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UNITED STATES SECURITIES AND EXCHANGE
COMMISSION
WASHINGTON, D.C. 20549
_______________________
F O R M 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1997 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 (I.R.S.
jurisdiction Employer
of incorporation or Identification
organization) 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 4, 1998, was approximately $756,145,929.
NORTHERN BORDER PARTNERS, L.P.
TABLE OF CONTENTS
Page No.
Part I
Item 1. Business 1
Item 2. Properties 9
Item 3. Litigation 10
Item 4. Submission of Matters to a Vote of Security
Holders 11
Part II
Item 5. Market for Registrant's Common Units and Related
Security Holder Matters 12
Item 6. Selected Financial Data (Unaudited) 13
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations 14
Item 8. Financial Statements 18
Item 9. Disagreements on Accounting and Financial
Disclosure 18
Part III
Item 10. Partnership Management 19
Item 11. Executive Compensation 22
Item 12. Security Ownership of Certain Beneficial Owners
and Management 28
Item 13. Certain Relationships and Related Transactions 28
Part IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K. 30
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"), Pan Border is a wholly-owned subsidiary of Duke
Energy Corporation ("Duke Energy") and Northwest Border is a
wholly-owned subsidiary of The Williams Companies, Inc.
("Williams"). The General Partners hold an aggregate 2%
general partner interest in the Partnership. The General
Partners or their affiliates also own subordinated limited
partner interests ("Subordinated Units") in the Partnership
which, subsequent to an offering of limited partnership
interests in December 1997 and January 1998 (See
"Management's Discussion and Analysis of Financial Condition
and Results of Operations - Liquidity and Capital
Resources"), is an effective 21.4% in the aggregate. The
combined general and limited partner interests in the
Partnership of Enron, Duke Energy and Williams are 11.7%,
7.6% and 4.1%, respectively (See "Certain Relationships and
Related Transactions").
Northern Border Pipeline owns a 969-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
in the State of Iowa. The Pipeline System has pipeline
access to natural gas reserves in the 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 ("syngas") from the
Dakota Gasification Plant in North Dakota. Interconnecting
pipeline facilities provide Northern Border Pipeline
shippers access to markets in the Midwest, as well as other
markets throughout the U.S. by transportation, displacement
and exchange arrangements.
Management of Northern Border Pipeline is overseen by
the Northern Border Management Committee, which is comprised
of three representatives from the Partnership (one selected
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 185 individuals to
operate the Pipeline System. These employees are located at
the operating headquarters in Omaha, Nebraska, and at
locations along the pipeline route. Northern Plains'
employees are not represented by any labor union and are not
covered by any collective bargaining agreements.
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 transports gas for shippers under a tariff
regulated by the Federal Energy Regulatory Commission
("FERC"). Northern Border Pipeline does not own the gas
that it transports and therefore it does not assume any gas
commodity price risk. Currently the shippers provide to
Northern Border Pipeline the linepack gas necessary for its
operations. However, in January 1998, Northern Border
Pipeline filed an application with the FERC to acquire the
linepack in its Pipeline System from its existing shippers
and to provide the linepack in the future. Approximately 5.1
billion cubic feet of linepack gas would be purchased at an
estimated value of $12.5 million. Northern Border Pipeline
has proposed that the cost of the linepack gas be included
in its rate base.
During 1997, the Partnership increased its ownership in
Black Mesa Pipeline Holdings, Inc. ("Black Mesa") to 100% by
its acquisitions of Williams Technologies, Inc. ("WTI") and
the interest held by the remaining stockholder in Black
Mesa. Black Mesa, through a wholly-owned subsidiary, owns a
273-mile, 18-inch diameter coal slurry pipeline (the "Black
Mesa Pipeline") which originates at a coal mine in Kayenta,
Arizona. The pipeline traverses westward through northern
Arizona to the 1,500 megawatt Mohave Power Station located
in Laughlin, Nevada. Black Mesa 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 Black Mesa Pipeline is fully contracted to the coal
supplier for the Mohave Power Station through the year 2005.
Black Mesa is operated by WTI of Tulsa, Oklahoma, a
wholly-owned subsidiary of the Partnership. Approximately 66
people are employed in the operations of Black Mesa and WTI,
of which 26 are represented by a labor union, the United
Mine Workers.
The Pipeline System
The 822-mile 42-inch diameter segment of the Pipeline
System from the Canadian border to Ventura, Iowa was
completed and placed in service in 1982. It was built to
transport large quantities of natural gas through large
diameter, high operating pressure pipe. In 1992, a 30-inch
diameter pipeline, approximately 147 miles in length, was
acquired and placed in-service. This pipeline interconnects
with the original system near Ventura, Iowa and terminates
near Harper, Iowa where it interconnects with the facilities
of Natural Gas Pipeline of America ("NGPL"). There were
seven compressor stations on the Pipeline System as of
December 31, 1997. Other facilities include three pipeline
field offices and warehouses, six major measurement stations
and 39 microwave tower sites. The current throughput
capacity of the Pipeline System is 1,675 million cubic feet
per day ("MMCFD").
At its northern end, the Pipeline System is connected
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
interconnects at multiple points with the pipeline
facilities of an Enron subsidiary, Northern Natural Gas
Company ("Northern Natural"). At its southern end, the
Pipeline System interconnects with the pipeline facilities
of NGPL near Harper, Iowa. The Ventura, Iowa interconnect
functions as a large market center, where gas volumes
transported on the Pipeline System are sold, traded and
received for transport to significant consuming markets in
the Midwest and to interconnecting pipeline facilities
destined for other markets. The Harper, Iowa interconnect
with NGPL also provides access for gas transported through
the Pipeline System to Chicago and other Midwest markets and
to interconnecting pipeline facilities destined for other
markets.
The 822-mile, 42-inch diameter segment of the Pipeline
System was designed (with maximum compression before
looping) to transport up to 2,400 MMCFD. The 147-mile, 30-
inch diameter segment was designed (with maximum compression
before looping) to transport up to 750 MMCFD. The existing
compression on the line allows the transportation of 1,675
MMCFD through the 42-inch segment and 386 MMCFD through the
30-inch segment. As a result, an increase in transportation
capacity could be achieved through the use of additional
compression.
Demand For Transportation Capacity
Northern Border Pipeline's operations are supported by
significant supplies of natural gas in Canada. In 1997,
approximately 87% of the natural gas transported by the
Pipeline System was produced in the Western Canadian
Sedimentary Basin located in the provinces of Alberta,
British Columbia and Saskatchewan. The Pipeline System's
share of Canadian gas exported to the United States was
approximately 20% in 1996. Northern Border Pipeline's
capacity utilization was an average of 102% of summer design
capacity during 1997.
With the existing interconnecting pipeline facilities,
Northern Border Pipeline's transportation of natural gas
produced in Canada primarily reaches gas consuming markets
located in the upper midwestern portion of the United
States. There are currently two other interstate pipelines
that transport Canadian gas into the upper midwest, Great
Lakes Gas Transmission and Viking Gas Transmission, whose
combined share of Canadian gas exported to the United States
was approximately 15% in 1996.
The Chicago Project
Following an open season during which prospective
shippers could submit requests for capacity, Northern Border
Pipeline filed for the requisite authority to construct and
operate extended and expanded facilities ("The Chicago
Project") to its Pipeline System. In August 1997, after
receiving final authorization, Northern Border Pipeline
commenced construction. The project includes extension of
the Pipeline System from Harper, Iowa to near Chicago,
Illinois and expansion of the Pipeline System's capacity.
New transportation contracts entered into in connection with
The Chicago Project provide for additional receipts into the
Pipeline System of 700 MMCFD, with 648 MMCFD to be
transported through the pipeline's extension into Illinois
and 516 MMCFD to be delivered at Harper, Iowa for transport
on another interstate pipeline. The Chicago Project's
estimated construction cost as filed with the FERC is $839 million.
Overall, project activities are estimated to be 40
percent complete. Northern Border Pipeline has completed
the design and engineering for the project and has acquired
a substantial portion of the right-of-way. One, of five
new compressor stations on the 42-inch segment has been
completed and placed in service to maintain gas flow at firm
contracted capacity while an existing compressor station is
being upgraded. The pipeline route includes ten major river
crossings including the Mississippi River crossing that was
completed by directional bore in December 1997.
Construction of the 390 miles of mainline segments is
expected to commence in April. Northern Border Pipeline has
acquired 96% of the right-of-way and fee sites required.
Condemnation actions to acquire right-of-way were filed in
Federal District Court in Illinois in September and October
1997. In two of the Divisions of the Federal District Court,
an order has been entered granting possession of the
right-of-way in litigation. In an action pending in a third
Division, Northern Border Pipeline's motion for immediate
possession was denied. This ruling has been appealed and oral
arguments are scheduled for April 3, 1998 before the Seventh
Circuit Court of Appeals. While the appeal is pending,
Northern Border continues to negotiate the acquisition of
the remaining 4% of the right-of-way and the settlement of
the condemnation litigation.
While the Partnership expects that Northern Border
Pipeline will complete The Chicago Project in the fourth
quarter of 1998 within the budgeted cost, certain events
and conditions could delay completion or increase the
actual cost. These include possible delays in obtaining
necessary rights-of-way and costs and delays due to
inclement weather or other problems in completing the
physical construction of the pipeline facilities.
Under a settlement agreement in a recent rate case,
Northern Border Pipeline agreed to a capital project
cost containment mechanism which would limit its ability
to include cost overruns in its rate base (see "FERC
Regulation - Cost of Service Tariff").
Future Demand and Competition
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 after The Chicago Project is completed.
Approximately fifty bids were submitted. The period of time
in which to resolve bid contingencies was extended to April
30, 1998. If sufficient requests are perfected, a specific
project may be proposed with a targeted in-service date of
November 2000. It is within Northern Border Pipeline's
discretion to determine the scope of and design of the
proposed project. Northern Border Pipeline intends to
limit the size of this project, if necessary, in order to
maintain its competitive rates and a high level of
contracted capacity.
Currently two potentially competitive natural gas
pipeline projects are pending regulatory approval, financing
and construction. If either or both of these projects were
to be authorized, financed and constructed they would
directly compete with Northern Border Pipeline in the
transportation of natural gas from the Western Canadian
Sedimentary Basin to markets in the United States. The
first proposed project, known as the Alliance Pipeline,
received preliminary, non-environmental approval from the
FERC in August 1997. The FERC determination was subject to
final environmental analysis and approval and the receipt by
Alliance Pipeline of regulatory approval from the National
Energy Board of Canada (the "NEB"). Requests for rehearing
of the FERC's preliminary order are currently pending before
the FERC. Regulatory proceedings before the NEB have
commenced; however a decision from the NEB is not expected
before the second quarter of 1998. Environmental analysis
of the Alliance Pipeline is ongoing at the FERC and will
likely be completed in 1998. The second competitive
proposal is known as the Transvoyageur-Viking-Voyageur
project. The application for this project was filed at the
FERC in November 1997. The project's sponsors have
indicated that the application for the Canadian segment of
this project is expected to be filed with the NEB in 1998.
The sponsors of both the Alliance Pipeline and the
Transvoyageur-Viking-Voyageur project propose to originate
their respective pipelines in western Canada and terminate
in the vicinity of Chicago, Illinois. Either of these
projects could be in-service by the year 2000 if timely
regulatory approvals are received and if other conditions
are satisfied.
Shippers
The Pipeline System serves a number of shippers with
diverse financial and market profiles. Based upon existing
contracts (including contracts for The Chicago Project) and
the expanded Pipeline System's projected capacity, 92% of
the firm capacity (based on annual cost of service
obligations) is contracted by producers and marketers. The
remaining firm capacity is contracted to interstate
pipelines (3%) and local distribution companies (5%). At
present, the termination dates of these contracts range from
October 31, 2001 to October 31, 2013. The weighted average
contract life as of December 31, 1997 (based upon annual cost
of service obligations) is slightly over eight years. There
are four contracts totaling 143.25 MMCFD (3.8% of projected
firm capacity) with termination dates of December 31, 2008 or
July 31, 2009 that may be terminated by the shippers if the
production of syngas at the Dakota Gasification Plant is
abandoned by Dakota Gasification Company under its gas
purchase agreements with these shippers.
Firm shippers on the Pipeline System which are
affiliated with general partners of the Partnership or
Northern Border Pipeline are: Enron Capital & Trade
Resources Corp., a subsidiary of Enron; Mobil Natural Gas
Inc., through its marketing arrangement with an affiliate of
Duke Energy; 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 hold 12.6% of the firm capacity.
Based upon the contracts for The Chicago Project, this
percentage may increase to 17.2%.
Northern Border Pipeline's largest shipper, Pan-Alberta
Gas U.S. Inc. ("PAGUS"), currently holds, under three
transportation contracts, 800 MMCFD of capacity or 30% of
the projected firm capacity. Affiliates of Duke Energy and
Enron provide guaranties for 350 MMCFD (150 MMCFD and 200
MMCFD, respectively) of PAGUS' contractual obligations
through October 31, 2001. The PAGUS transportation contract
for 450 MMCFD of capacity is supported by various credit
support arrangements including, among others, a letter of
credit, an additional guaranty from Northern Natural for
100 MMCFD, an escrow account and an upstream capacity
transfer agreement.
At the request of PAGUS, in February 1997 Northern
Border Pipeline filed an application with the FERC to
convert the authority for PAGUS transportation contracts
totaling 800 MMCFD of capacity from individually
certificated transactions to Northern Border Pipeline's
blanket certificate under the FERC regulations. PAGUS
requested this conversion for increased operational
flexibility and to more fully utilize capacity release
provisions of the FERC regulations. Panhandle Eastern Pipe
Line Company, the affiliate of Duke Energy that has provided
a guaranty, filed a motion to intervene and protest
requesting the FERC to convene a technical conference to
determine the effect of the conversion on its obligations
and the appropriate credit support for the contract covering
150 MMCFD. In an order issued December 29, 1997, the FERC
approved the conversion of 650 MMCFD of capacity but denied
the conversion of the contract covering 150 MMCFD of capacity.
This portion of PAGUS' capacity will continue to be transported
as an individually certificated transaction. Because of this
ruling, any extension of the termination date of the
contract covering the 150 MMCFD will need to be approved by
the FERC.
PAGUS has indicated its intent to enter into two year
extensions of its transportation contracts covering 741
MMCFD of capacity on the Pipeline System. If these contract
extensions were implemented, the term of the contracts would
be extended to October 31, 2003. With such extensions, 90%
of projected firm capacity would be contracted through
mid-September 2003. No assurances can be given that the
contracts will be extended. NOVA Corp. announced in
December 1997 its intention to sell the parent company of
PAGUS. In addition, NOVA Corp. and TransCanada have announced
their intention to merge. The Partnership cannot predict the
impact, if any, of these events on the outcome of the possible
contract extensions.
Order 636 (See "FERC Regulation") has created a
secondary market in existing Northern Border Pipeline
capacity. There have been temporary releases of capacity
where the releasing party (which is not relieved of its
obligations under its contract) receives credit against its
firm transportation contract for revenues received as a
result of the temporary release. In addition to the
temporary releases, several shippers have permanently
released a portion of their capacity to other shippers who
have agreed to comply with the underlying contractual and
regulatory obligations associated with such capacity.
FERC Regulation
General
Northern Border Pipeline is subject to extensive
regulation by the FERC as a "natural gas company" under the
Natural Gas Act (the "NGA"). Under the NGA and the Natural
Gas Policy Act ("NGPA"), 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. Rates charged by natural gas
companies may not exceed rates deemed just and reasonable
by the FERC. In addition, natural gas companies
are prohibited 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
charge per dekatherm-mile of capacity contracted, calculated
under a cost of service tariff. Similarly during any given
month, the shippers' obligations to pay their allocable
share of the cost of service is not dependent upon the
percentage of available capacity actually used. 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 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 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' 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
any period when the risk conditions described in the next
paragraph are applicable, all revenue from the interruptible
transportation service is credited back to the firm
shippers' accounts.
Northern Border Pipeline is at risk for the recovery of
the annual cost of service associated with the capacity from
the addition of a compressor station in 1991 and the
addition of four compressor stations and the acquisition of
the 147 mile, 30-inch diameter pipeline in 1992 (See "The
Pipeline System"). In the event that a portion of that
capacity were to become uncontracted, or the government
authorizations to export or import natural gas from Canada
were to lapse, FERC has stated that Northern Border Pipeline
would not be allowed to recover from the remaining firm
shippers on the system that portion of its cost of service
related to those facilities and the uncontracted capacity
associated with these facilities.
The cost of service has been levelized due primarily to
annual depreciation changes. This means that the annual
cost of service, since the effective date of Northern Border
Pipeline's 1992 rate case, was designed to be generally
level until January 1, 1997 when a higher levelized cost of
service was to be effective through 2001. As a result of
Northern Border Pipeline's rate case filed in November 1995
and the proposed change in the depreciation schedule in
conjunction with The Chicago Project, the depreciation rate
applied to Northern Border Pipeline's gross transmission
plant was reduced effective June 1, 1996, from 3.6% to
2.7%. Beginning January 1, 1997, the depreciation rate was
reduced to 2.5%. With the in-service date of The Chicago
Project, the depreciation rate will be 2% and is scheduled
to increase each year until it reaches 3.2% in 2002.
The November 1995 rate case was filed in compliance
with Northern Border Pipeline's FERC tariff for the
determination of its allowed equity rate of return. In this
proceeding, Northern Border Pipeline reached a settlement
accord with shippers holding in excess of 90% of the
aggregate contracted firm capacity as of October 15, 1996
(the "Shippers") and filed for FERC approval of a
Stipulation and Agreement ("Stipulation") to settle its rate
case. The Stipulation was approved by the FERC in August
1997. The Stipulation allowed Northern Border Pipeline to
retain its 12.75% equity rate of return through September
30, 1996, and a 12% rate beginning October 1, 1996. In
addition, the depreciation rates applied to Northern Border
Pipeline's gross transmission plant was reduced as
described in the previous paragraph. Under the Stipulation,
the Shippers agreed that for at least seven years following
the completion of The Chicago Project, Northern Border
Pipeline 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, in connection with the
completion of The Chicago Project, Northern Border Pipeline
will implement a new depreciation schedule with an extended
depreciable life, a capital project cost containment
mechanism and a $31 million settlement adjustment mechanism.
The settlement adjustment mechanism will effectively reduce
the allowed return on rate base. In October 1997, Northern
Border Pipeline made refunds to its shippers in the amount
of $52.6 million, previously reserved, drawing on an
existing $750 million revolving credit facility and
utilizing cash on hand.
Open Access Regulation
The FERC issued Order No. 636 on April 8, 1992, Order
No. 636-A, an order on rehearing of Order 636, on August 3,
1992, and a further order on rehearing, Order No. 636-B, on
November 27, 1992 (together, "Order 636"). Among other
things, Order 636 required companies to unbundle their
services and offer sales, transportation, storage, gathering
and other services separately; to permanently assign their
firm capacity on upstream pipelines to firm shippers wanting
such capacity; and to provide all transportation services on
a basis that is equal in quality for all shippers. Order
636 was substantially affirmed by the United States Court of
Appeals for the District of Columbia.
With respect to the limited aspects of Order 636 that
the court remanded to the FERC, only one issue, the "right
of first refusal" ("ROFR") procedures (imposed by the FERC
as a condition to the pipeline's right to abandon long-term
transportation service), is relevant to Northern Border
Pipeline operations. The ROFR procedures required existing
shippers to match any bid of up to twenty years in order to
retain their capacity. The court upheld the basic structure
of the FERC's rules, but remanded the ROFR mechanism for further
explanation of why a twenty-year term-matching limit was
adopted. The FERC, on remand, adopted a five-year matching
limit. The effect of this ruling on Northern Border
Pipeline's ability to renew or recontract firm capacity
under long-term service agreements once existing agreements
expire cannot be quantified at this time.
During 1996 and 1997, the FERC issued Order Nos. 587,
587-B and 587-C amending its open access regulations to
standardize certain business practices and procedures
governing transactions between interstate natural gas
pipelines, their customers, and others doing business with
the pipelines. These initial business standards, developed
by the Gas Industry Standards Board (GISB), govern important
business practices such as shipper supplied service
nominations, allocation of available capacity, accounting
and invoicing of transportation service, standardized
Internet business transactions, and capacity release.
Northern Border Pipeline has implemented changes to its
tariff and internal systems so it can fully comply with the
business standards as required by these orders.
In Order No. 587-F, a combination of Notice of Proposed
Rulemaking (NOPR) and Statement was issued on November 12,
1997 in which the FERC proposed to further amend its regulations
governing standards for conduction of business practices and
electronic communication with interstate natural gas
pipelines by incorporating the most recent GISB promulgated
standards. In addition, the FERC proposed to adopt
regulations governing intra-day nominations and operational
orders issued by the pipelines. A final order on this NOPR
is expected to be issued during the second quarter of 1998.
Northern Border Pipeline is currently analyzing the impact
such order would have on current business processes and
systems. The Partnership does not expect that compliance
will have a material affect on Northern Border Pipeline's
cost of service.
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. The Partnership believes that its
operations and facilities are in general compliance with
applicable environmental and safety regulations.
Northern Border Pipeline has ongoing environmental and
safety audit programs. As part of the construction of The
Chicago Project, Northern Border Pipeline must comply with
numerous environmental conditions. Northern Border Pipeline
provides environmental training to all construction
personnel. Northern Border Pipeline has obtained the
necessary air quality permits for construction and operation
of the new and upgraded compressor stations and is working
with regulatory agencies through the start-up phases of new
equipment and its operations.
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 and pipeline field office 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. While Northern Border Pipeline had been
advised by attorneys retained by the Fort Peck Tribes that
Northern Border Pipeline may not have a valid right-of-way
across tribal lands, Northern Border's initial analysis of this
claim did not support this conclusion and there has been no
recent correspondence from the attorneys for the Fort Peck
Tribes addressing this claim.
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. The condemnation of
the one tract where a stipulation was not reached has been set
for trial in order to determine the value of the interest being
condemned. 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
In addition to the condemnation actions (See "Business-Demand
for Transportation Capacity-The Chicago Project" and "Properties")
and matters related to the FERC regulation, various legal actions
that have arisen in the ordinary course of business are pending
with respect to Northern Border Pipeline.
The Partnership is not currently a party 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 1997.
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 in
each quarter:
Price Range Cash
High Low Distributions
1997
First Quarter $29.125 $26.125 $0.55
Second Quarter 29.375 26.875 0.55
Third Quarter 33.250 28.500 0.55
Fourth Quarter 35.000 32.063 0.55
1996
First Quarter $25.875 $23.500 $0.55
Second Quarter 24.875 22.875 0.55
Third Quarter 26.125 23.875 0.55
Fourth Quarter 27.375 25.500 0.55
As of February 15, 1998, there were approximately 1,772
record holders of the Partnership's Common Units. There is
no established public trading market for the Partnership's
Subordinated Units. Cash distributions of $0.55 per Unit have
been paid on all Common and Subordinated Units with respect to
all quarters since inception of the Partnership through the
third quarter of 1997. On November 19, 1997, the Partnership
announced its intention to increase the quarterly cash
distribution from $0.55 to $0.60 per Unit (from $2.20 to
$2.40 per Unit on an annualized basis) by the fourth quarter
of 1998. The Partnership effected half of this increase with
a $0.575 per Unit distribution ($2.30 per Unit on an
annualized basis) on all Common and Subordinated Units with
respect to the fourth quarter of 1997. The distribution was
declared January 15, 1998, payable February 13, 1998 to the
General Partners and Unitholders of record at January 30,
1998. The Partnership distributes 100% of its Available Cash
(defined below) within 45 days after the end of each quarter
to Unitholders of record and the General Partners. During a
specified period that will not end earlier than December 31,
1998 (the "Subordination Period"), distributions of
Available Cash on Subordinated Units are subordinated to the
rights of the holders of the Common Units to receive $0.55
per Common Unit per quarter. Under the partnership
agreement, the Subordination Period extends until the first
day of any calendar quarter that occurs on or after January
1, 1999, on which cumulative capital expenditures by the
Partnership subsequent to October 1, 1993 equal or exceed
$248 million and the Partnership has distributed the Minimum
Quarterly Distribution on all Common Units and Subordinated
Units for each of the eight consecutive preceding calendar
quarters. The Partnership anticipates that the
Subordination Period will no longer be in effect as of
January 1, 1999. "Available Cash" consists generally of
all of the cash receipts of the Partnership adjusted for
its cash disbursements and net changes to cash reserves.
A full definition of Available Cash and the Subordination
Period is set forth in the Partnership Agreement, a form of
which is filed as an Exhibit hereto.
Item 6. Selected Financial Data (Unaudited)
(in thousands, except per Unit and operating data)
On October 1, 1993, the Partnership acquired a 70% general partner
interest in Northern Border Pipeline. Prior to October 1, 1993, the
Partnership had no financial statements. The following selected
financial data labeled "Historical (Predecessor)" represent the income
data, cash flow data, balance sheet data and operating data of Northern
Border Pipeline, the Partnership's predecessor company as defined under
the regulations of the Securities and Exchange Commission ("SEC"). As
discussed in Item 1, in May 1997, the Partnership acquired WTI and
increased its ownership interest in Black Mesa. The operations of Black
Mesa and WTI are included in the Partnership's consolidated results of
operations and financial position from that point forward.
Historical
Partnership (Predecessor)
Pro Forma Three Nine
Year Months Months
Ended Ended Ended
Year Ended December 31, December 31, December 31, September 30,
1997 1996 1995 1994 1993 1993 1993
INCOME DATA:
Operating revenue $ 198,574 $ 201,943 $ 206,497 $ 211,580 $ 205,241 $ 53,148 $ 152,093
Operations and
maintenance 37,418 28,366 26,730 28,919 27,210 7,424 18,661
Depreciation and
amortization 40,172 46,979 47,081 41,959 39,539 10,489 29,050
Taxes other than
income 22,836 24,390 23,886 24,438 21,393 5,582 15,811
Operating income 98,148 102,208 108,800 116,264 117,099 29,653 88,571
Interest expense 34,520 33,117 35,205 38,424 40,671 10,054 30,617
Other income (expense) 11,649 3,347 568 (1,340) (784) (1,209) 425
Minority interests in
net income 22,253 22,153 22,360 23,147 22,622 5,108 --
Net income
to partners $ 53,024 $ 50,285 $ 51,803 $ 53,353 $ 53,022 $ 13,282 $ 58,379
Net income per Unit $ 1.97 $ 1.88 $ 1.94 $ 2.00 $ 1.98 $ .50 $ --
Number of units used
in computation 26,392 26,200 26,200 26,200 26,200 26,200 --
CASH FLOW DATA:
Net cash provided by
operating activities $ 119,621 $ 137,534 $ 127,078 $ 121,088 $ 116,530 $ 35,184 $ 82,471
Capital expenditures 152,658 18,597 8,411 2,985 1,268 528 739
Distribution per Unit 2.20 2.20 2.20 2.20 -- -- --
BALANCE SHEET DATA
(AT END OF PERIOD):
Net property, plant
and equipment $1,118,364 $ 937,859 $ 957,587 $ 983,842 $ -- $1,015,567 $1,023,725
Total assets 1,266,917 1,016,484 1,041,339 1,083,468 -- 1,115,768 1,096,099
Long-term debt,
including current
maturities 481,355 377,500 410,000 445,000 -- 470,000 470,000
Minority interests in
partners' capital 174,424 158,089 166,789 173,984 -- 177,089 --
Partners' capital 500,728 410,586 419,117 426,130 -- 431,593 597,587
OPERATING DATA:
Northern Border Pipeline:
MMCF of gas delivered 633,280 633,908 615,133 597,898 570,469 142,040 428,429
Average throughput (MMCFD) 1,770 1,764 1,720 1,663 1,592 1,581 1,596
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations
Results of Operations
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 (8%) due primarily to
lower depreciation and amortization expense, taxes other than
income and returns on a lower rate base. These lower recoveries
were partially offset by higher operations and maintenance
expense recoveries. 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. Additionally, in accordance with the Stipulation
approved by the FERC to settle Northern Border Pipeline's 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"). Operating revenue from the
combined operations of Black Mesa and WTI was $12.5 million for
the year ended December 31, 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 from the combined
operations of Black Mesa and WTI. Operations and maintenance
expense attributable to Northern Border Pipeline increased $1.5
million (6%) 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
(18%). 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 from the combined operations of Black Mesa and WTI was
$1.5 million for the year ended December 31, 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 (8%) due primarily to
lower property tax assessments received in various states where
the pipeline system operates. Taxes other than income from the
combined operations of Black Mesa and WTI was $0.4 million for
the year ended December 31, 1997.
Interest expense increased $1.4 million for the year ended
December 31, 1997, as compared to the results for the same period
in 1996 due primarily to interest expense from the combined
operations of Black Mesa and WTI.
Other income increased $8.3 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 $4.2 million increase in the allowance for funds used
during construction. The increase in the allowance for funds
used during construction primarily relates to Northern Border
Pipeline's expenditures for The Chicago Project (See "Cash Flows
From Investing Activities").
Year Ended December 31, 1996 Compared With the Year Ended
December 31, 1995
Operating revenue decreased $4.6 million (2%) for the year
ended December 31, 1996, as compared to the results for the
comparable period in 1995, due primarily to equity returns on a
lower rate base and lower interest expense. These lower
recoveries were partially offset by higher operations and
maintenance expense recoveries. Operating revenue for 1996
reflects the terms of the Stipulation filed by Northern Border
Pipeline for FERC approval, which was subsequently approved by
the FERC in 1997, to settle its rate case (See "Business-FERC
Regulation-Cost of Service Tariff").
Operations and maintenance expense increased $1.6 million (6%)
for the year ended December 31, 1996, from the comparable period
in 1995 due primarily to expenses incurred in conjunction with
Northern Border Pipeline's rate case proceeding as well as higher
administrative expenses.
Depreciation and amortization expense remained constant for
the year ended December 31, 1996, as compared to the results for
the same period in 1995. Depreciation and amortization expense
for 1996 was reduced approximately $7.4 million from the level
authorized in Northern Border Pipeline's FERC tariff to reflect
the Stipulation discussed above, which resulted in an average
depreciation rate for transmission plant of 3.1% for the year
ended December 31, 1996 and matched the rate used in 1995. In
accordance with the terms of the Stipulation, the depreciation
rate applied to Northern Border Pipeline's gross transmission
plant was reduced to 2.7% effective June 1996 from the 3.6% rate
in its FERC tariff.
Interest expense decreased $2.1 million (6%) for the year
ended December 31, 1996, as compared to the results for the same
period in 1995 due to a decrease in the average debt outstanding.
Average debt outstanding had decreased between the two periods
reflecting principal payments of $32.5 million made under the
Northern Border Pipeline bank loan agreement.
Other income increased $2.8 million for the year ended
December 31, 1996, from results for the year ended December 31,
1995, primarily due to the reversal of previously established
reserves for regulatory issues.
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. At December 31, 1997, $127.5 million and
$81.5 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 required 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. After The Chicago Project has
been placed in service, the Partnership Credit Agreement allows
the Partnership to borrow any undrawn amounts up to an aggregate
principal amount of $40 million for general business purposes.
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, 1997,
the Partnership had not borrowed on the Partnership Credit
Agreement.
In November 1997, the Partnership filed a registration
statement with the SEC for a proposed offering of $225 million in
Common Units. 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 will be 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 $7.5
million.
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 statement filed
in November 1997 or separate registrations.
Cash Flows From Operating Activities
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 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 provided by operating activities increased $10.5
million to $137.5 million for the year ended December 31, 1996 as
compared to the same period in 1995, due primarily to amounts
collected subject to refund by Northern Border Pipeline as a
result of its rate case.
Cash Flows From Investing Activities
Capital expenditures of $152.7 million for the year ended
December 31, 1997, include $135.7 million for The Chicago
Project (See "Business-Demand for Transportation Capacity-The
Chicago Project"). The remaining $17.0 million of capital
expenditures for 1997 are primarily related to renewals and
replacements of Northern Border Pipeline's existing facilities.
For the comparable period in 1996, capital expenditures were
$18.6 million, which included $11.8 million for The Chicago
Project, and $6.8 million primarily related to renewals and
replacements of Northern Border Pipeline's existing facilities.
Total capital expenditures for 1998 are estimated to be $637
million for The Chicago Project. The estimated cost of The
Chicago Project as filed with the FERC is approximately $839
million and it is expected to be ready for service in the fourth
quarter of 1998. An additional $9 million of 1998 capital
expenditures is planned for renewals and replacements of the
existing facilities. Capital expenditures for linepack gas, if
the filing to acquire the linepack is approved by the FERC,
would be approximately $12.5 million in 1998 (See "Business-
General"). Northern Border Pipeline anticipates funding
approximately 65% of its 1998 capital expenditures by borrowing
on the Pipeline Credit Agreement. 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 is related primarily to the
consolidation of Black Mesa's cash balance.
Cash Flows From Financing Activities
Cash flows provided by financing activities were $95.6 million
for the year ended December 31, 1997, as compared to cash flows
used in financing activities of $112.2 million for the year ended
December 31, 1996. Financing activities for 1997 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. 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 1997 also reflect a $24.3 million
capital contribution from minority interest holders to Northern
Border Pipeline. In 1996, net principal reductions on Northern
Border Pipeline's bank loan agreements totaled $22.5 million.
Computer Systems and the Year 2000
As a result of computer programs being written using two
digits rather than four to define the applicable year, computer
programs that have date-sensitive software may recognize a date
using "00" as the year 1900 rather than the year 2000. The
Partnership continues to assess and modify its computer systems
to ensure they will operate properly in 2000. Management
anticipates that resulting costs, which will be incurred over the
next two years, will not have a material impact on the
Partnership's financial position or results of operations.
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-Demand for Transportation
Capacity-The Chicago Project", "Business-Demand for
Transportation Capacity-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 "Market for the Registrant's Common Units
and Related Security Holder Matters" regarding intentions to
increase the quarterly cash distribution 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 political and regulatory developments that
impact FERC and state utility commission proceedings, Northern Border
Pipeline's success in sustaining its positions in such
proceedings or the success of intervenors in opposing Northern
Border Pipeline's positions, 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 and conditions of the capital markets and
equity markets during the periods covered by the forward looking
statements.
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 utilizes 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. 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 56 Chief Executive Officer
Jerry L. Peters 40 Chief Financial and
Accounting Officer
Members of Partnership Policy
Committee and Partnership's
representatives on Northern
Border Management Committee:
Larry L. DeRoin 56 Chairman of Partnership
(Northern Plains) Policy Committee and
Northern Border Management
Committee
George L. Mazanec 62 Member of Partnership Policy
(Pan Border) Committee and Northern
Border Management Committee
Brian E. O'Neill 62 Member of Partnership Policy
(Northwest Border) Committee and Northern
Border Management Committee
Members of Audit
Committee:
Daniel P. Whitty 66 Chairman of Audit Committee
Gerald B. Smith 47 Member of Audit Committee
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.
George L. Mazanec was appointed to the Partnership Policy
Committee in July 1993. Mr. Mazanec is an Advisor to the Chief
Operating Officer of Duke Energy. From December 1993 to
December 1996, he was the Vice Chairman of the Board of Directors
of PanEnergy Corp (PanEnergy), the predecessor to Duke Energy, and
had been a director since December 1992. He is a director of
Texas Eastern Products Pipeline Company, the general partner of
TEPPCO Partners, L.P. From March 1991 to December 1993, he was
Executive Vice President of PanEnergy. From 1989 to 1991, he was
Group Vice President of PanEnergy and from 1987 to 1989, he was
Senior Vice President of Texas Eastern Corporation and Texas
Eastern Transmission Company. He is a director of National Fuel
Gas Company, Associated Electric & Gas Insurance Services Limited
and Northern Trust Bank of Texas. He is Chairman of the management
committee of the Maritimes & Northeast Pipeline. He has served on
the Northern Border Management Committee since 1991.
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 Interstate Natural Gas Systems, 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 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 Corp.,
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:
Summary Compensation Table
All Other
Annual Compensation Long-Term Compensation Compensation
Other Securities
Annual Restricted Underlying LTIP
Compensation Stock Options/ Payouts
Name & Position Year Salary Bonus (1) Awards (2) SARs (#) (3) (4)
Larry L. DeRoin 1997 $247,333 $200,000 $11,908 $ - 15,285 $ - $ -
Chief Executive 1996 $239,667 $144,000 $ 6,900 $ - 18,220 $ 56,250 $ 1,102
Officer 1995 $235,000 $128,500 $ 8,294 $ - 14,550 $150,000 $ 793
Jerry L. Peters 1997 $118,750 $ 47,500 $ 1,200 $ - 5,715 $ - $ -
Chief Financial and 1996 $114,525 $ 28,000 $ - $ - 5,045 $ - $ 767
Accounting Officer 1995 $104,900 $ 15,000 $ - $ - 2,655 $ - $ 552
(1) Includes "Perquisites and Other Personal Benefits" if value
is greater than the lesser of $50,000 or 10% of reported
salary and bonus. Also, Enron maintains three deferral plans
for key employees under which payment of base salary, annual
bonus and long-term incentive awards may be deferred to a
later specified date. Under the 1985 Deferral Plan, interest
is credited on amounts deferred based on 150% of Moody's
seasoned corporate bond yield index with a minimum rate of
12%, which for 1995 was 12.39%, for 1996 was the minimum rate
of 12.0%, and for 1997 was the minimum rate of 12.0%. No
interest has been reported as Other Annual Compensation under
the 1985 Deferral Plan for the participating Named Officers
because the crediting rates during 1995, 1996, and 1997 were
9.91%, 7.65%, and 8.15%, respectively, and did not exceed
120% of the long-term Applicable Federal Rate ("AFR") in
effect in January, 1985 when the Deferral Plan was
implemented. No interest has been reported as Other Annual
Compensation under the 1992 Deferral Plan, as none of the
named officers are participants in the Plan. Interest in
excess of 120% of the December, 1993 long-term Applicable
Federal Rate ("AFR") (7.29%) has been reported as Other
Annual Compensation under the 1994 Deferral Plan during 1995
for the participating Named Officers. Beginning January 1,
1996, the 1994 Deferral Plan credits interest based on fund
elections chosen by participants. Since earnings on deferred
compensation invested in third-party investment vehicles,
comparable to mutual funds, need not be reported, no interest
has been reported as Other Annual Compensation under the 1994
Deferral Plan during 1996 and 1997. Other Annual Compensation
also includes cash perquisite allowances.
(2) The Named Officers had no unreleased restricted stock
holdings as of December 31, 1997.
(3) The amounts shown for 1995 and 1996 for Mr. DeRoin represent
payouts made under Enron's Performance Unit Plan.
(4) The amounts shown include the value, as of year-end 1995 and
1996, of Enron Common Stock allocated during those years to
employees' special subaccounts under Enron's Employee Stock
Ownership Plan.
Stock Option Grants During 1997
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 1997.
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%
Larry L DeRoin 5,025 (2) 0.03% $44.5000 01/21/02 $- $ 61,780 $ 136,518
10,260 (3) 0.06% $41.5625 12/31/04 $- $ 173,600 $ 404,563
Jerry L. Peters 3,215 (2) 0.02% $44.5000 01/21/02 $- $ 39,527 $ 87,344
2,500 (4) 0.01% $41.5625 12/31/07 $- $ 65,346 $ 165,600
All Employee and
Director Optionees 16,929,185 (7) 100% $40.4740 (8) N/A $- $ 430,913,782 (9) $ 1,092,020,126 (9)
All Stockholders N/A N/A N/A N/A $- $7,821,684,107 (9) $19,821,683,169 (9)
Optionee Gain as %
of All Stockholders
Gain N/A N/A N/A N/A N/A 5.51% 5.51%
(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 bonus stock options that are five year grants and
became 100% vested on January 21, 1997.
(3) Represents stock options awarded under the Long-Term
Incentive Program for 1998. Grants under this program are
granted on the last trading day of the prior year, due to
regulations under Section 162(m). Options are seven year
grants and became 20% vested on the date of grant with an
additional 20% vested on the anniversary of the date of grant
until December 31, 2001.
(4) Represents stock options awarded to key employees below the
Executive Compensation group. Options are ten year grants
and became 20% vested on the date of grant with an additional
20% vested on the anniversary of the date of grant until
December 31, 2001.
(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, 1997 under the All
Employee Stock Option Program to employees hired during 1997
including Portland General Corporation employees.
(8) Weighted average exercise price of all Enron stock options
granted to employees in 1997.
(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 ($40.4740) and the number of shares of Common Stock
issued and outstanding on December 31, 1997 excluding
3,958,072 shares held by the Enron Flexible Equity Trust.
Aggregated Stock Option/SAR Exercises During 1997 and Stock
Option/SAR Values as of December 31, 1997
The following table sets forth information with respect to
the Named Officers concerning the exercise of Enron SARs and
options during the last fiscal year and unexercised Enron options
and SARs held as of the end of the fiscal year:
Number of Securities
Underlying Unexercised Value of Unexercised
Shares Options/SARs at In-the-Money Options/
Acquired on Value December 31, 1997 SARs at December 31, 1997
Name Exercise (#) Realized Exercisable Unexercisable Exercisable Unexercisable
Larry L. DeRoin - $ - 133,878 24,622 $2,181,526 $ 83,650
Jerry L. Peters 1,100 $28,931 17,248 4,142 $ 142,769 $ 15,399
Long-Term Incentive Plan - Awards in 1997
The following table provides information concerning awards of
performance units under Enron's Performance Unit Plan during
1997. Mr. Peters is not a participant in this plan. 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 stockholder
return is compared to that of the 11 peer companies included in
the Peer Group. At that time, the units are assigned a value
ranging from $0 to $2.00 based on the rank of Enron's stockholder
return within the Peer Group. To be valued at the maximum of
$2.00, Enron must rank first, and to be valued at the target of
$1.00, Enron must rank third. Regardless of Enron's rank,
Enron's stockholder return must be above the return on 90-day
U.S. Treasury Bills over the same performance period in order for
any value to be assigned.
Number of Shares, Performance or Estimated Future Payouts
Units or Other Other Period Until Under Non-Stock Price-Based Plans
Name Rights (#) Maturation Payout Threshold ($) Target ($) Maximum ($)
Larry L. DeRoin 100,000 4 years $ - $100,000 $200,000
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.
Estimated
Current Credited Current Estimated
Credited Years of Compensation Annual Benefit
Years of Service Covered Payable Upon
Service at Age 65 By Plans Retirement
Mr. DeRoin 30.3 39.0 $250,000 $137,601
Mr. Peters 12.9 37.8 $123,600 $ 72,367
NOTE: The estimated annual benefits payable are based on the
straight life annuity form without adjustment for any offset
applicable to a participant's retirement subaccount in
Enron's ESOP.
Mr. DeRoin participates in the Executive Supplemental
Survivor Benefit Plan. In the event of death after retirement,
the Plan provides an annual benefit to the participant's
beneficiary equal to 50 percent of the participant's annual base
salary at retirement, paid for 10 years. The Plan also provides
that in the event of death before retirement, the participant's
beneficiary receives an annual benefit equal to 30% of the
participant's annual base salary at death, paid for the life of
the participant's spouse (but for no more than 20 years in some
cases).
Severance Plans
Enron's Severance Pay Plan, as amended, provides for the
payment of benefits to employees who are terminated for failing
to meet performance objectives or standards or who are terminated
due to reorganization or economic factors. The amount of
benefits payable for performance related terminations is based on
length of service and may not exceed six weeks' pay. For those
terminated as the result of reorganization or economic
circumstances, the benefit is based on length of service and
amount of pay up to a maximum payment of 26 weeks of base pay.
If the employee signs a Waiver and Release of Claims Agreement,
the severance pay benefits are doubled. Under no circumstances
will the total severance pay benefit exceed 52 weeks of pay.
Under the Enron Corp. Change of Control Severance Plan, in the
event of an unapproved change of control of Enron, any employee
who is involuntarily terminated within two years following the
change of control will be eligible for severance benefits equal
to two weeks of base pay multiplied by the number of full or
partial years of service, plus one month of base pay for each
$10,000 (or portion of $10,000) included in the employee's annual
base pay, plus one month of base pay for each five percent of
annual incentive award opportunity under any approved plan. The
maximum an employee can receive is 2.99 times the employee's
average W-2 earnings over the past five years.
Item 12. Security Ownership of Certain Beneficial
Owners and Management
The following table sets forth the beneficial ownership of
the voting securities of the Partnership as of February 15, 1998
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.
Amount and Nature of Beneficial Ownership
Common Units Subordinated Units
Number Percent Number Percent
of Units1/ of Class of Units of Class
Larry L. DeRoin 10,000 *
Jerry L. Peters 1,300 *
George L. Mazanec 2,500 *
Brian E. O'Neill -
Daniel P. Whitty -
Gerald B. Smith -
The Williams Companies, 1,123,500 17.5
Inc.2/
One Williams Center
Tulsa, OK 74101-3288
Enron Corp.2/ 3,210,000 50.0
1400 Smith Street
Houston, TX 77002
Duke Energy Corp.2/ 2,086,500 32.5
422 So. Church St.
Charlotte, NC 88242-0001
______________
* Less than 1%.
1/ All units involve sole voting and investment power.
2/ Indirect ownership through their subsidiaries.
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 an affiliate 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 including The Chicago Project
pursuant to the terms of an Operating Agreement between Northern
Plains and Northern Border Pipeline. In addition, as of March 1,
1998, (i) Enron Capital & Trade Resources Corp., an affiliate of
Enron, is a transportation customer of Northern Border Pipeline,
which is obligated to pay 2.4% 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 17.2%
of Northern Border Pipeline's annual cost of service; (iii) Duke
Energy Trading and Market Services L.L.C., a joint venture
affiliate of Duke Energy is the agent for the transportation
contract with Mobil Natural Gas Inc. which is obligated to pay
1.8% of Northern Border Pipeline's annual cost of service; (iv)
Panhandle Eastern Pipe Line Company, an affiliate of Duke Energy,
provides a financial guaranty for a portion (150 MMCFD) of the
transportation capacity held by PAGUS, which in turn represents
10.7% of Northern Border Pipeline's annual cost of service; (v)
TransCanada Gas Services Inc. ("TransCanada Gas Services"), an
affiliate of TransCanada, is a transportation customer of
Northern Border Pipeline which is obligated to pay 7.2% 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 1.2% of Northern Border Pipeline's annual cost
of service. In addition, Duke Energy Trading and Market Services
L.L.C. and Cibola Energy Services Corporation, an affiliate of
TransCanada are transportation customers under temporary releases
from firm transportation shippers.
The Partnership Policy Committee, whose members are
appointed by the three General Partners, establishes the business
policies of the Partnership, and each General Partner has a right
to appoint a representative to the Northern Border Management
Committee, each of which will vote a portion of the Partnership's
voting interest on the Northern Border Management Committee.
Certain conflicts of interest could arise as a result of the
relationships among the General Partners, their respective
parents and other affiliates, TransCanada, its affiliates, the
Unitholders and Northern Border Pipeline. The directors and
officers of Enron, Duke Energy, Williams and TransCanada have
fiduciary duties to manage their respective companies, including
their investments in their respective affiliates and
subsidiaries, in a manner beneficial to their respective
shareholders. In addition, (i) the members of the Partnership
Policy Committee have a fiduciary duty to manage the Partnership
in a manner beneficial to the Unitholders, (ii) the Partnership's
representatives on the Northern Border Management Committee have
a fiduciary duty to manage Northern Border Pipeline in a manner
beneficial to the Partnership, and (iii) the Partnership has a
fiduciary duty to the subsidiaries of TransCanada, as partners in
Northern Border Pipeline, which duty is also owed by TransCanada
to the Partnership. The Partnership Agreement contains
provisions that allow the General Partners and the Partnership
Policy Committee to take into account the interests of parties in
addition to the Partnership in resolving conflicts of interest,
thereby limiting their duties to the Partnership and the
Unitholders, as well as provisions that may restrict the remedies
available to Unitholders for actions taken that might, without
such limitations, constitute breaches of duty. The 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 such General Partner and its affiliates
(or the member of the Partnership Policy Committee designated by
it), on the one hand, and the Partnership or the Unitholders, on
the other. In addition, with respect to the fiduciary duties
owed by the Partnership and the subsidiaries of TransCanada to
each other as partners in Northern Border Pipeline, (i) the
fiduciary duty owed by the Partnership to such subsidiaries of
TransCanada may restrict the ability of the Partnership Policy
Committee to cause the Partnership to take certain actions that
might be in the best interests of the Partnership, but in
conflict with the fiduciary duty owed by the Partnership to such
subsidiaries of TransCanada and (ii) the duty of the directors
and officers of each of the parent companies of such subsidiaries
of TransCanada to its shareholders may conflict with the duty
owed by such subsidiaries of TransCanada to the Partnership as a
partner in Northern Border Pipeline.
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 Amended and Restated Loan Agreement among
Northern Border Pipeline Company, the
Banks (as defined therein), Canadian
Imperial Bank of Commerce, New York
Agency and Bank of America National Trust
& Savings Association, dated July 15,
1992 (Exhibit 10.5 to Form S-1).
*10.5.1 Letter Amendment to Amended and Restated
Loan Agreement effective as of September
21, 1993 (Exhibit 10.5.1 to the
Partnership's Annual Report on Form 10-K
for the year ended December 31, 1993
("1993 10-K")).
*10.5.2 Letter Amendment to Amended and Restated
Loan Agreement effective as of September
9, 1994 (Exhibit 10.5.2 to the
Partnership's Annual Report on Form 10-K
for the year ended December 31, 1994
("1994 10-K")).
*10.5.3 Letter Amendment to Amended and Restated
Loan Agreement dated May 18, 1995
(Exhibit 10.5.3 to the Partnership's
Annual Report on Form 10-K for the year
ended December 31, 1995 ("1995 10-K")).
*10.6 Note Purchase Agreement between Northern
Border Pipeline Company and the parties
listed therein, dated July 15, 1992
(Exhibit 10.6 to Form S-1).
*10.6.1 Supplemental Agreement to the Note
Purchase Agreement dated as of June 1,
1995 (Exhibit 10.6.1 to 1995 10-K).
*10.7 Consent and Agreement of the Partners
among Northern Plains Natural Gas
Company, Northwest Border Pipeline
Company, Pan Border Gas Company,
TransCanada Border PipeLine Ltd. and
Canadian Imperial Bank of Commerce, New
York Agency, dated February 28, 1990
(Exhibit 10.7 to Form S-1).
*10.8 Consent and Agreement of the Partners
among TransCanada Border PipeLine Ltd.,
TransCan Northern Ltd. and Canadian
Imperial Bank of Commerce, New York
Agency, dated April 19, 1991 (Exhibit
10.8 to Form S-1).
*10.9 Guaranty made by Panhandle Eastern
Pipeline Company, dated October 31, 1992
(Exhibit 10.9 to Form S-1).
*10.10 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).
*10.10.1 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 1993 10-K).
*10.10.2 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 1994
10-K).
*10.10.3 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).
10.10.4 Amended Exhibit A to Northern Border
Pipeline Company U.S. Shipper Service
Agreement effective April l, 1998.
*10.11.1 Guaranty made by Northern Natural Gas
Company, dated October 7, 1993 (Exhibit
10.11.1 to 1993 10-K).
*10.11.2 Guaranty made by Northern Natural Gas
Company, dated October 7, 1993 (Exhibit
10.11.2 to 1993 10-K).
*10.12 Northern Border Pipeline Company U.S.
Shippers Service Agreement between
Northern Border Pipeline Company and
Northern Natural Gas Company, dated
August 25, 1988 (Exhibit 10.12 to Form S-1).
*10.12.1 Amendment to Northern Border Pipeline
Company U.S. Shippers Service Agreement
effective October 1, 1993. (Exhibit
10.12.1 to 1993 10-K).
*10.12.2 Amendment to Northern Border Pipeline
Company U.S. Shippers Service Agreement
terminating the Agreement as of November
1, 1994 (Exhibit 10.12.2 to 1994 10-K).
*10.13 Northern Border Pipeline Company U.S.
Shippers Service Agreement between
Northern Border Pipeline Company and
Western Gas Marketing Limited, as agent
for TransCanada PipeLines Limited, dated
December 15, 1980 (Exhibit 10.13 to Form
S-1).
*10.13.1 Amendment to Northern Border Pipeline
Company Service Agreement extending the
term effective November 1, 1995 (Exhibit
10.13.1 to 1995 10-K).
*10.14 Form of Credit Agreement between Northern
Border Partners, L.P., as borrower, and
Northern Plains Natural Gas Company,
Northwest Border Pipeline Company and Pan
Border Gas Company, as lenders (Exhibit
10.14 to Form S-1).
*10.15 Form of Seventh Supplement Amending
Northern Border Pipeline Company General
Partnership Agreement (Exhibit 10.15 to
Form S-1).
*10.16 Form of Conveyance, Contribution and
Assumption Agreement among Northern
Plains Natural Gas Company, Northwest
Border Pipeline Company, Pan Border Gas
Company, Northern Border Partners, L.P.,
and Northern Border Intermediate Limited
Partnership (Exhibit 10.16 to Form S-1).
*10.17 Northern Border Pipeline Company U.S.
Shippers Service Agreement between
Northern Border Pipeline Company and
Transcontinental Gas Pipe Line
Corporation, dated July 14, 1983, with
Amended Exhibit A effective February 11,
1994 (Exhibit 10.17 to 1995 10-K).
*10.18 Northern Border Pipeline Company U.S.
Shippers Service Agreement dated August
30, 1991 between Northern Border Pipeline
Company and Mobil Natural Gas, Inc., with
Amended Exhibit A effective April 29,
1994 and designation of agent effective
August 1, 1996 (Exhibit 10-18 to the
Partnership's Annual Report on Form 10-K
for the year ended December 31, 1996).
*10.19 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")).
*10.20 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).
10.21 Northern Border Pipeline Company U.S.
Shippers Service Agreement between
Northern Border Pipeline Company and
Enron Capital & Trade Resources Corp.
dated October 15, 1997.
10.22 Northern Border Pipeline Company U.S.
Shippers Service Agreement between
Northern Border Pipeline Company and
Enron Capital & Trade Resources Corp.
dated October 15, 1997.
10.23 Northern Border Pipeline Company U.S.
Shippers Service Agreement between
Northern Border Pipeline Company and
PanEnergy Trading and Market Services,
L.L.C., now known as Duke Trading and
Market Services L.L.C., dated August 14,
1997.
10.24 Northern Border Pipeline Company U.S.
Shippers Service Agreement between
Northern Border Pipeline Company and
PanEnergy Trading and Market Services,
L.L.C., now known as Duke Trading and
Market Services L.L.C., dated August 14,
1997.
10.25 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.
10.26 Northern Border Pipeline Company U.S.
Shippers Service Agreement between
Northern Border Pipeline Company and
Enron Capital & Trade Resources Corp.
dated August 5, 1997.
10.27 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.
10.28 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 14, 1997.
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., and Williams Technologies, Inc.
23.01 Consent of Arthur Andersen LLP.
__________
*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 1997.
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 27th day of March, 1998.
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 27, 1998
Larry L. DeRoin Chairman of the Partnership
Policy Committee
(Principal Executive Officer)
GEORGE L. MAZANEC Member of Partnership Policy March 27, 1998
George L. Mazanec Committee
BRIAN E. O'NEILL Member of Partnership Policy March 27, 1998
Brian E. O'Neill Committee
JERRY L. PETERS Chief Financial and March 27, 1998
Jerry L. Peters Accounting Officer
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
INDEX TO FINANCIAL STATEMENTS
Page No.
Consolidated Financial Statements
Report of Independent Public Accountants F-2
Consolidated Balance Sheet - December 31, 1997 and 1996 F-3
Consolidated Statement of Income - Years Ended F-4
December 31, 1997, 1996 and 1995
Consolidated Statement of Cash Flows - Years Ended F-5
December 31, 1997, 1996 and 1995
Consolidated Statement of Changes in Partners' Capital - F-6
Years Ended December 31, 1997, 1996 and 1995
Notes to Consolidated Financial Statements F-7 through
F-17
Financial Statements Schedule
Report of Independent Public Accountants on Schedule S-1
Schedule II - Valuation and Qualifying Accounts S-2
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Northern Border Partners, L.P.:
We have audited the accompanying consolidated balance sheets of
Northern Border Partners, L.P., a Delaware limited partnership,
and Subsidiaries as of December 31, 1997 and 1996, 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, 1997. 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, 1997 and 1996, and the results of their operations and their
cash flows for each of the three years in the period ended
December 31, 1997, in conformity with generally accepted
accounting principles.
ARTHUR ANDERSEN LLP
Omaha, Nebraska,
January 26, 1998
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(In Thousands)
December 31,
ASSETS 1997 1996
CURRENT ASSETS
Cash and cash equivalents $ 106,757 $ 41,390
Accounts receivable 18,139 16,907
Related party receivables 1,780 2,364
Materials and supplies, at cost 4,458 4,128
Total current assets 131,134 64,789
TRANSMISSION PLANT
Property, plant and equipment 1,749,862 1,513,116
Less: Accumulated provision for
depreciation and amortization 631,498 575,257
Net property, plant and equipment 1,118,364 937,859
OTHER ASSETS 17,419 13,836
Total assets $1,266,917 $1,016,484
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES
Current maturities of long-term debt $ 2,523 $ 17,500
Note payable -- 10,000
Accounts payable 64,668 3,463
Accrued taxes other than income 20,508 20,968
Accrued interest 10,766 10,353
Over recovered cost of service 4,601 4,236
Accumulated provision for billings
subject to refund -- 12,227
Total current liabilities 103,066 78,747
LONG-TERM DEBT, net of current maturities 478,832 360,000
MINORITY INTERESTS IN PARTNERS' CAPITAL 174,424 158,089
RESERVES AND DEFERRED CREDITS 9,867 9,062
COMMITMENTS AND CONTINGENCIES (NOTE 7)
PARTNERS' CAPITAL
General Partners 10,015 8,212
Common Units 394,587 303,777
Subordinated Units 96,126 98,597
Total partners' capital 500,728 410,586
Total liabilities and partners'
capital $1,266,917 $1,016,484
The accompanying notes are an integral part of these consolidated
financial statements.
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF INCOME
(In Thousands, Except Per Unit Amounts)
Year Ended December 31,
1997 1996 1995
OPERATING REVENUE $198,574 $201,943 $206,497
OPERATING EXPENSES
Operations and maintenance 37,418 28,366 26,730
Depreciation and amortization 40,172 46,979 47,081
Taxes other than income 22,836 24,390 23,886
Operating expenses 100,426 99,735 97,697
OPERATING INCOME 98,148 102,208 108,800
INTEREST EXPENSE 34,520 33,117 35,205
OTHER INCOME
Other income, net 6,589 2,504 379
Allowance for borrowed funds used
during construction 3,660 447 99
Allowance for equity funds used
during construction 1,400 396 90
Other income 11,649 3,347 568
MINORITY INTERESTS IN NET INCOME 22,253 22,153 22,360
NET INCOME TO PARTNERS $ 53,024 $ 50,285 $ 51,803
NET INCOME PER UNIT $ 1.97 $ 1.88 $ 1.94
NUMBER OF UNITS USED IN
COMPUTATION 26,392 26,200 26,200
The accompanying notes are an integral part of these consolidated
financial statements.
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
(In Thousands)
Year Ended December 31,
1997 1996 1995
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income to partners $ 53,024 $ 50,285 $ 51,803
Adjustments to reconcile net income to
partners to net cash provided by
operating activities:
Depreciation and amortization 40,179 47,010 47,083
Minority interests in net income 22,253 22,153 22,360
Provision for billings subject to refund 40,403 12,227 --
Refunds to shippers (52,630) -- --
Changes in other current assets
and liabilities 17,101 7,749 (975)
Other (709) (1,890) 6,807
Total adjustments 66,597 87,249 75,275
Net cash provided by operating activities 119,621 137,534 127,078
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for property, plant
and equipment, net (152,658) (18,597) (8,411)
Acquisition and consolidation of businesses 3,374 -- --
Other (586) (4,796) --
Net cash used in investing activities (149,870) (23,393) (8,411)
CASH FLOWS FROM FINANCING ACTIVITIES:
Cash distributions
Common units (43,654) (43,516) (43,516)
Subordinated units (14,124) (14,124) (14,124)
General partners (1,179) (1,176) (1,176)
Minority Interests (30,080) (30,853) (29,555)
Contributions received from
Minority Interests 24,300 -- --
Issuance of partnership interests, net 90,987 -- --
Issuance of long-term debt 209,000 -- --
Long-term debt financing costs (969) -- --
Retirement of long-term debt (128,665) (32,500) (35,000)
Borrowings on (repayment of) note payable (10,000) 10,000 --
Net cash provided by (used in)
financing activities 95,616 (112,169) (123,371)
NET CHANGE IN CASH AND CASH EQUIVALENTS 65,367 1,972 (4,704)
Cash and cash equivalents-beginning of period 41,390 39,418 44,122
Cash and cash equivalents-end of period $ 106,757 $ 41,390 $ 39,418
The accompanying notes are an integral part of these consolidated
financial statements.
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' CAPITAL
(In Thousands)
Total
General Common Subordinated Partners'
Partners Units Units Capital
Partners' Capital at December 31, 1994 $ 8,522 $315,278 $102,330 $426,130
Net income to partners 1,036 38,327 12,440 51,803
Distributions paid (1,176) (43,516) (14,124) (58,816)
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
The accompanying notes are an integral part of these consolidated
financial statements.
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND MANAGEMENT
Northern Border Partners, L.P., through a subsidiary limited
partnership, Northern Border Intermediate Limited Partnership,
collectively referred to herein as the Partnership, a Delaware
limited 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%) (collectively TransCanada), both
of which are wholly-owned subsidiaries of TransCanada PipeLines
Limited. At December 31, 1997, 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 Duke Energy
Corporation (Duke Energy), 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. The General Partners or their affiliates
also own Subordinated Units representing, in the aggregate, an
effective 21.6% limited partner interest in the Partnership at
December 31, 1997.
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. The
pipeline system owned by Northern Border Pipeline is a 969-mile
natural gas transmission line extending from the United States-
Canadian border near Port of Morgan, Montana, to a terminus
near Harper, Iowa, where it interconnects with the pipeline
system of Natural Gas Pipeline Company of America (NGPL).
Northern Border Pipeline is managed by a Management Committee
that includes three representatives from the Partnership (one
representative from each of the General Partners of the
Partnership) and one representative from TransCanada. 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.
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 its wholly-owned subsidiary, Black Mesa
Pipeline Company, 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. WTI, a leading consultant in slurry pipeline
technology, 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 TransCanada 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 cost of
service determined for that period in accordance with the
FERC tariff (incurred cost of service) to the estimated
billing is accumulated, including carrying charges thereon,
and is either billed to or credited back to the shippers.
Revenues reflect incurred cost of service. An amount equal
to differences between billing estimates and the incurred
cost of service, including carrying charges, is reflected
in current assets or current liabilities.
(D) Cash and Cash Equivalents
Cash equivalents consist of highly liquid investments
with original maturities of three months or less. The
carrying amount of cash and cash equivalents approximates
fair value because of the short maturity of these
investments.
(E) Income Taxes
Income taxes are the responsibility of the partners and
are not reflected in these financial statements. However,
the Northern Border Pipeline tariff establishes the method
of accounting for and calculating income taxes and requires
Northern Border Pipeline to reflect in its 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
$300.0 million and $306.7 million as of December 31, 1997
and 1996, respectively, and are primarily related to
accelerated depreciation and other plant-related
differences.
(F) Property, Plant and Equipment and Related Depreciation
and Amortization
Property, plant and equipment is stated at original cost.
Balances at December 31, 1997 and 1996 include construction
work in progress of approximately $211.4 million and $19.6
million, respectively. Approximately $197.9 million and
$16.8 million of construction work in progress at December
31, 1997 and 1996, respectively, represents project-to-date
costs on Northern Border Pipeline's expansion and extension
of its pipeline from its current terminus near Harper, Iowa
to a point near Manhattan, Illinois (The Chicago Project)
(see Note 7). At December 31, 1997, approximately $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 and levelized
cost of service. The effective depreciation rate applied
to Northern Border Pipeline's gross transmission plant in
1997, 1996 and 1995 was 2.5%, 3.1% and 3.1%, respectively
(see Note 7). 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.
(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.
Recognition of this allowance is appropriate because it
constitutes an actual cost of construction. 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. Northern Border Pipeline does not use
these agreements for trading purposes. The cost or benefit
of the interest rate swap agreements is recognized
currently as a component of interest expense.
3. ACQUISITIONS
On May 31, 1997, the Partnership exchanged 125,357 Common Units
for all of the outstanding common stock of WTI. In addition to
being the operator of Black Mesa, WTI has an 11.25% ownership
position in Black Mesa.
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 (amounts in thousands):
Cash $ 3,374
Net property, plant and equipment 18,350
Other current and noncurrent assets 10,159
Long-term debt, including
current maturities (23,520)
Other liabilities (3,090)
Minority interests (185)
Common Units $ 5,088
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, including
firm service agreements applicable to The Chicago Project,
extend for various terms with termination dates that range from
October 2001 to October 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.
At December 31, 1997, Northern Border Pipeline's largest
shipper, Pan-Alberta Gas (U.S.) Inc. (PAGUS), was obligated for
approximately 49.0% of the cost of service through its firm
service agreements which expire in October 2001. Operating
revenues from the PAGUS firm service agreements and
interruptible service contracts for the years ended December
31, 1997, 1996 and 1995 were $86.8 million, $95.7 million and
$99.9 million, respectively. Northern Natural Gas Company
(Northern), a wholly-owned subsidiary of Enron, and Panhandle
Eastern Pipe Line Company (Panhandle), a wholly-owned
subsidiary of Duke Energy, have executed financial guarantees
representing 17.2% and 10.7%, respectively, of the total cost
of service related to the contracted capacity of PAGUS. 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. After The Chicago Project is placed in-
service, PAGUS is obligated for approximately 29.9% of the cost
of service and the financial guarantees related to the PAGUS
contracted capacity by Northern and Panhandle will represent
10.5% and 6.5%, respectively, of the total cost of service.
Shippers affiliated with the partners of Northern Border
Pipeline have firm service agreements representing
approximately 12.6% of the cost of service at December 31,
1997. These firm service agreements extend for various terms
with termination dates that range from October 2003 to December
2008. Operating revenues from the affiliated firm service
agreements and interruptible service contracts for the years
ended December 31, 1997, 1996 and 1995 were $20.2 million,
$21.4 million and $18.8 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, SHORT-TERM BORROWINGS AND LONG-TERM DEBT
Detailed information on short-term borrowings and long-term
debt is as follows:
December 31,
(In thousands) 1997 1996
Northern Border Pipeline
Senior notes - average 8.43%,
due from 2000 to 2003 $250,000 $250,000
1996 one-year revolving credit
facility - average 5.95% and
5.94% in 1997 and 1996, respectively -- 10,000
Pipeline Credit Agreement
Five-year revolving credit facility 127,500 --
Three-year revolving credit facility 81,500 --
Amended bank loan agreement due 1999 -- 127,500
Black Mesa
10.7% Note agreement,
due quarterly to 2004 22,355 --
Total 481,355 387,500
Less: Current maturities of long-term debt 2,523 17,500
Amount classified as note payable -- 10,000
Long-term debt $478,832 $360,000
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 The Chicago Project has been placed in service
and certain other 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, 1997 and 1996, 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 two years as of
December 31, 1997, 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, 1997 and 1996, 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 7.09% and 7.32% at December 31, 1997 and
1996, respectively.
In November 1997, the Partnership entered into a credit
agreement (Partnership Credit Agreement) with certain financial
institutions to borrow up to an aggregate principal amount of
$175 million under a revolving credit facility. The Partnership
Credit Agreement is to be used for interim funding of the
Partnership's required capital contributions to Northern Border
Pipeline for construction of The Chicago Project. The amount
available under the Partnership Credit Agreement is reduced to
the extent the Partnership issues additional limited partner
interests to fund the Partnership's required capital contributions
for The Chicago Project in excess of $25 million. The public
offering of Common Units discussed in Note 6 reduced the amount
available under the Partnership Credit Agreement to $111
million at December 31, 1997. After The Chicago Project has
been placed in service, the Partnership Credit Agreement allows
the Partnership to borrow any undrawn amounts up to an
aggregate principal amount of $40 million for general business
purposes. 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, 1997, the Partnership had not
borrowed on the Partnership Credit Agreement.
Interest paid, net of amounts capitalized, during the years
ended December 31, 1997, 1996 and 1995 was $31.6 million, $31.9
million and $34.3 million, respectively.
Aggregate repayments of long-term debt required for the next
five years are as follows: $3 million, $3 million, $151
million, $44 million and $209 million for 1998, 1999, 2000,
2001 and 2002, respectively.
Certain of Northern Border Pipeline's long-term debt and credit
arrangements contain requirements as to the maintenance of
minimum partners' capital and debt to capitalization ratios
which restrict the incurrence of other indebtedness by Northern
Border Pipeline and also place certain restrictions on
distributions to the partners of Northern Border Pipeline.
Under the most restrictive of the covenants, as of December 31,
1997 and 1996, respectively, $81 million and $27 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, which is reflected in other assets on the
consolidated balance sheet at December 31, 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 $276 million and $271 million at
December 31, 1997 and 1996, respectively, and the estimated
fair value of the Black Mesa note agreement was approximately
$25 million at December 31, 1997. At December 31, 1997 and
1996, 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
and $4 million, respectively. The Partnership presently
intends to maintain the current schedule of maturities for the
senior notes, the Black Mesa note agreement and the interest
rate swap agreements that will result in no gains or losses on
their respective repayment. The carrying value of the Pipeline
Credit Agreement approximates the fair value since the interest
rates are periodically adjusted to current market conditions.
6. PARTNERS' CAPITAL
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. At December
31, 1996, partners' capital consisted of 19,780,000 Common
Units representing an effective 74% limited partner interest in
the Partnership; 6,420,000 Subordinated Units representing an
effective 24% limited partner interest in the Partnership; and
a 2% general partner interest. In December 1997, the
Partnership sold, through an underwritten public offering,
2,750,000 Common Units. In conjunction with the issuance of
the additional Common Units, the Partnership's general partners
made capital contributions to the Partnership to maintain a 2%
general partner interest in accordance with the partnership
agreements. The net proceeds, of the public offering and the
general partners' capital contributions, of approximately $90.9
million will be 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 (see Note 11).
The Partnership Policy Committee may cause the Partnership to
issue additional Common Units or other partner interests.
However, as of December 31, 1997, the Partnership may not issue
more than an additional 14.5 million Common Units (17.2 million
Common Units as of December 31, 1996) or equivalent other
partner interests, while the Subordinated Units have not been
converted or are still outstanding, without the approval of the
holders of at least a majority of the outstanding Common Units
(excluding Common Units, if any, held by the General Partners
and their affiliates). Under the partnership agreement, the
Subordinated Units may not be converted to Common Units prior
to January 1, 1999, and only after cumulative capital
expenditures by the Partnership subsequent to October 1, 1993,
equal or exceed $248 million and the Partnership has
distributed the minimum quarterly distribution on all Common
and Subordinated Units for each of the eight consecutive
preceding calendar quarters.
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. Partnership
income is allocated to the General Partners, Common
Unitholders and Subordinated Unitholders 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.
7. COMMITMENTS AND CONTINGENCIES
Regulatory Proceedings
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 estimated value of the
linepack gas, including the linepack gas attributable to the
pipeline extension for The Chicago Project, is $12.5 million.
Northern Border Pipeline has proposed that the cost of the
linepack gas be included in its rate base.
In August 1997, Northern Border Pipeline received FERC approval
of the 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.
In August 1997, the FERC issued a certificate of public
convenience and necessity authorizing Northern Border Pipeline
to construct and operate facilities, as filed for in a
September 1996 application with the FERC for The Chicago
Project. Northern Border Pipeline has accepted the certificate
and construction is proceeding. NGPL had filed in the United
States Court of Appeals for the District of Columbia a petition
for review of the August order issued by the FERC that has been
dismissed. The Chicago Project pipeline facilities consist of
243 miles of pipeline and 147 miles of pipeline loop. Compression
facilities for The Chicago Project involve the installation of
228,500 compressor horsepower at eight new compressor stations and
upgrades at five existing compressor stations by the removal from
service of units producing 100,000 compressor horsepower with the
installation of replacement units producing 175,000 compressor
horsepower. The project's estimated cost as filed with the
FERC is approximately $839 million and it is expected to be
ready for service in the fourth quarter of 1998.
In May 1996, the FERC granted rehearing of its May 1994 order
on Northern Border Pipeline's methodology for recording in its
books and reflecting in its rates amounts related to
alternative minimum tax (AMT). The FERC Audit Staff (Staff),
in December 1991 after an examination of Northern Border
Pipeline's records for the period January 1, 1987 through
December 31, 1989, took exception to Northern Border Pipeline's
established method of accounting for AMT for ratemaking
purposes. Northern Border Pipeline did not agree with the
exception noted by the Staff and proceeded with a hearing
before an Administrative Law Judge (ALJ) who concluded Northern
Border Pipeline had properly accounted for AMT. Ultimately, in
the May 1996 order, the FERC accepted the ALJ's conclusions and
vacated its May 1994 order which had held that the AMT
component of Northern Border Pipeline's rate base should
reflect the particular tax circumstances of each Northern
Border Pipeline partner. There were no accounting adjustments
or rate refunds required in resolution of this issue.
In May 1996, the Staff issued its audit report on its
examination of Northern Border Pipeline's records for the three
year period subsequent to January 1, 1990. The audit report
required Northern Border Pipeline to record certain adjustments
to its accounts including the reclassification of $3.9 million
of costs from utility plant in service to a regulatory asset.
In accordance with Northern Border Pipeline's FERC tariff, the
regulatory asset is includable in rate base, however Northern
Border Pipeline must file with the FERC for the future recovery
of this asset through amortization in cost of service. The
General Partners indemnified the Partnership for any negative
impact on distributions the Partnership received from Northern
Border Pipeline as a result of this audit that was attributable
to periods prior to October 1, 1993. The adjustments made and
the indemnification received as a result of the audit report
did not materially affect the consolidated financial position
or results of operations.
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 1998 are estimated to be $637
million for The Chicago Project and $9 million for renewals and
replacements of the existing facilities. Capital expenditures
for linepack gas, if the filing to acquire the linepack is
approved by the FERC, would be approximately $12.5 million (see
Note 7). Funds required to meet the 1998 capital expenditures
are anticipated to be provided from debt borrowings, internal
sources and capital contributions from minority interest
holders.
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)
(In thousands, except Operating Operating Net Income Net Income
per unit amounts) Revenue Income to Partners per Unit
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
1996
First Quarter $52,953 $26,325 $12,847 $0.48
Second Quarter 52,918 25,943 12,737 0.48
Third Quarter 52,863 25,991 12,942 0.48
Fourth Quarter 43,209 23,949 11,759 0.44
11. SUBSEQUENT EVENTS
On January 5, 1998, the Partnership sold, through the exercise
of the underwriters' over-allotment option (see Note 6), an
additional 225,000 Common Units. In conjunction with the sale,
the General Partners made capital contributions to the
Partnership to maintain a 2% general partner interest. The net
proceeds, including the General Partners' capital
contributions, of approximately $7.5 million will be used by
the Partnership to fund a portion of the capital contributions
to Northern Border Pipeline for construction of The Chicago
Project. After the issuance of these Units, partners' capital
consists 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; and a 2% general partner
interest. The amount available under the Partnership Credit
Agreement was further reduced from $111 million to $104 million
(see Note 5).
On January 15, 1998, the Partnership declared an increase in
the quarterly cash distribution from $0.55 per Unit to $0.575
per Unit and a cash distribution to the General Partners at a
rate equivalent to their combined 2% general partner interest
for the period October 1, 1997 through December 31, 1997. The
distribution is payable February 13, 1998, to the General
Partners and to the Unitholders of record at January 30, 1998.
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 26, 1998. 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 26, 1998
SCHEDULE II
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
(In Thousands)
Column A Column B Column C Column D Column E
Additions Deductions
Balance at Charged to Charged For Purpose For
Beginning Costs and to Other Which Reserves Balance at
Description of Year Expenses Accounts Were Created End of Year
Reserve for
regulatory issues
1997 $5,953 $ 773 $-- $ -- $6,726
1996 $8,200 $ -- $-- $2,247 $5,953
1995 $5,583 $2,617 $-- $ -- $8,200
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, 1997 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 (I.R.S. Employer
jurisdiction 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 Amended and Restated Loan Agreement among
Northern Border Pipeline Company, the
Banks (as defined therein), Canadian
Imperial Bank of Commerce, New York
Agency and Bank of America National Trust
& Savings Association, dated July 15,
1992 (Exhibit 10.5 to Form S-1).
*10.5.1 Letter Amendment to Amended and Restated
Loan Agreement effective as of September
21, 1993 (Exhibit 10.5.1 to the
Partnership's Annual Report on Form 10-K
for the year ended December 31, 1993
("1993 10-K")).
*10.5.2 Letter Amendment to Amended and Restated
Loan Agreement effective as of September
9, 1994 (Exhibit 10.5.2 to the
Partnership's Annual Report on Form 10-K
for the year ended December 31, 1994
("1994 10-K")).
*10.5.3 Letter Amendment to Amended and Restated
Loan Agreement dated May 18, 1995
(Exhibit 10.5.3 to the Partnership's
Annual Report on Form 10-K for the year
ended December 31, 1995 ("1995 10-K")).
*10.6 Note Purchase Agreement between Northern
Border Pipeline Company and the parties
listed therein, dated July 15, 1992
(Exhibit 10.6 to Form S-1).
*10.6.1 Supplemental Agreement to the Note
Purchase Agreement dated as of June 1,
1995 (Exhibit 10.6.1 to 1995 10-K).
*10.7 Consent and Agreement of the Partners
among Northern Plains Natural Gas
Company, Northwest Border Pipeline
Company, Pan Border Gas Company,
TransCanada Border PipeLine Ltd. and
Canadian Imperial Bank of Commerce, New
York Agency, dated February 28, 1990
(Exhibit 10.7 to Form S-1).
*10.8 Consent and Agreement of the Partners
among TransCanada Border PipeLine Ltd.,
TransCan Northern Ltd. and Canadian
Imperial Bank of Commerce, New York
Agency, dated April 19, 1991 (Exhibit
10.8 to Form S-1).
*10.9 Guaranty made by Panhandle Eastern
Pipeline Company, dated October 31, 1992
(Exhibit 10.9 to Form S-1).
*10.10 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).
*10.10.1 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 1993 10-K).
*10.10.2 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 1994
10-K).
*10.10.3 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).
10.10.4 Amended Exhibit A to Northern Border
Pipeline Company U.S. Shipper Service
Agreement effective April l, 1998.
*10.11.1 Guaranty made by Northern Natural Gas
Company, dated October 7, 1993 (Exhibit
10.11.1 to 1993 10-K).
*10.11.2 Guaranty made by Northern Natural Gas
Company, dated October 7, 1993 (Exhibit
10.11.2 to 1993 10-K).
*10.12 Northern Border Pipeline Company U.S.
Shippers Service Agreement between
Northern Border Pipeline Company and
Northern Natural Gas Company, dated
August 25, 1988 (Exhibit 10.12 to Form S-1).
*10.12.1 Amendment to Northern Border Pipeline
Company U.S. Shippers Service Agreement
effective October 1, 1993. (Exhibit
10.12.1 to 1993 10-K).
*10.12.2 Amendment to Northern Border Pipeline
Company U.S. Shippers Service Agreement
terminating the Agreement as of November
1, 1994 (Exhibit 10.12.2 to 1994 10-K).
*10.13 Northern Border Pipeline Company U.S.
Shippers Service Agreement between
Northern Border Pipeline Company and
Western Gas Marketing Limited, as agent
for TransCanada PipeLines Limited, dated
December 15, 1980 (Exhibit 10.13 to Form
S-1).
*10.13.1 Amendment to Northern Border Pipeline
Company Service Agreement extending the
term effective November 1, 1995 (Exhibit
10.13.1 to 1995 10-K).
*10.14 Form of Credit Agreement between Northern
Border Partners, L.P., as borrower, and
Northern Plains Natural Gas Company,
Northwest Border Pipeline Company and Pan
Border Gas Company, as lenders (Exhibit
10.14 to Form S-1).
*10.15 Form of Seventh Supplement Amending
Northern Border Pipeline Company General
Partnership Agreement (Exhibit 10.15 to
Form S-1).
*10.16 Form of Conveyance, Contribution and
Assumption Agreement among Northern
Plains Natural Gas Company, Northwest
Border Pipeline Company, Pan Border Gas
Company, Northern Border Partners, L.P.,
and Northern Border Intermediate Limited
Partnership (Exhibit 10.16 to Form S-1).
*10.17 Northern Border Pipeline Company U.S.
Shippers Service Agreement between
Northern Border Pipeline Company and
Transcontinental Gas Pipe Line
Corporation, dated July 14, 1983, with
Amended Exhibit A effective February 11,
1994 (Exhibit 10.17 to 1995 10-K).
*10.18 Northern Border Pipeline Company U.S.
Shippers Service Agreement dated August
30, 1991 between Northern Border Pipeline
Company and Mobil Natural Gas, Inc., with
Amended Exhibit A effective April 29,
1994 and designation of agent effective
August 1, 1996 (Exhibit 10-18 to the
Partnership's Annual Report on Form 10-K
for the year ended December 31, 1996).
*10.19 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")).
*10.20 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).
10.21 Northern Border Pipeline Company U.S.
Shippers Service Agreement between
Northern Border Pipeline Company and
Enron Capital & Trade Resources Corp.
dated October 15, 1997.
10.22 Northern Border Pipeline Company U.S.
Shippers Service Agreement between
Northern Border Pipeline Company and
Enron Capital & Trade Resources Corp.
dated October 15, 1997.
10.23 Northern Border Pipeline Company U.S.
Shippers Service Agreement between
Northern Border Pipeline Company and
PanEnergy Trading and Market Services,
L.L.C., now known as Duke Trading and
Market Services L.L.C., dated August 14,
1997.
10.24 Northern Border Pipeline Company U.S.
Shippers Service Agreement between
Northern Border Pipeline Company and
PanEnergy Trading and Market Services,
L.L.C., now known as Duke Trading and
Market Services L.L.C., dated August 14,
1997.
10.25 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.
10.26 Northern Border Pipeline Company U.S.
Shippers Service Agreement between
Northern Border Pipeline Company and
Enron Capital & Trade Resources Corp.
dated August 5, 1997.
10.27 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.
10.28 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 14, 1997.
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., and Williams Technologies, Inc.
23.01 Consent of Arthur Andersen LLP.
__________
*Indicates exhibits incorporated by reference as
indicated; all other exhibits are filed herewith.