restricted stock
holdings and their values as of December 31, 1998, for each
of the Named Officers is: Mr. DeRoin, 2,191 shares valued at
$125,024; Mr. Peters, 1,052 shares valued at $60,030. This
represents performance based restricted stock which was
granted in lieu of performance units for the 1999-2002
performance period. Assuming continuous employment with Enron
or an Affiliate, the Award will become vested and will be released
January 31, 2002 as follows: (a) 33-1/3% of the total number of
shares granted will vest and be released if earnings targets,
as set by the Board of Directors of Enron in its sole discretion,
are met in any one year of the three year period 1999, 2000 and
2001, (b) 66-2/3% of the total number of shares granted will vest
and be released if earnings targets, as set by the Board of
Directors of Enron in its sole discretion, are met in any two years
of the three year period 1999, 2000 and 2001, and (c) 100% of
the Total Number of Shares Granted will vest and be released
if earnings targets, as set by the Board of Directors of
Enron in its sole discretion, are met in each of the
three years or cumulatively over the three year period 1999,
2000 and 2001. Shares of Restricted Stock which do not
become vested according to the above provisions will be
canceled.
(4) The amount shown for 1996 for Mr. DeRoin represent payouts
made under Enron's Performance Unit Plan account.
(5) The amounts shown include the value, as of year-end 1996 and
1998, of Enron Common Stock allocated during those years to
employees' special subaccounts under Enron's Employee Stock
Ownership Plan, and 1998 matching contributions to employees'
Enron Corp. Savings Plan.
</TABLE>
Stock Option Grants During 1998
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 1998.
<TABLE>
<CAPTION>
Individual Grants
% of Total Potential Realizable Value at
Options/ Options/SARs Exercise Assumed Annual Rates of
SARs Granted to or Base Stock Price Appreciation
Granted Employees in Price Expiration For Option Term (6)
Name (#) (1) Fiscal Year ($/Sh) Date 0%(5) 5% 10%
<S> <C> <C> <C> <C> <C> <C> <C>
Larry L DeRoin 9,510 (2) 0.12% $57.0625 12/31/05 $ - $ 220,920 $ 514,835
Jerry L. Peters 4,435 (3) 0.06% $40.1250 01/19/05 $ - $ 72,446 $ 168,829
1,000 (4) 0.01% $50.9375 10/12/08 $ - $ 32,035 $ 81,182
4,565 (2) 0.06% $57.0625 12/31/05 $ - $ 106,046 $ 247,132
All Employee and
Director Optionees 7,854,054 (7) 100% $49.9120 (8) N/A $ - $ 246,534,043(9) $ 624,765,648 (9)
All Stockholders N/A N/A N/A N/A $ - $10,386,143,976(9) $26,320,527,193 (9)
Optionee Gain as %
of All Stockholders
Gain N/A N/A N/A N/A N/A 2.37% 2.37%
<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) Represents stock options awarded under the Long-Term
Incentive Program for 1999. Grants under this program are
granted on the last trading day of the prior year, due to
regulations under Section 162(m) of the Internal Revenue Code.
Options have a seven year term, and are 25% vested on the date
of grant with an additional 25% vesting on the anniversary of
the date of grant through December 31, 2001.
(3) Represents stock options in lieu of 1997 bonus payment in
January 1998. Options have a seven year term and immediate
vesting.
(4) Represents stock options awarded for retention purposes.
Options have a ten year term, and are 20% vested on the date
of grant with an additional 20% vesting on each anniversary
of the date of grant through October 12, 2002.
(5) 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.
(6) 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.
(7) Includes shares issued on December 31, 1998 under the All
Employee Stock Option Program to employees hired during 1998.
(8) Weighted average exercise price of all Enron stock options
granted to employees in 1998.
(9) Appreciation for All Employee and Director Optionees is
calculated using the maximum allowable option term of 10
years, even though in some cases the actual option term is
less than 10 years. Appreciation for all stockholders is
calculated using an assumed ten-year option term, the
weighted average exercise price for All Employee and Director
Optionees ($49.9120) and the number of shares of Common Stock
issued and outstanding on December 31, 1998.
</TABLE>
Aggregated Stock Option/SAR Exercises During 1998 and Stock
Option/SAR Values as of December 31, 1998
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/
Acquired on Value December 31, 1998 SARs at December 31, 1998
Name Exercise (#) Realized Exercisable Unexercisable Exercisable Unexercisable
<S> <C> <C> <C> <C> <C> <C>
Larry L. DeRoin 96,745 $2,901,089 51,438 19,827 $995,040 $218,105
Jerry L. Peters 3,145 $ 77,736 21,450 6,795 $410,704 $ 51,864
</TABLE>
Long-Term Incentive Plan - Awards in 1998
The following table provides information concerning Long-Term
Incentive Plan awards under the Performance Unit Plan of Enron for
the 1998-2001 performance period. Grants are made at the beginning
of each fiscal year and each unit is assigned a value of $1.00.
The units are subject to a four-year performance period, at the end
of which Enron's total shareholder return is compared to that of the
11 peer companies included in the Current Peer Group. At that time,
the units are assigned a value ranging from $0 to $2.00 based on the
rank of Enron's shareholder return within the Current Peer Group.
To be valued at the maximum of $2.00, Enron must rank first, and to be
valued at the target of $1.00, Enron must rank third. Regardless
of Enron's rank, Enron's shareholder return must be above the
return on 90-day U.S. Treasury Bills over the same performance
period in order for any value to be assigned.
<TABLE>
<CAPTION>
Number of Shares, Performance or Estimated Future Payouts
Units or Other Other Period Until Under Non-Stock Price-Based Plans
Name Rights (#) Maturation Payout Threshold ($) Target ($) Maximum ($)
<S> <C> <C> <C> <C> <C>
Larry L.DeRoin 100,000 4 years $ - $100,000 $200,000
</TABLE>
Retirement and Supplemental Benefit Plans
Enron maintains the Enron Corp. Cash Balance Plan (the "Cash
Balance Plan") which is a noncontributory defined benefit 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. 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 31.3 39.0 $256,067 $138,009
Mr. Peters 13.9 37.8 $123,225 $ 71,933
<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. Security Ownership of Certain Beneficial
Owners and Management
The following table sets forth the beneficial ownership of
the voting securities of the Partnership as of February 10, 1999
by the Partnership's executive officers, members of the
Partnership Policy Committee and the Audit Committee and certain
beneficial owners. Other than as set forth below, no person is
known by the General Partners to own beneficially more than 5% of
the voting securities.
<TABLE>
<CAPTION>
Amount and Nature of Beneficial Ownership
Common Units
Number Percent
of Units1/ of Class
<S> <C> <C>
Larry L. DeRoin 10,000 *
1111 South 103rd Street
Omaha, NE 68124-1000
Jerry L. Peters 1,300 *
1111 South 103rd Street
Omaha, NE 68124-1000
The Williams Companies, Inc.2/ 1,123,500 3.8
One Williams Center
Tulsa, OK 74101-3288
Enron Corp.2/ 3,210,000 10.9
1400 Smith Street
Houston, TX 77002
Duke Energy Corp.2/ 2,086,500 7.1
422 So. Church St.
Charlotte, NC 88242-0001
<FN>
* Less than 1%.
1/ All units involve sole voting and investment power.
2/ Indirect ownership through their subsidiaries.
</TABLE>
Item 13. Certain Relationships and Related Transactions
The Partnership has extensive ongoing relationships with the
General Partners. Such relationships include the following: (i)
Northern Plains provides, in its capacity as the operator of the
Pipeline System, certain tax, accounting and other information to
the Partnership, and (ii) NBP Services, an affiliate of Enron,
assists the Partnership in connection with the operation and
management of the Partnership pursuant to the terms of an
Administrative Services Agreement between the Partnership and NBP
Services.
In addition, Northern Border Pipeline, in which the
Partnership owns a 70% general partner interest, has extensive
ongoing relationships with the General Partners and certain of
their affiliates and with affiliates of TransCanada. For
example, Northern Plains, a General Partner and affiliate of
Enron, has acted (since 1980), and will continue to act, as the
operator of the Pipeline System pursuant to the terms of an
Operating Agreement between Northern Plains and Northern Border
Pipeline. Enron Engineering & Construction Company ("EE&CC"),
an affiliate or Enron, provided project management for the
construction of The Chicago Project pursuant to a Project
Management Agreement between Northern Plains and EE&CC. In
addition, as of February 1, 1999, (i) ECT, an affiliate of Enron,
is a transportation customer of Northern Border Pipeline, which
is obligated to pay 5% of Northern Border Pipeline's annual cost
of service; (ii) Northern Natural, an affiliate of Enron, provides
a financial guaranty for a portion (300 MMCFD) of the transportation
capacity held by PAGUS, which represents 11% of Northern Border
Pipeline's annual cost of service; (iii) TransCanada Gas Services
Inc. ("TransCanada Gas Services"), an affiliate of TransCanada,
is a transportation customer of Northern Border Pipeline which is
obligated to pay 11% of Northern Border Pipeline's annual cost of
service pursuant to a transportation contract with Northern Border
Pipeline wherein TransCanada Gas Services acts as the agent of its
parent, TransCanada and (vi) Transco, an affiliate of Williams, is a
transportation customer of Northern Border Pipeline which is
obligated to pay 1% of Northern Border Pipeline's annual cost of
service.
The Partnership Policy Committee, whose members are
designated by the three General Partners, establishes the
business policies of the Partnership. The Partnership has
three representatives on the Northern Border Management
Committee, each of whom votes a portion of the Partnership's
70% interest on the Northern Border Management Committee.
These representatives are also designated by the General Partners.
The Partnership's interests could conflict with the
interests of the General Partners or their affiliates, and
in such case the members of the Partnership Policy Committee
will generally have a fiduciary duty to resolve such
conflicts in a manner that is in the Partnership's best
interest. Northern Border Pipeline's interests could
conflict with the Partnership's interest or the interest of
TransCanada and their affiliates, and in such case the
Partnership's representatives on the Northern Border
Management Committee will generally have a fiduciary duty
to resolve such conflicts in a manner that is in the best
interest of Northern Border Pipeline. The Partnership's
fiduciary duty as a general partner of Northern Border Pipeline
may restrict the Partnership from taking actions that might be
in the Partnership's best interest but in conflict with the
fiduciary duty that the Partnership's representatives or the
Partnership owe to TransCanada.
Unless otherwise provided for in a partnership
agreement, the laws of Delaware and Texas generally require
a general partner of a partnership to adhere to fiduciary
duty standards under which it owes its partners the highest
duties of good faith, fairness and loyalty. Similar rules
apply to persons serving on the Partnership Policy Committee
or the Northern Border Management Committee. Because of the
competing interests identified above, the Partnership's
Partnership Agreement and the partnership agreement for
Northern Border Pipeline contain provisions that modify
certain of these fiduciary duties. For example:
* The Partnership Agreement states that the General
Partners, their affiliates and their officers and directors
will not be liable for damages to the Partnership, its
limited partners or their assignees for errors of judgment
or for any acts or omissions if the General Partners and
such other persons acted in good faith.
* The Partnership Agreement allows the General Partners
and the Partnership Policy Committee to take into account
the interests of parties in addition to the Partnership's
interest in resolving conflicts of interest.
* The Partnership Agreement provides that the General
Partners will not be in breach of their obligations under
the Partnership Agreement or their duties to the Partnership
or its unitholders if the resolution of a conflict is fair
and reasonable to the Partnership. The latitude given in
the Partnership Agreement in connection with resolving
conflicts of interest may significantly limit the ability of
a unitholder to challenge what might otherwise be a breach
of fiduciary duty.
* The Partnership Agreement provides that a purchaser of
Common Units is deemed to have consented to certain
conflicts of interest and actions of the General Partners
and their affiliates that might otherwise be prohibited and
to have agreed that such conflicts of interest and actions
do not constitute a breach by the General Partners of any
duty stated or implied by law or equity.
* The Partnership's Audit Committee will, at the request
of a General Partner or a member of the Partnership Policy
Committee, review conflicts of interest that may arise
between a General Partner and its affiliates (or the member
of the Partnership Policy Committee designated by it), on
the one hand, and the unitholders or the Partnership, on the
other. Any resolution of a conflict approved by the Audit
Committee is conclusively deemed fair and reasonable to the
Partnership.
* The Partnership has proposed to enter into an amendment
to the partnership agreement for Northern Border Pipeline
that relieves TransCanada, its affiliates and their
transferees from any duty to offer business opportunities to
Northern Border Pipeline, with certain exceptions. The
proposed amendment would also relieve the Partnership from
any duty to offer to Northern Border Pipeline certain
business opportunities that come to the Partnership's
attention.
The Partnership is required to indemnify the members of
the Partnership Policy Committee and General Partners, their
affiliates and their respective officers, directors,
employees, agents and trustees to the fullest extent
permitted by law against liabilities, costs and expenses
incurred by any such person who acted in good faith and in a
manner reasonably believed to be in, or (in the case of a
person other than one of the General Partners) not opposed
to, the Partnership's best interests and with respect to any
criminal proceedings, had no reasonable cause to believe the
conduct was unlawful.
<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 Form of Amended and Restated Agreement of
Limited Partnership of Northern Border
Partners, L.P. (Exhibit 3.1 No. 2 to the
Partnership's Form S-1 Registration
Statement, Registration No. 33-66158
("Form S-1")).
*10.1 Form of Amended and Restated Agreement of
Limited Partnership For Northern Border
Intermediate Limited Partnership (Exhibit
10.1 to Form S-1).
*10.2 Northern Border Pipeline Company General
Partnership Agreement between Northern
Plains Natural Gas Company, Northwest
Border Pipeline Company, Pan Border Gas
Company, TransCanada Border Pipeline Ltd.
and TransCan Northern Ltd., effective
March 9, 1978, as amended (Exhibit 10.2
to Form S-1).
*10.3 Operating Agreement between Northern
Border Pipeline Company and Northern
Plains Natural Gas Company, dated
February 28, 1980 (Exhibit 10.3 to Form S-1).
*10.4 Administrative Services Agreement between
NBP Services Corporation, Northern Border
Partners, L.P. and Northern Border
Intermediate Limited Partnership (Exhibit
10.4 to Form S-1).
*10.5 Note Purchase Agreement between Northern
Border Pipeline Company and the parties
listed therein, dated July 15, 1992
(Exhibit 10.6 to Form S-1).
*10.5.1 Supplemental Agreement to the Note
Purchase Agreement dated as of June 1,
1995 (Exhibit 10.6.1 to the Partnership's
Annual Report on Form 10-K for the year
ended December 31, 1995 ("1995 10-K")).
*10.6 Guaranty made by Panhandle Eastern
Pipeline Company, dated October 31, 1992
(Exhibit 10.9 to Form S-1).
*10.7 Northern Border Pipeline Company U.S.
Shippers Service Agreement between
Northern Border Pipeline Company and
Enron Gas Marketing, Inc., dated June 22,
1990 (Exhibit 10.10 to Form S-1).
*10.7.1 Amended Exhibit A to Northern Border
Pipeline Company U.S. Shippers Service
Agreement between Northern Border
Pipeline Company and Enron Gas Marketing,
Inc. (Exhibit 10.10.1 to the
Partnership's Annual Report on Form 10-K
for the year ended December 31, 1993
("1993 10-K")).
*10.7.2 Amended Exhibit A to Northern Border
Pipeline U.S. Shippers Service Agreement
between Northern Border Pipeline Company
and Enron Gas Marketing, Inc., effective
November 1, 1994 (Exhibit 10.10.2 to the
Partnership's Annual Report on Form 10-K
for the year ended December 31, 1994).
*10.7.3 Amended Exhibit A's to Northern Border
Pipeline Company U.S. Shipper Service
Agreement effective, August 1, 1995 and
November 1, 1995 (Exhibit 10.10.3 to 1995
10-K).
*10.7.4 Amended Exhibit A to Northern Border
Pipeline Company U.S. Shipper Service
Agreement effective April l, 1998
(Exhibit 10.10.4 to the Partnership's
Annual Report on Form 10-K for the year
ended December 31, 1997 ("1997 10-K")).
*10.8 Guaranty made by Northern Natural Gas
Company, dated October 7, 1993 (Exhibit
10.11.1 to 1993 10-K).
*10.9 Guaranty made by Northern Natural Gas
Company, dated October 7, 1993 (Exhibit
10.11.2 to 1993 10-K)
*10.10 Northern Border Pipeline Company U.S.
Shippers Service Agreement between
Northern Border Pipeline Company and
Western Gas Marketing Limited, as agent
for TransCanada PipeLines Limited, dated
December 15, 1980 (Exhibit 10.13 to Form S-1).
*10.10.1 Amendment to Northern Border Pipeline
Company Service Agreement extending the
term effective November 1, 1995 (Exhibit
10.13.1 to 1995 10-K).
*10.11 Form of Seventh Supplement Amending
Northern Border Pipeline Company General
Partnership Agreement (Exhibit 10.15 to
Form S-1).
*10.12 Northern Border Pipeline Company U.S.
Shippers Service Agreement between
Northern Border Pipeline Company and
Transcontinental Gas Pipe Line
Corporation, dated July 14, 1983, with
Amended Exhibit A effective February 11,
1994 (Exhibit 10.17 to 1995 10-K).
*10.13 Form of Credit Agreement among Northern
Border Pipeline Company, The First
National Bank of Chicago, as
Administrative Agent, The First National
Bank of Chicago, Royal Bank of Canada,
and Bank of America National Trust and
Savings Association, as Syndication
Agents, First Chicago Capital Markets,
Inc., Royal Bank of Canada, and
BancAmerica Securities, Inc, as Joint
Arrangers and Lenders (as defined
therein) dated as of June 16, 1997
(Exhibit 10(c) to Amendment No. 1 to Form
S-3, Registration Statement No. 333-40601
("Form S-3")).
*10.14 Form of Credit Agreement among Northern
Border Partners, L.P., Canadian Imperial
Bank of Commerce, as Agent and Lenders
(as defined therein) dated as of November 6, 1997
(Exhibit 10(d) to Amendment No. 1 to Form S-3).
*10.15 Northern Border Pipeline Company U.S.
Shippers Service Agreement between
Northern Border Pipeline Company and
Enron Capital & Trade Resources Corp.
dated October 15, 1997 (Exhibit 10.21 to
1997 10-K).
*10.16 Northern Border Pipeline Company U.S.
Shippers Service Agreement between
Northern Border Pipeline Company and
Enron Capital & Trade Resources Corp.
dated October 15, 1997 (Exhibit 10.22 to
1997 10-K).
*10.17 Northern Border Pipeline Company U.S.
Shippers Service Agreement between
Northern Border Pipeline Company and
Enron Capital & Trade Resources Corp.
dated August 5, 1997 with Amendment dated
September 25, 1997 (Exhibit 10.25 to 1997
10-K).
*10.18 Northern Border Pipeline Company U.S.
Shippers Service Agreement between
Northern Border Pipeline Company and
Enron Capital & Trade Resources Corp.
dated August 5, 1997 (Exhibit 10.26 to
1997 10-K).
*10.19 Northern Border Pipeline Company U.S.
Shippers Service Agreement between
Northern Border Pipeline Company and
TransCanada Gas Services Inc., as agent
for TransCanada PipeLines Limited dated
August 5, 1997 (Exhibit 10.27 to 1997
10-K).
*10.20 Northern Border Pipeline Company U.S.
Shippers Service Agreement between
Northern Border Pipeline Company and
TransCanada Gas Services Inc., as agent
for TransCanada PipeLines Limited dated
August 5, 1997 (Exhibit 10.28 to 1997
10-K).
21 The subsidiaries of Northern Border
Partners, L.P. are Northern Border
Intermediate Limited Partnership,
Northern Border Pipeline Company, Black
Mesa Holdings, Inc., Black Mesa Pipeline,
Inc., Black Mesa Pipeline Operations
L.L.C. Williams Technologies, Inc. and
Williams Technologies L.L.C.
23.01 Consent of Arthur Andersen LLP.
*99.1 Northern Plains Natural Gas Company Phantom
Unit Plan (Exhibit 99.1 to Form S-8,
Registration No. 333-66949).
__________
*Indicates exhibits incorporated by reference as
indicated; all other exhibits are filed herewith.
(b) Reports
No reports on Form 8-K were filed by the Partnership
during the last quarter of 1998.
<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 18th day of March, 1999.
NORTHERN BORDER PARTNERS, L.P.
(A Delaware Limited Partnership)
By: LARRY L. DEROIN
Larry L. DeRoin
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons
in the capacities and on the dates indicated.
Signature Title Date
LARRY L. DEROIN Chief Executive Officer and March 18, 1999
Larry L. DeRoin Chairman of the Partnership
Policy Committee
(Principal Executive Officer)
STANLEY C. HORTON Member of Partnership Policy March 18, 1999
Stanley C. Horton Committee
BRIAN E. O'NEILL Member of Partnership Policy March 18, 1999
Brian E. O'Neill Committee
JERRY L. PETERS Chief Financial and March 18, 1999
Jerry L. Peters Accounting Officer
<PAGE>
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
INDEX TO FINANCIAL STATEMENTS
Page No.
Consolidated Financial Statements
Report of Independent Public Accountants F-2
Consolidated Balance Sheet - December 31, 1998 and 1997 F-3
Consolidated Statement of Income - Years Ended F-4
December 31, 1998, 1997 and 1996
Consolidated Statement of Cash Flows - Years Ended F-5
December 31, 1998, 1997 and 1996
Consolidated Statement of Changes in Partners' Capital - F-6
Years Ended December 31, 1998, 1997 and 1996
Notes to Consolidated Financial Statements F-7 through
F-18
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 Partners, L.P.:
We have audited the accompanying consolidated balance sheets of
Northern Border Partners, L.P., a Delaware limited partnership,
and Subsidiaries as of December 31, 1998 and 1997, and the
related consolidated statements of income, cash flows and changes
in partners' capital for each of the three years in the period
ended December 31, 1998. These financial statements are the
responsibility of the Company's management. Our responsibility
is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether
the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that
our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above
present fairly, in all material respects, the financial position
of Northern Border Partners, L.P. and Subsidiaries as of December
31, 1998 and 1997, and the results of their operations and their
cash flows for each of the three years in the period ended
December 31, 1998, in conformity with generally accepted
accounting principles.
ARTHUR ANDERSEN LLP
Omaha, Nebraska,
January 19, 1999
<PAGE>
<TABLE>
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(In Thousands)
<CAPTION>
December 31,
1998 1997
<S> <C> <C> 1998 1997
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 41,042 $ 106,757
Accounts receivable 19,077 18,139
Related party receivables 2,470 1,780
Materials and supplies, at cost 4,189 4,458
Under recovered cost of service 2,781 --
Total current assets 69,559 131,134
TRANSMISSION PLANT
Property, plant and equipment 2,345,700 1,749,862
Less: Accumulated provision for
depreciation and amortization 615,224 631,498
Net property, plant and equipment 1,730,476 1,118,364
OTHER ASSETS 25,731 17,419
Total assets $1,825,766 $1,266,917
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES
Current maturities of long-term debt $ 2,805 $ 2,523
Accounts payable 46,032 64,668
Accrued taxes other than income 20,140 20,508
Accrued interest 12,462 10,766
Over recovered cost of service -- 4,601
Total current liabilities 81,439 103,066
LONG-TERM DEBT, net of current maturities 974,027 478,832
MINORITY INTERESTS IN PARTNERS' CAPITAL 253,031 174,424
RESERVES AND DEFERRED CREDITS 9,843 9,867
COMMITMENTS AND CONTINGENCIES (NOTE 7)
PARTNERS' CAPITAL
General Partners 10,148 10,015
Common Units 401,388 394,587
Subordinated Units 95,890 96,126
Total partners' capital 507,426 500,728
Total liabilities and partners' capital $1,825,766 $1,266,917
<FN>
The accompanying notes are an integral part of these consolidated
financial statements.
</TABLE>
<PAGE>
<TABLE>
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF INCOME
(In Thousands, Except Per Unit Amounts)
<CAPTION>
Year Ended December 31,
1998 1997 1996
<S> <C> <C> <C>
OPERATING REVENUE $217,592 $198,574 $201,943
OPERATING EXPENSES
Operations and maintenance 44,770 37,418 28,366
Depreciation and amortization 43,536 40,172 46,979
Taxes other than income 22,012 22,836 24,390
Regulatory credit (8,878) -- --
Operating expenses 101,440 100,426 99,735
OPERATING INCOME 116,152 98,148 102,208
INTEREST EXPENSE
Interest expense 49,923 34,520 33,117
Interest expense capitalized (19,001) (3,660) (447)
Interest expense, net 30,922 30,860 32,670
OTHER INCOME
Allowance for equity funds used
during construction 10,237 1,400 396
Other income, net 2,622 6,589 2,504
Other income 12,859 7,989 2,900
MINORITY INTERESTS IN NET INCOME 30,069 22,253 22,153
NET INCOME TO PARTNERS $ 68,020 $ 53,024 $ 50,285
NET INCOME PER UNIT $ 2.27 $ 1.97 $ 1.88
NUMBER OF UNITS USED IN COMPUTATION 29,345 26,392 26,200
<FN>
The accompanying notes are an integral part of these consolidated
financial statements.
</TABLE>
<PAGE>
<TABLE>
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
(In Thousands)
<CAPTION>
Year Ended December 31,
1998 1997 1996
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income to partners $ 68,020 $ 53,024 $ 50,285
Adjustments to reconcile net income to
partners to net cash provided by
operating activities:
Depreciation and amortization 43,551 40,179 47,010
Minority interests in net income 30,069 22,253 22,153
Provision for billings subject to refund -- 40,403 12,227
Refunds to shippers -- (52,630) --
Allowance for equity funds used
during construction (10,237) (1,400) (396)
Regulatory credit (9,105) -- --
Changes in other current assets
and liabilities (19,243) 17,101 7,749
Other 794 691 (1,494)
Total adjustments 35,829 66,597 87,249
Net cash provided by operating activities 103,849 119,621 137,534
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for property, plant
and equipment, net (652,194) (152,658) (18,597)
Acquisition and consolidation of businesses -- 3,374 --
Other -- (586) (4,796)
Net cash used in investing activities (652,194) (149,870) (23,393)
CASH FLOWS FROM FINANCING ACTIVITIES:
Cash distributions
General and limited partners (68,876) (58,957) (58,816)
Minority Interests (18,362) (30,080) (30,853)
Contributions received from
Minority Interests 66,900 24,300 --
Issuance of partnership interests, net 7,554 90,987 --
Issuance of long-term debt 498,000 209,000 --
Long-term debt financing costs (63) (969) --
Retirement of long-term debt (2,523) (128,665) (32,500)
Borrowings on (repayment of) note payable -- (10,000) 10,000
Net cash provided by (used in)
financing activities 482,630 95,616 (112,169)
NET CHANGE IN CASH AND CASH EQUIVALENTS (65,715) 65,367 1,972
Cash and cash equivalents-beginning of period 106,757 41,390 39,418
Cash and cash equivalents-end of period $ 41,042 $ 106,757 $ 41,390
<FN>
The accompanying notes are an integral part of these consolidated
financial statements.
</TABLE>
<PAGE>
<TABLE>
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' CAPITAL
(In Thousands)
<CAPTION>
Total
General Common Subordinated Partners'
Partners Units Units Capital
<S> <C> <C> <C> <C>
Partners' Capital at December 31, 1995 $ 8,382 $310,089 $100,646 $419,117
Net income to partners 1,006 37,204 12,075 50,285
Distributions paid (1,176) (43,516) (14,124) (58,816)
Partners' Capital at December 31, 1996 8,212 303,777 98,597 410,586
Net income to partners 1,061 39,331 12,632 53,024
Issuance of partnership interests, net 1,921 95,133 (979) 96,075
Distributions paid (1,179) (43,654) (14,124) (58,957)
Partners' Capital at December 31, 1997 10,015 394,587 96,126 500,728
Net income to partners 1,359 52,077 14,584 68,020
Issuance of partnership interests, net 151 7,457 (54) 7,554
Distributions paid (1,377) (52,733) (14,766) (68,876)
Partners' Capital at December 31, 1998 $10,148 $401,388 $ 95,890 $507,426
<FN>
The accompanying notes are an integral part of these consolidated
financial statements.
</TABLE>
<PAGE>
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND MANAGEMENT
Northern Border Partners, L.P., a Delaware limited partnership,
through a subsidiary limited partnership, Northern Border Intermediate
Limited Partnership, a Delaware limited partnership, collectively
referred to herein as the Partnership, owns a 70% general partner
interest in Northern Border Pipeline Company (Northern Border Pipeline).
The remaining 30% general partner interests in Northern Border Pipeline
are owned by TransCanada Border PipeLine Ltd. (6%) and TransCan Northern
Ltd. (24%), both of which are wholly-owned subsidiaries of TransCanada
PipeLines Limited (TransCanada). Black Mesa Holdings, Inc. and
Black Mesa Pipeline Operations, L.L.C. (collectively Black
Mesa) and Williams Technologies, Inc. (WTI) are wholly-owned
subsidiaries of the Partnership (see Note 3).
Northern Plains Natural Gas Company (Northern Plains), a
wholly-owned subsidiary of Enron Corp. (Enron), Pan
Border Gas Company (Pan Border), a wholly-owned subsidiary of
Northern Plains, and Northwest Border Pipeline Company (Northwest
Border), a wholly-owned subsidiary of The Williams Companies, Inc.
serve as the General Partners of the Partnership and collectively
own a 2% general partner interest in the Partnership. In December
1998, Northern Plains acquired Pan Border from a subsidiary of Duke
nergy Corporation. At the closing, Pan Border's sole asset consisted
of its general partner interest in the Partnership. The General
Partners or their affiliates also own Subordinated Units representing,
in the aggregate, an effective 14.5% limited partner interest in the
Partnership at December 31, 1998 (see Note 6).
The Partnership is managed by or under the direction of a committee
(Partnership Policy Committee) consisting of one person appointed by
each General Partner. The members appointed by Northern Plains, Pan
Border and Northwest Border have 50%, 32.5% and 17.5%, respectively,
of the voting interest on the Partnership Policy Committee. The
Partnership has entered into an administrative services agreement
with NBP Services Corporation (NBP Services), a wholly-owned
subsidiary of Enron, pursuant to which NBP Services provides certain
administrative services for the Partnership and is reimbursed for
its direct and indirect costs and expenses.
Northern Border Pipeline is a general partnership, formed March 9,
1978, pursuant to the Texas Uniform Partnership Act. Northern
Border Pipeline owns a 1,214-mile natural gas transmission pipeline
system extending from the United States-Canadian border near Port of
Morgan, Montana, to a terminus near Manhattan, Illinois.
Northern Border Pipeline is managed by a Management Committee that
includes three representatives from the Partnership (one
representative appointed by each of the General Partners of the
Partnership) and one representative from the TransCanada subsidiaries.
The Partnership's representatives selected by Northern Plains, Pan
Border and Northwest Border have 35%, 22.75% and 12.25%, respectively,
of the voting interest on the Northern Border Pipeline Management
Committee. The representative designated by TransCanada votes the
remaining 30% interest. The day-to-day management of Northern
Border Pipeline's affairs is the responsibility of Northern Plains
(the Operator), as defined by the operating agreement between
Northern Border Pipeline and Northern Plains. Northern Border
Pipeline is charged for the salaries, benefits and expenses of the
Operator. Substantially all of the operations and maintenance
expenses are paid to the Operator and other Enron affiliates.
Additionally, an Enron affiliate was responsible for project
management on Norther Border Pipeline's expansion and extension
of its pipeline from near Harper, Iowa to a point near Manhattan,
Illinois (The Chicago Project) (see Note 7).
The Northern Border Pipeline partnership agreement provides that
distributions to Northern Border Pipeline's partners are to be made
on a pro rata basis according to each partner's capital account
balance. The Northern Border Pipeline Management Committee
determines the amount and timing of such distributions. Any changes
to, or suspension of, the cash distribution policy of Northern
Border Pipeline requires the unanimous approval of the Northern
Border Pipeline Management Committee.
Black Mesa, through a wholly-owned subsidiary, owns a 273-
mile, 18-inch diameter coal slurry pipeline that originates at a coal
mine in Kayenta, Arizona and ends at the 1,500 megawatt Mohave Power
Station located in Laughlin, Nevada. A subsidiary of the Partnership is
the operator of Black Mesa, pursuant to a management agreement.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(A) Principles of Consolidation and Use of Estimates
The consolidated financial statements include the assets,
liabilities and results of operations of the Partnership and its
majority-owned subsidiaries. The Partnership operates through a
subsidiary limited partnership of which the Partnership is the
sole limited partner and the General Partners are the sole
general partners. The 30% ownership of Northern Border Pipeline
by the TransCanada subsidiaries is accounted for as a minority
interest. All significant intercompany items have been eliminated
in consolidation.
The preparation of financial statements in conformity with
generally accepted accounting principles requires management to
make estimates and assumptions that affect the reported amounts
of assets and liabilities and disclosure of contingent assets
and liabilities at the date of the financial statements and the
reported amounts of revenues and expenses during the reporting
period. Actual results could differ from those estimates.
(B) Government Regulations
Northern Border Pipeline is subject to regulation by the
Federal Energy Regulatory Commission (FERC). Northern Border
Pipeline's accounting policies conform to generally accepted
accounting principles, as applied in the case of regulated
entities.
(C) Revenue Recognition
Northern Border Pipeline bills the cost of service on an
estimated basis for a six-month cycle. Any net excess or deficiency
resulting from the comparison of the actual cost of service determined
for that period in accordance with the FERC tariff to the estimated
billing is accumulated, including carrying charges thereon, and is
either billed to or credited back to the shippers. Revenues reflect
actual cost of service. An amount equal to differences between billing
estimates and the actual cost of service, including carrying charges, is
reflected in current assets or current liabilities.
(D) Income Taxes
Income taxes are the responsibility of the partners and are
not reflected in these financial statements. However, the
Northern Border Pipeline tariff establishes the method of
accounting for and calculating income taxes and requires
Northern Border Pipeline to reflect in its cost of service the
income taxes which would have been paid or accrued if Northern
Border Pipeline were organized during the period as a
corporation. As a result, for purposes of calculating the
return allowed by the FERC, partners' capital and rate base are
reduced by the amount equivalent to the net accumulated deferred
income taxes. Such amounts were approximately $300 million at
both December 31, 1998 and 1997, and are primarily related to
accelerated depreciation and other plant-related differences.
(E) Property, Plant and Equipment and Related Depreciation and
Amortization
Property, plant and equipment is stated at original cost.
Balances at December 31, 1998 and 1997 include construction work
in progress of approximately $1.5 million and $211.4 million,
respectively. Approximately $197.9 million of construction work
in progress at December 31, 1997, represented project-to-date
costs on The Chicago Project. In December 1998, Northern Border
Pipeline placed into service the facilities for The Chicago
Project. At December 31, 1998 and 1997, respectively,
approximately $37.4 million and $44.2 million of project costs
incurred but not paid for The Chicago Project were recorded in
accounts payable and property, plant and equipment on the
consolidated balance sheet and were excluded from the
changes in other current assets and liabilities and capital
expenditures for property, plant and equipment, net on the
consolidated statement of cash flows.
Maintenance and repairs are charged to operations in the
period incurred. The provision for depreciation and
amortization of Northern Border Pipeline's transmission line is
an integral part of its FERC tariff. The effective depreciation
rate applied to Northern Border Pipeline's gross transmission
plant in 1998, 1997, and 1996 was 2.5%, 2.5%, and 3.1%,
respectively (see Note 7). At the time The Chicago Project was
placed into service, Northern Border Pipeline's depreciation
rate was reduced to 2.0%. Beginning in the year 2000, the
depreciation rate is scheduled 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 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.
(F) 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.
(G) Allowance for Funds Used During Construction
The allowance for funds used during construction (AFUDC)
represents the estimated costs, during the period of
construction, of funds used for construction purposes. For
regulated activities, Northern Border Pipeline is permitted to
earn a return on and recover AFUDC through its inclusion in rate
base and the provision for depreciation. The rate employed for
the equity component of AFUDC is the equity rate of return
stated in Northern Border Pipeline's FERC tariff.
(H) Risk Management
Financial instruments are used 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. Additionally, Northern
Border Pipeline has entered into interest rate forward
agreements to hedge the interest rates on a planned issuance
of 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. No cost or benefit is currently
associated with the interest rate forward agreements.
(I) Reclassifications
Certain reclassifications have been made to the consolidated
financial statements for prior years to conform with the current
presentation.
3. ACQUISITIONS
On May 31, 1997, the Partnership exchanged 125,357 Common
Units for all of the outstanding common stock of WTI. Effective
with the acquisition of WTI, which was recorded using the purchase
method of accounting, the Partnership increased its ownership
position in Black Mesa from the 60.5% acquired in 1996 to 71.75%
and began to reflect Black Mesa, including Black Mesa's minority
ownership interests, in the Partnership's consolidated financial
statements. Prior to this time, the Partnership's investment in
Black Mesa was accounted for using the equity method. On December
29, 1997, the Partnership acquired the remaining minority ownership
interest in Black Mesa through the exchange of 46,956 Common Units
and cash. The following is a summary of the effects of the
acquisition of WTI and consolidation of Black Mesa on the
Partnership's consolidated financial position in 1997 (amounts
in thousands):
<TABLE>
<S> <C>
Cash $ 3,374
Net property, plant and equipment 18,350
Other current and noncurrent assets 10,159
Long-term debt, including
current maturities (23,520)
Other liabilities (3,090)
Minority interests (185)
Common Units $ 5,088
</TABLE>
4. SHIPPER SERVICE AGREEMENTS
Operating revenues are collected pursuant to the FERC tariff which
directs that Northern Border Pipeline collect its cost of service
through firm transportation service agreements (firm service
agreements). Northern Border Pipeline's FERC tariff provides an
opportunity to recover all operations and maintenance costs of the
pipeline, taxes other than income taxes, interest, depreciation and
amortization, an allowance for income taxes and a regulated equity
return. Billings for the firm service agreements are based on
contracted volumes to determine the allocable share of the cost of
service and are not dependent upon the percentage of available
capacity actually used.
Northern Border Pipeline's firm service agreements extend for
various terms with termination dates that range from October 2001 to
December 2013. Northern Border Pipeline also has interruptible
service contracts with numerous other shippers as a result of its
self-implementing blanket transportation authority. Revenues
received from the interruptible service contracts are credited to
the cost of service reducing the billings for the firm service
agreements.
Northern Border Pipeline's largest shipper, Pan-Alberta Gas (U.S.)
Inc. (PAGUS), is presently obligated for approximately 26.5% of the
cost of service through three firm service agreements which expire
in October 2003. FERC approval is required for the extension of one
of the firm service agreements, relating to approximately 6.5% of
the cost of service, beyond October 2001. Financial guarantees
exist through October 2001 for approximately 17.0% 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, 1998, 1997 and 1996 were $87.3 million, $86.8
million and $95.7 million, respectively.
Shippers affiliated with the partners of Northern Border Pipeline
have firm service agreements representing approximately 16.9% 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, 1998, 1997 and 1996 were $22.4 million, $20.2 million
and $21.4 million, respectively.
Black Mesa's operating revenue is derived from a pipeline
transportation agreement (Pipeline Agreement) with the coal supplier
for the Mohave Power Station that expires in December 2005. The
pipeline is the sole source of fuel for the Mohave plant. Under the
terms of the Pipeline Agreement, the pipeline receives a monthly
demand payment, a per ton commodity payment and a reimbursement for
certain other expenses.
5. CREDIT FACILITIES AND LONG-TERM DEBT
Detailed information on long-term debt is as follows:
<TABLE>
<CAPTION>
December 31,
(In thousands) 1998 1997
<S> <C> <C>
Northern Border Pipeline
Senior notes - average 8.43%,
due from 2000 to 2003 $250,000 $250,000
Pipeline Credit Agreement
Five-year revolving credit facility 127,500 127,500
Three-year revolving credit facility 484,500 81,500
Northern Border Partners, L.P.
Partnership Credit Agreement -
due 2000 95,000 --
Black Mesa
10.7% Note agreement,
due quarterly to 2004 19,832 22,355
Total 976,832 481,355
Less: Current maturities of long-term debt 2,805 2,523
Long-term debt $974,027 $478,832
</TABLE>
In June 1997, Northern Border Pipeline entered into a credit
agreement (Pipeline Credit Agreement) with certain financial
institutions to borrow up to an aggregate principal amount of $750
million. The Pipeline Credit Agreement is comprised of a $200
million five-year revolving credit facility to be used for the
retirement of Northern Border Pipeline's 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. The three-year revolving credit facility
may be converted to a term loan maturing in June 2002 once certain
conditions are met. 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 aggregate principal amount of $750
million.
At both December 31, 1998 and 1997, Northern Border Pipeline had
outstanding interest rate swap agreements with notional amounts of
$90 million. Under the agreements, which have a remaining average
maturity of approximately one year as of December 31, 1998, 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 both December 31, 1998 and 1997,
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 6.17% and 7.09% at December 31,
1998 and 1997, respectively.
During September 1998, Northern Border Pipeline executed interest
rate forward agreements with an aggregate notional amount of $150
million to hedge the interest rate for a planned issuance of fixed
rate debt during 1999. The average reference interest rate on the
agreements, based on ten-year U.S. Treasury Notes, is 4.90%.
In November 1997, the Partnership entered into a credit agreement
(Partnership Credit Agreement) with certain financial institutions
to borrow up to an aggregate principal amount of $175 million under
a revolving credit facility. The Partnership Credit Agreement is to
be used for interim funding of the Partnership's required capital
contributions to Northern Border Pipeline for construction of The
Chicago Project. The amount available under the Partnership Credit
Agreement is reduced to the extent the Partnership issues additional
limited partner interests to fund the Partnership's required capital
contributions for The Chicago Project in excess of $25 million. The
public offering of Common Units discussed in Note 6 reduced the
amount available under the Partnership Credit Agreement to $104
million at December 31, 1998. The maturity date of the Partnership
Credit Agreement will be November 2000 if Northern Border Pipeline
converts the $550 million three-year revolving credit facility to a
term loan; otherwise the maturity date is June 2000. The
Partnership Credit Agreement permits the Partnership to choose among
various interest rate options, to specify the portion of the
borrowings to be covered by specific interest rate options and to
specify the interest rate period, subject to certain parameters.
The Partnership is required to pay a commitment fee on the aggregate
undrawn principal amount under the facility. At December 31, 1998,
the average interest rate on the Partnership Credit Agreement was
6.04%.
Interest paid, net of amounts capitalized, during the years
ended December 31, 1998, 1997 and 1996 was $28.7 million, $31.6
million and $31.9 million, respectively.
Aggregate repayments of long-term debt required for the next five
years are as follows: $3 million, $164 million, $44 million, $694
million and $69 million for 1999, 2000, 2001, 2002 and 2003,
respectively. The aggregate repayments reflect Northern Border
Pipeline's intent and ability to convert the three-year revolving
credit facility to a term loan.
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, 1998 and 1997, respectively, $173
million and $81 million of partners' capital of Northern Border
Pipeline could be distributed. The Partnership Credit Agreement
restricts incurrence of senior indebtedness by the Partnership and
requires the maintenance of a ratio of debt to total capital,
excluding the debt of consolidated subsidiaries, of no more than 35
percent. Black Mesa's note agreement is secured by the common stock
of Black Mesa and by a guarantee by the Partnership of up to $1.0
million. In addition, the note agreement requires Black Mesa to
maintain a deposit of $2.0 million, invested in Treasury bills, in
escrow until the debt is retired. The deposit is reflected in other
assets on the consolidated balance sheet at December 31, 1998 and
1997.
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 was
approximately $287 million and $276 million at December 31, 1998 and
1997, respectively. The estimated fair value of the Black Mesa note
agreement was approximately $23 million and $25 million at December
31, 1998 and 1997, respectively. At both December 31, 1998 and
1997, the estimated fair value which would be payable to terminate
the interest rate swap agreements, taking into account current
interest rates, was approximately $3 million. The estimated fair
value which would be payable to terminate the interest rate forward
agreements, taking into account current interest rates, was
approximately $3 million at December 31, 1998. The Partnership
presently intends to maintain the current schedule of maturities for
the senior notes, the Black Mesa note agreement and the interest
rate swap agreements that will result in no gains or losses on their
respective repayment. The carrying value of the Pipeline Credit
Agreement approximates the fair value since the interest rates are
periodically adjusted to current market conditions.
6. PARTNERS' CAPITAL
At December 31, 1998, partners' capital consisted of 22,927,313
Common Units representing an effective 76.6% limited partner
interest in the Partnership; 6,420,000 Subordinated Units
representing an effective 21.4% limited partner interest in the
Partnership (including the 14.5% held collectively by the General
Partners or their affiliates); and a 2% general partner interest.
At December 31, 1997, partners' capital consisted of 22,702,313
Common Units representing an effective 76.4% limited partner
interest in the Partnership; 6,420,000 Subordinated Units
representing an effective 21.6% limited partner interest in the
Partnership; and a 2% general partner interest. In January 1998 and
December 1997, the Partnership sold, through an underwritten public
offering, 225,000 Common Units and 2,750,000 Common Units,
respectively. The units sold in 1998 resulted from the underwriters
exercise of an over-allotment option to purchase a limited number of
additional Common Units. In conjunction with the issuance of the
additional Common Units, the Partnership's general partners made
capital contributions to the Partnership to maintain a 2% general
partner interest in accordance with the partnership agreements.
The net proceeds, of the public offering and the general partners'
capital contributions, of approximately $7.6 million and $90.9
million in 1998 and 1997, respectively, were used by the Partnership
to fund a portion of the capital contributions to Northern Border
Pipeline for construction of The Chicago Project.
The Partnership will make distributions to its partners with respect
to each calendar quarter in an amount equal to 100% of its Available
Cash. "Available Cash" generally consists of all of the cash
receipts of the Partnership adjusted for its cash disbursements and
net changes to cash reserves. Available Cash will generally be
distributed 98% to the Unitholders and 2% to the General Partners.
The holders of Units are entitled to receive the minimum quarterly
distribution of $0.55 per Unit per quarter if and to the extent
there is sufficient Available Cash. Distributions of Available Cash
to the holders of Subordinated Units are subject, while the
Subordinated Units remain outstanding, to the rights of the holders
of the Common Units to receive the minimum quarterly distribution.
The Partnership Policy Committee determined the subordination period
ended as a result of satisfying the criteria set forth in the
partnership agreement. The holders of Subordinated Units are no
longer subordinated to the rights of the holders of Common Units
to receive quarterly distributions and the 6,420,000 outstanding
Subordinated Units have been converted into an equal number of
Common Units effective January 19, 1999.
Partnership income is allocated to the General Partners and the
limited partners in accordance with their respective partnership
percentages, after giving effect to any priority income allocations
for incentive distributions that are allocated 100% to the General
Partners. As an incentive, the General Partners' percentage
interest in quarterly distributions is increased after certain
specified target levels are met. At the time the quarterly
distributions exceed $0.605 per Unit, the General Partners receive
15% of the excess. As the quarterly distributions are increased
above $0.715 per Unit, the General Partners receive increasing
percentages in excess of the targets reaching a maximum of 50% of
the excess of the highest target level (see Note 11).
7. COMMITMENTS AND CONTINGENCIES
Regulatory Proceedings
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 by November 2000 (Project 2000).
Project 2000 would afford shippers on the extended pipeline system
access to industrial gas consumers in northern Indiana. Project
2000 capital expenditures are estimated at $130 million.
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. Northern Border Pipeline filed
the rate case, in compliance with its FERC tariff, for the
determination of its allowed equity rate of return and was
permitted, pursuant to a December 1995 FERC order, to begin
collecting the requested increase in the equity rate of return
effective June 1, 1996, subject to refund. 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, the Stipulation reduced the effective depreciation
rate applied to Northern Border Pipeline's gross transmission plant
from 3.6% to 2.7% for the period June 1, 1996 to December 31, 1996,
which resulted in an average effective depreciation rate of 3.1% for
the year ended December 31, 1996. Beginning January 1, 1997, the
depreciation rate was reduced to 2.5%. 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. Under the terms of the Stipulation,
Northern Border Pipeline agreed to further reduce its depreciation
rate to 2.0% 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.
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 has been
estimated as of the in service date to be $889 million, with the
final construction cost estimated to be $892 million. Thus, Northern
Border Pipeline's report to the FERC and its shippers in late December
1998, reflected the conclusion that, based on information as of that
date, once the budgeted cost has been established, there would be no
adjustment to rate base as a result of the PCCM. Northern Border
Pipeline is obligated by the Stipulation to update its calculation
of the PCCM six months after the in service date of The Chicago
Project. The Stipulation requires the calculation of the PCCM to be
reviewed by an independent national accounting firm. Several
parties to the Stipulation advised the FERC that they may have
questions and desire further information about the report, and may
possibly wish to test it (or the final report) and its conclusions
in an appropriate proceeding in the future. The parties also stated
that if it is determined that Northern Border Pipeline is not permitted
to include certain claimed costs for The Chicago Project in its rate
base, they reserve their rights to seek refunds, with interest, of
any overcollections. Although the Partnership believes the initial
computation has been made in accordance with the terms of the
Stipulation, it is unable to make a definitive determination at this
time whether any adjustments will be required. Should subsequent
developments cause costs not to be recovered pursuant to the PCCM,
a non-cash charge to write down transmission plant may result and
such charge could be material to the operating results of the
Partnership.
During the construction of The Chicago Project, Northern Border
Pipeline placed certain new facilities into service in advance of
the December 1998 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 is reflected on
the consolidated statement of income. The regulatory credit results
in a deferral of the cost of service of these new facilities. The
regulatory asset that resulted from the cost of service deferral is
included in Other Assets on the consolidated balance sheet.
Northern Border Pipeline is allowed to recover the regulatory asset
from its shippers over a ten-year period commencing with the in
service date of The Chicago Project.
Environmental Matters
The Partnership is not aware of any material contingent liabilities
with respect to compliance with applicable environmental laws and
regulations.
Other
Various legal actions that have arisen in the ordinary course of
business are pending. The Partnership believes that the resolution
of these issues will not have a material adverse impact on the
Partnership's results of operations or financial position.
8. CAPITAL EXPENDITURE PROGRAM
Total capital expenditures for 1999 are estimated to be $131
million. This includes approximately $30 million for Project 2000
(see Note 7), approximately $85 million for The Chicago Project and
approximately $16 million for renewals and replacements of the
existing facilities. Approximately $37 million of the capital
expenditures for The Chicago Project is for construction completed
in 1998. Funds required to meet the 1999 capital expenditures are
anticipated to be provided primarily from debt borrowings and
internal sources.
9. NET INCOME PER UNIT
The General Partners' allocation of net income is based on their
combined 2% interest in the Partnership which has been deducted
before calculating net income per Unit. The computation of net
income per Unit is based on the weighted average number of
outstanding Common Units and Subordinated Units.
10. QUARTERLY FINANCIAL DATA (Unaudited)
<TABLE>
<CAPTION>
(In thousands, except Operating Operating Net Income Net Income
per unit amounts) Revenue Income to Partners per Unit
<S> <C> <C> <C> <C>
1998
First Quarter $52,820 $25,650 $14,933 $0.50
Second Quarter 53,782 27,717 16,410 0.55
Third Quarter 54,442 29,722 18,042 0.60
Fourth Quarter 56,548 33,063 18,635 0.62
1997
First Quarter $46,646 $23,818 $13,471 $0.50
Second Quarter 48,069 23,755 12,753 0.48
Third Quarter 52,738 25,737 12,729 0.47
Fourth Quarter 51,121 24,838 14,071 0.51
</TABLE>
11. SUBSEQUENT EVENTS
On January 19, 1999, the Partnership declared an increase in the
quarterly cash distribution from $0.575 per Unit to $0.61 per Unit
for the period October 1, 1998 through December 31, 1998. As
described in Note 6, since the quarterly distribution amount
exceeded $0.605 per Unit, the General Partners were entitled to
receive an incentive distribution for the fourth quarter of 1998 of
approximately $24 thousand. The distribution is payable February
12, 1999, to the General Partners and to the Unitholders of record
at January 29, 1999.
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS ON SCHEDULE
To Northern Border Partners, L.P.:
We have audited in accordance with generally accepted auditing
standards, the consolidated financial statements of Northern Border
Partners, L.P. and Subsidiaries included in this Form 10-K and have
issued our report thereon dated January 19, 1999. Our audits were made
for the purpose of forming an opinion on the basic financial statements
taken as a whole. The schedule of Northern Border Partners, L.P. and
Subsidiaries listed in Item 14 of Part IV of this Form 10-K is the
responsibility of the Company's management and is presented for purposes
of complying with the Securities and Exchange Commission's rules and is
not part of the basic financial statements. This schedule has been
subjected to the auditing procedures applied in the audits of the basic
financial statements and, in our opinion, fairly states in all material
respects the financial data required to be set forth therein in relation
to the basic financial statements taken as a whole.
ARTHUR ANDERSEN LLP
Omaha, Nebraska,
January 19, 1999
<PAGE>
<TABLE>
SCHEDULE II
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
(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
1998 $6,726 $ -- $-- $ -- $6,726
1997 $5,953 $773 $-- $ -- $6,726
1996 $8,200 $ -- $-- $2,247 $5,953
</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, 1998 Commission file
number: 1-12202
NORTHERN BORDER PARTNERS, L.P.
(Exact name of registrant as specified in its charter)
DELAWARE 93-1120873
(State or other jurisdiction (I.R.S. Employer Identification No.)
of incorporation
or organization)
1400 Smith Street, Houston, Texas 77002-7369
(Address of principal executive offices)(zip code)
Registrant's telephone number, including area code: 713-853-6161
___________________
EXHIBIT INDEX
* 3.1 Form of Amended and Restated
Agreement of Limited Partnership of
Northern Border Partners, L.P.
(Exhibit 3.1 No. 2 to the
Partnership's Form S-1 Registration
Statement, Registration No. 33-66158
("Form S-1")).
*10.1 Form of Amended and Restated
Agreement of Limited Partnership
For Northern Border Intermediate
Limited Partnership (Exhibit 10.1 to
Form S-1).
*10.2 Northern Border Pipeline Company
General Partnership Agreement
between Northern Plains Natural Gas
Company, Northwest Border Pipeline
Company, Pan Border Gas Company,
TransCanada Border Pipeline Ltd. and
TransCan Northern Ltd., effective
March 9, 1978, as amended (Exhibit
10.2 to Form S-1).
*10.3 Operating Agreement between Northern
Border Pipeline Company and Northern
Plains Natural Gas Company, dated
February 28, 1980 (Exhibit 10.3 to
Form S-1).
*10.4 Administrative Services Agreement
between NBP Services Corporation,
Northern Border Partners, L.P. and
Northern Border Intermediate Limited
Partnership (Exhibit 10.4 to Form S-1).
*10.5 Note Purchase Agreement between
Northern Border Pipeline Company and
the parties listed therein, dated
July 15, 1992 (Exhibit 10.6 to Form S-1).
*10.5.1 Supplemental Agreement to the Note
Purchase Agreement dated as of June 1, 1995
(Exhibit 10.6.1 to the Partnership's Annual
Report on Form 10-K for the year ended December 31,
1995 ("1995 10-K")).
*10.6 Guaranty made by Panhandle Eastern
Pipeline Company, dated October 31,
1992 (Exhibit 10.9 to Form S-1).
*10.7 Northern Border Pipeline Company
U.S. Shippers Service Agreement
between Northern Border Pipeline
Company and Enron Gas Marketing,
Inc., dated June 22, 1990 (Exhibit
10.10 to Form S-1).
*10.7.1 Amended Exhibit A to Northern Border
Pipeline Company U.S. Shippers
Service Agreement between Northern
Border Pipeline Company and Enron
Gas Marketing, Inc. (Exhibit 10.10.1
to the Partnership's Annual Report
on Form 10-K for the year ended
December 31, 1993 ("1993 10-K")).
*10.7.2 Amended Exhibit A to Northern Border
Pipeline U.S. Shippers Service
Agreement between Northern Border
Pipeline Company and Enron Gas
Marketing, Inc., effective November 1,
1994 (Exhibit 10.10.2 to the
Partnership's Annual Report on Form
10-K for the year ended December 31,
1994).
*10.7.3 Amended Exhibit A's to Northern
Border Pipeline Company U.S. Shipper
Service Agreement effective, August 1,
1995 and November 1, 1995
(Exhibit 10.10.3 to 1995 10-K).
*10.7.4 Amended Exhibit A to Northern Border
Pipeline Company U.S. Shipper
Service Agreement effective April l,
1998 (Exhibit 10.10.4 to the
Partnership's Annual Report on Form
10-K for the year ended December 31,
1997 ("1997 10-K")).
*10.8 Guaranty made by Northern Natural
Gas Company, dated October 7, 1993
(Exhibit 10.11.1 to 1993 10-K).
*10.9 Guaranty made by Northern Natural
Gas Company, dated October 7, 1993
(Exhibit 10.11.2 to 1993 10-K)
*10.10 Northern Border Pipeline Company
U.S. Shippers Service Agreement
between Northern Border Pipeline
Company and Western Gas Marketing
Limited, as agent for TransCanada
PipeLines Limited, dated December 15,
1980 (Exhibit 10.13 to Form S-1).
*10.10.1 Amendment to Northern Border
Pipeline Company Service Agreement
extending the term effective
November 1, 1995 (Exhibit 10.13.1 to
1995 10-K).
*10.11 Form of Seventh Supplement Amending
Northern Border Pipeline Company
General Partnership Agreement
(Exhibit 10.15 to Form S-1).
*10.12 Northern Border Pipeline Company
U.S. Shippers Service Agreement
between Northern Border Pipeline
Company and Transcontinental Gas
Pipe Line Corporation, dated July
14, 1983, with Amended Exhibit A
effective February 11, 1994 (Exhibit
10.17 to 1995 10-K).
*10.13 Form of Credit Agreement among
Northern Border Pipeline Company,
The First National Bank of Chicago,
as Administrative Agent, The First
National Bank of Chicago, Royal Bank
of Canada, and Bank of America
National Trust and Savings
Association, as Syndication Agents,
First Chicago Capital Markets, Inc.,
Royal Bank of Canada, and
BancAmerica Securities, Inc, as
Joint Arrangers and Lenders (as
defined therein) dated as of June
16, 1997 (Exhibit 10(c) to Amendment
No. 1 to Form S-3, Registration
Statement No. 333-40601 ("Form S-3")).
*10.14 Form of Credit Agreement among
Northern Border Partners, L.P.,
Canadian Imperial Bank of Commerce,
as Agent and Lenders (as defined
therein) dated as of November 6,
1997 (Exhibit 10(d) to Amendment No.1
to Form S-3).
*10.15 Northern Border Pipeline Company
U.S. Shippers Service Agreement
between Northern Border Pipeline
Company and Enron Capital & Trade
Resources Corp. dated October 15,
1997 (Exhibit 10.21 to 1997 10-K).
*10.16 Northern Border Pipeline Company
U.S. Shippers Service Agreement
between Northern Border Pipeline
Company and Enron Capital & Trade
Resources Corp. dated October 15,
1997 (Exhibit 10.22 to 1997 10-K).
*10.17 Northern Border Pipeline Company
U.S. Shippers Service Agreement
between Northern Border Pipeline
Company and Enron Capital & Trade
Resources Corp. dated August 5, 1997
with Amendment dated September 25,
1997 (Exhibit 10.25 to 1997 10-K).
*10.18 Northern Border Pipeline Company
U.S. Shippers Service Agreement
between Northern Border Pipeline
Company and Enron Capital & Trade
Resources Corp. dated August 5, 1997
(Exhibit 10.26 to 1997 10-K).
*10.19 Northern Border Pipeline Company
U.S. Shippers Service Agreement
between Northern Border Pipeline
Company and TransCanada Gas Services
Inc., as agent for TransCanada
PipeLines Limited dated August 5,
1997 (Exhibit 10.27 to 1997 10-K).
*10.20 Northern Border Pipeline Company
U.S. Shippers Service Agreement
between Northern Border Pipeline
Company and TransCanada Gas Services
Inc., as agent for TransCanada
PipeLines Limited dated August 5,
1997 (Exhibit 10.28 to 1997 10-K).
21 The subsidiaries of Northern Border
Partners, L.P. are Northern Border
Intermediate Limited Partnership,
Northern Border Pipeline Company,
Black Mesa Holdings, Inc., Black
Mesa Pipeline, Inc., Black Mesa
Pipeline Operations L.L.C. Williams
Technologies, Inc. and Williams
Technologies L.L.C.
23.01 Consent of Arthur Andersen LLP.
*99.1 Northern Plains Natural Gas Company Phantom
Unit Plan (Exhibit 99.1 to Form S-8,
Registration No. 333-66949).
__________
*Indicates exhibits incorporated by reference
as indicated; all other exhibits are filed
herewith.
Exhibit 23.01
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the
incorporation of our reports included in this Annual Report
on Form 10-K, into the Company's previously filed
Registration Statement File No. 333-40601 and Registration
Statement File No. 333-66949.
Omaha, Nebraska,
March 11, 1999
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-END> DEC-31-1998
<CASH> 1,659
<SECURITIES> 39,383
<RECEIVABLES> 21,547
<ALLOWANCES> 0
<INVENTORY> 4,189
<CURRENT-ASSETS> 69,559
<PP&E> 2,345,700
<DEPRECIATION> 615,224
<TOTAL-ASSETS> 1,825,766
<CURRENT-LIABILITIES> 81,439
<BONDS> 974,027
0
0
<COMMON> 0
<OTHER-SE> 507,426
<TOTAL-LIABILITY-AND-EQUITY> 1,825,766
<SALES> 0
<TOTAL-REVENUES> 217,592
<CGS> 0
<TOTAL-COSTS> 101,440
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 49,923
<INCOME-PRETAX> 68,020
<INCOME-TAX> 0
<INCOME-CONTINUING> 68,020
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 68,020
<EPS-PRIMARY> 2.27
<EPS-DILUTED> 2.27
</TABLE>
