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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, 2003 Commission file number: 333-88577
NORTHERN BORDER PIPELINE COMPANY
(Exact name of registrant as specified in its charter)
TEXAS 74-2684967
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)
13710 FNB PARKWAY, OMAHA, NEBRASKA 68154-5200
(Address of principal executive offices)(zip code)
Registrant's telephone number, including area code: 402-492-7300
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Title of each class Name of each exchange on which registered
None
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]
Indicate by check mark whether the registrant is an accelerated filer
(as defined by Rule 12b-2 of the Securities Exchange Act of 1934). Yes [ ] No
[X]
Aggregate market value of the voting and non-voting common equity held
by non-affiliates of the registrant on June 30, 2003, was $0.
NORTHERN BORDER PIPELINE COMPANY
TABLE OF CONTENTS
PAGE NO.
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PART I
Item 1. Business 1
Item 2. Properties 12
Item 3. Legal Proceedings 13
Item 4. Submission of Matters to a Vote of Security Holders 13
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters 14
Item 6. Selected Financial Data 15
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations 16
Item 7a. Quantitative and Qualitative Disclosures About
Market Risk 29
Item 8. Financial Statements and Supplementary Data 30
Item 9. Changes in and Disagreements With Accountants on
Accounting and Financial Disclosure 30
Item 9(a) Controls and Procedures 30
PART III
Item 10. Partnership Management 31
Item 11. Executive Compensation 34
Item 12. Security Ownership of Certain Beneficial Owners
and Management 37
Item 13. Certain Relationships and Related Transactions 37
Item 14. Principal Accounting Fees and Services 38
PART IV
Item 15. Exhibits, Financial Statement Schedules and
Reports on Form 8-K. 40
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PART I
ITEM 1. BUSINESS
GENERAL
Northern Border Pipeline Company is a general partnership formed in
1978. Our general partners are Northern Border Partners, L.P. and TC PipeLines,
LP, both of which are publicly traded partnerships. Each of Northern Border
Partners and TC PipeLines holds its interest in us, 70% and 30% of voting power,
respectively, through a subsidiary limited partnership. The general partners of
Northern Border Partners and its subsidiary limited partnership are Northern
Plains Natural Gas Company ("Northern Plains") and Pan Border Gas Company, both
subsidiaries of Enron Corp., and Northwest Border Pipeline Company, a subsidiary
of TransCanada PipeLines Limited which is a subsidiary of TransCanada
Corporation. The general partner of TC PipeLines and its subsidiary limited
partnership, TC PipeLines GP, Inc., is also a subsidiary of TransCanada.
We own an interstate pipeline system that transports natural gas from
the Montana-Saskatchewan border to natural gas markets in the midwestern United
States. This pipeline system connects with multiple pipelines that provide
shippers with access to the various natural gas markets served by those
pipelines. In the year ended December 31, 2003, we estimate that we transported
approximately 22% of the total amount of natural gas imported from Canada to the
United States. Over the same period, approximately 88% of the natural gas
transported was produced in the western Canadian sedimentary basin located in
the provinces of Alberta, British Columbia and Saskatchewan.
We transport gas for shippers under a tariff regulated by the Federal
Energy Regulatory Commission ("FERC"). The tariff specifies the maximum and
minimum transportation rates and the general terms and conditions of
transportation service on the pipeline system. Our 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. We do
not own the gas that we transport, and therefore we do not assume natural gas
commodity price risk for quantities transported. Any exposure to commodity risk
for imbalances on our system that may result from under or over deliveries to
customers or interconnecting pipelines is either recovered through provisions in
our tariff or is immaterial. We own the line pack, which is the amount of gas
necessary to maintain efficient operations of the pipeline. Our shippers are
responsible to provide fuel gas necessary for the operation of gas compressor
stations.
Our management is overseen by a four-member management committee. Three
representatives are designated by Northern Border Partners, with each of its
general partners selecting one representative; and one representative is
designated by TC PipeLines. Voting power on the management committee is
allocated among Northern Border Partners' three representatives in proportion to
their general partner interests in Northern Border Partners. As a result, the
70% voting power of Northern Border Partners' three representatives on the
management committee is allocated as follows: 35% to the representative
designated by Northern Plains, 22.75% to the representative designated by Pan
Border and 12.25% to the representative designated by Northwest Border.
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Northern Plains and Pan Border are subsidiaries of Enron. Therefore, Enron
controls 57.75% of the voting power of the management committee and has the
right to select two of the members. On December 2, 2001, Enron filed a voluntary
petition for Chapter 11 protection in bankruptcy court. On September 25, 2003, a
motion by Enron to transfer Enron's interests in, among other entities, Northern
Plains and Pan Border to CrossCountry Energy, a new pipeline operating entity,
was approved. See Item 7. "Management's Discussion and Analysis of Financial
Condition and Results of Operations - The Impact Of Enron's Chapter 11 Filing On
Our Business" and Item 13. "Certain Relationships and Related Transactions."
Our pipeline system is operated by Northern Plains pursuant to an
operating agreement. As of December 31, 2003, Northern Plains employed
approximately 216 individuals located at its headquarters in Omaha, Nebraska and
at various locations along the pipeline route and also used employees and
information technology systems of its affiliates to provide its services.
Northern Plains' employees are not represented by any labor union and are not
covered by any collective bargaining agreements.
THE PIPELINE SYSTEM
We own a 1,249-mile interstate pipeline system that transports natural
gas from the Montana-Saskatchewan border near Port of Morgan, Montana to natural
gas markets in the midwestern United States. Construction of the pipeline was
initially completed in 1982. Our pipeline system was expanded and/or extended in
1991, 1992, 1998 and 2001. Our pipeline system connects directly and through
multiple pipelines to various natural gas markets in the United States.
Our pipeline system consists of 822 miles of 42-inch diameter pipe from
the Canadian border to Ventura, Iowa capable of transporting a total of 2,374
million cubic feet per day ("mmcfd"); 30-inch diameter pipe and 36-inch diameter
pipe, each approximately 147 miles in length, capable of transporting 1,484
mmcfd in total from Ventura, Iowa to Harper, Iowa; 226 miles of 36-inch diameter
pipe and 19 miles of 30-inch diameter pipe capable of transporting 844 mmcfd
from Harper, Iowa to Manhattan, Illinois (Chicago area); and 35 miles of 30-inch
diameter pipe capable of transporting 545 mmcfd from Manhattan, Illinois to a
terminus near North Hayden, Indiana. Along the pipeline there are 16 compressor
stations with total rated horsepower of 499,000 and measurement facilities to
support the receipt and delivery of gas at various points. Other facilities
include four field offices and a microwave communication system with 50 tower
sites.
Our pipeline system has pipeline access to natural gas reserves in the
western Canadian sedimentary basin in the provinces of Alberta, British Columbia
and Saskatchewan in Canada, domestic natural gas produced within the Williston
Basin and synthetic gas produced at the Dakota Gasification plant in North
Dakota. In addition, the pipeline is capable of physically receiving natural gas
at two locations near Chicago. At its northern end, the pipeline system's gas
supplies are received through an interconnection with Foothills Pipe Lines
(Sask.) Ltd. system in Canada. The Foothills system, owned by TransCanada, is
connected to TransCanada's Alberta system and the pipeline system owned by
Transgas Limited in Saskatchewan. Also at the north end, the
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pipeline system connects to a domestic natural gas gathering system owned by
Omimex Ltd. In North Dakota, our pipeline system connects with facilities of
Northern Natural Gas Company at Buford, which facilities in turn are connected
to Williston Basin Interstate Pipeline and the gathering system owned by Bear
Paw Energy, LLC, a wholly-owned subsidiary of Northern Border Partners. In
December 2003, an interconnection with a newly constructed pipeline owned by
Williston Basin Interstate Pipeline near Manning, North Dakota was placed in
service. The initial design capacity of the interconnect facilities is 200
mmcfd. The pipeline, with an initial design capacity of 80 mmcfd, was
constructed to transport natural gas from coalbed and conventional natural gas
supplies in the Powder River Basin of northeastern Wyoming and southeastern
Montana as well as conventional supplies in the Rocky Mountain area. Other
locations in North Dakota where we can receive gas are interconnections with
Williston Basin Interstate Pipeline at Glen Ullin and Amerada Hess Corporation
at Watford City and facilities of Dakota Gasification Company at Hebron. Near
its terminus, the pipeline system is capable of physically receiving natural gas
from Northern Illinois Gas Company at Troy Grove, Illinois and from Midwestern
Gas Transmission Company, a wholly-owned subsidiary of Northern Border Partners,
at Channahon, Illinois. For the year ended December 31, 2003, of the natural gas
transported on our pipeline system, approximately 88% was produced in Canada,
approximately 5% was produced by the Dakota Gasification plant, approximately 6%
was produced in the Williston Basin and 1% from other sources.
INTERCONNECTS
Our pipeline system connects with multiple pipelines of various
interstate, intrastate and local distribution companies, as well as with
end-users. These interconnects provide our shippers with access to the various
natural gas markets served by those pipelines. The larger interconnections are
with the pipeline facilities of:
- Northern Natural Gas Company at Ventura, Iowa as well as multiple
smaller interconnections in South Dakota, Minnesota and Iowa;
- Natural Gas Pipeline Company of America at Harper, Iowa;
- MidAmerican Energy Company at Iowa City and Davenport, Iowa and
Cordova, Illinois;
- Alliant Power Company at Prophetstown, Illinois;
- Northern Illinois Gas Company at Troy Grove and Minooka, Illinois;
- Midwestern Gas Transmission Company near Channahon, Illinois;
- ANR Pipeline Company near Manhattan, Illinois;
- Vector Pipeline L.P. in Will County, Illinois;
- Guardian Pipeline, L.L.C., an affiliate of Northern Border
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Partners, in Will County, Illinois;
- The Peoples Gas Light and Coke Company near Manhattan, Illinois;
and
- Northern Indiana Public Service Company near North Hayden, Indiana
at the terminus of the pipeline system.
Several market centers, where natural gas transported on the pipeline
system is sold, traded and received for transport to significant consuming
markets in the Midwest and to interconnecting pipeline facilities, have
developed on the pipeline system. The largest of these market centers is at our
Ventura, Iowa connection with Northern Natural Gas Company. Two other market
center locations are the Harper, Iowa connection with Natural Gas Pipeline
Company of America and our multiple interconnects in the Chicago area that
include connections with Northern Illinois Gas Company, The Peoples Gas Light
and Coke Company and Northern Indiana Public Service Company, as well as four
interstate pipelines.
SHIPPERS
The pipeline system serves more than 40 firm transportation shippers
with diverse operating and financial profiles. Based upon shippers' contractual
obligations, as of December 31, 2003, 94% of the firm capacity is contracted by
producers and marketers. The remaining firm capacity is contracted primarily by
local distribution companies (5%), and interstate pipelines (1%). As of December
31, 2003, the termination dates of these contracts ranged from March 31, 2004 to
December 21, 2013, and the weighted average contract life, based upon
contractual obligations, was approximately three and one-third years. All of our
capacity was under contract through December 31, 2003 and, assuming no
extensions of existing contracts or execution of new contracts, approximately
70% and 59% is under contract through December 31, 2004 and 2005, respectively.
See Item 7. "Management's Discussion and Analysis of Financial Condition and
Results of Operations-Overview."
Our shippers may change throughout the year as a result of our shippers
utilizing our capacity release provisions that allow them to release all or part
of their capacity to other shippers, either permanently for the full term of
their contract or temporarily. Under the terms of our tariff, a temporary
capacity release does not relieve the original contract shipper from its payment
obligations if the replacement shipper fails to pay.
For the year ending December 31, 2003, BP Canada Energy Marketing Corp.
("BP Canada"), EnCana Marketing U.S.A. Inc. ("EnCana"), and Pan Alberta Gas
(U.S.) Inc. ("Pan-Alberta") collectively accounted for approximately 41% of our
revenues. As of December 31, 2003, our three largest shippers were BP Canada,
EnCana and Cargill Incorporated who are obligated for approximately 21%, 19% and
9%, respectively, of the contracted firm capacity. In July 2003, Cargill
Incorporated completed the assignment of all the firm capacity formerly held by
Mirant Americas Energy Marketing, LP, which extends for terms into 2006 and
2008. Approximately half of the capacity contracted to BP Canada and
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EnCana is due to expire by November 1, 2004. During 2003, all of the contracted
capacity due to expire by November 1, 2003, of which Pan - Alberta held
approximately 20% was recontracted with 10 shippers. See Item 7. "Management's
Discussion and Analysis of Financial Condition and Results of Operations -
Overview."
DEMAND FOR TRANSPORTATION CAPACITY
Our long-term financial condition is dependent on the continued
availability of economic western Canadian natural gas supplies for import into
the United States. Natural gas reserves may require significant capital
expenditures by others for exploration and development drilling and the
installation of production, gathering, storage, transportation and other
facilities that permit natural gas to be produced and delivered to pipelines
that interconnect with the interstate pipelines' systems. Prices for natural
gas, the currency exchange rate between Canada and the United States, regulatory
limitations or the lack of available capital for these projects could adversely
affect the development of additional reserves and production, gathering, storage
and pipeline transmission of western Canadian natural gas supplies. Increased
Canadian consumption of natural gas related to the extraction process for oil
sands projects as well as restrictions on gas production to protect oil sand
reserves could also impact supplies of natural gas for export. Additional
pipeline export capacity also could accelerate depletion of these reserves.
Furthermore, the availability of export capacity could also affect the demand or
value of the transport on our pipeline system.
Our business also depends on the level of demand for natural gas in the
markets the pipeline system serves. The volumes of natural gas delivered to
these markets from other sources affect the demand for both the natural gas
supplies and the use of our pipeline system. Demand for natural gas to serve
other markets also influences the ability and willingness of shippers to use our
pipeline system to meet demand in the markets that we serve.
A variety of factors could affect the demand for natural gas in the
markets that we serve. These factors include:
- economic conditions;
- fuel conservation measures;
- alternative energy requirements and prices;
- gas storage inventory levels;
- climatic conditions;
- government regulation; and
- technological advances in fuel economy and energy generation
devices.
Interstate pipelines' primary exposure to market risk occurs at the
time existing transportation contracts expire and are subject to
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renegotiation. A key determinant of the value that customers can realize from
firm transportation on a pipeline is the basis differential, or market price
spread, between two points on the pipeline. The difference in natural gas prices
between the points along the pipeline where gas enters and where gas is
delivered represents the gross margin that a customer can expect to achieve from
holding transportation capacity at any point in time. This margin and its
variability become important factors in determining the transportation rate
customers are willing to pay when they renegotiate their transportation
contracts. The basis differential between markets can be affected by trends in
production, available capacity, storage inventories, weather and general market
demand in the respective areas.
Throughput on our pipeline may experience seasonal fluctuations depending
upon the level of winter heating load demand or summer electric generation usage
in the markets we serve. However, since approximately 98% of our expected
revenue is attributable to demand charges, our revenues and cash flow are not
impacted materially by such seasonal throughput variations.
We cannot predict whether these or other factors will have an adverse
effect on demand for use of our pipeline system or how significant that adverse
effect could be.
INTERSTATE PIPELINE COMPETITION
We compete with other pipeline companies that transport natural gas
from the western Canadian sedimentary basin or that transport natural gas to
end-use markets in the midwest. Our competitive position is affected by the
availability of Canadian natural gas for export, the availability of other
sources of natural gas and demand for natural gas in the United States. Demand
for transportation services on our system is affected by natural gas prices, the
relationship between export capacity from and production in the western Canadian
sedimentary basin and natural gas shipped from producing areas in the United
States. Shippers of natural gas produced in the western Canadian sedimentary
basin also have other options to transport Canadian natural gas to the United
States, including transportation on the Alliance Pipeline, on TransCanada's
pipeline system through various interconnects with U.S. interstate pipelines,
including Viking Gas Transmission Company which is owned by Northern Border
Partners, or to markets on the West Coast.
The Alliance Pipeline competes directly with us in the transportation
of natural gas from the western Canadian sedimentary basin to the Chicago area.
Because it transports liquids-rich natural gas, the Alliance Pipeline currently
has no major interconnections with other pipelines upstream of liquids
extraction facilities located near Chicago. This contrasts with our pipeline
system, which serves various markets through interconnections with other
pipelines along its route. The Chicago market hub has absorbed the new supply
from Alliance Pipeline as incremental pipeline capacity has been developed to
transport natural gas from the Chicago area to other market regions.
In addition, we compete in our markets with other interstate pipelines
that provide access to other supply basins. Our major deliveries into Northern
Natural Gas at Ventura, Iowa compete with gas
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supplied from the Rockies, and mid-continent regions. We also compete with these
supply basins at our delivery interconnect with Natural Gas Pipeline at Harper,
Iowa. In the Chicago area, we compete with many interstate pipelines that
transport gas from the Gulf Coast, mid-continent, Rockies and western Canada.
FERC REGULATION
We are subject to extensive regulation by the FERC as a "natural gas
company" under the Natural Gas Act. Under the Natural Gas Act and the Natural
Gas Policy Act, the FERC has jurisdiction with respect to virtually all aspects
of our business, including:
- transportation of natural gas;
- rates and charges;
- construction of new facilities;
- extension or abandonment of service and facilities;
- accounts and records;
- depreciation and amortization policies;
- the acquisition and disposition of facilities; and
- the initiation and discontinuation of services.
Where required, we hold certificates of public convenience and
necessity issued by the FERC covering our facilities, activities and services.
Under Section 8 of the Natural Gas Act, the FERC has the power to prescribe the
accounting treatment for items for regulatory purposes. Our books and records
may be periodically audited by the FERC under Section 8. We were notified in
November 2002 that we were one of the companies selected by the FERC to undergo
an industry-wide audit of FERC-assessed annual charges. The overall audit
objective was to determine compliance with FERC accounting requirements and
regulations as they relate to the calculation and assessment of annual charges
by validating the accuracy of the data filed annually with the FERC. The audit
covered the period of January 1, 2001 to December 31, 2001. On April 10, 2003,
the FERC issued its final report that found we were in compliance.
The FERC regulates the rates and charges for transportation in
interstate commerce. Natural gas companies may not charge rates exceeding rates
judged just and reasonable by the FERC. Generally, rates are based on the cost
of service including recovery of and a return on the pipeline's actual
historical cost investment. In addition, the FERC prohibits natural gas
companies from unduly preferring or unreasonably discriminating against any
person with respect to pipeline rates or terms and conditions of service. Some
types of rates may be discounted without further FERC authorization and rates
may be negotiated subject to FERC approval. The rates and terms and conditions
for our service are found in our FERC approved tariff.
Transportation rates are established periodically in FERC
7
proceedings known as rate cases. Under our tariff, we are allowed to charge for
our services on the basis of stated transportation rates established in our 1999
rate case. We may also provide services under negotiated and discounted rates.
Firm shippers that contract for the stated transportation rate are obligated to
pay a monthly demand charge, regardless of the amount of natural gas they
actually transport, for the term of their contracts. Approximately 98% of the
revenue generated is attributed to demand charges. The remaining 2% of the
agreed upon revenue level is attributed to commodity charges based on the
volumes of gas actually transported.
Under the terms of settlement in our 1999 rate case, neither our
existing shippers nor we can seek rate changes until November 1, 2005, at which
time we must file a rate case. Prior to this rate case, we will not be permitted
to increase rates if costs increase, nor will we be required to reduce rates
based on cost savings. As a result, our earnings and cash flow will depend on
future costs, contracted capacity, the volumes of gas transported and our
ability to recontract capacity at acceptable rates.
Until new depreciation rates are approved by the FERC, we continue to
depreciate our transmission plant at the FERC approved annual depreciation rate.
Our annual depreciation rate on transmission plant in service is 2.25%. In order
to avoid a decline in transportation rates set in future rate cases as a result
of accumulated depreciation, we must maintain or increase our rate base by
acquiring or constructing assets that replace or add to existing pipeline
facilities or by adding new facilities.
In our 1995 rate case, the FERC addressed the issue of whether the
federal income tax allowance included in our proposed cost of service was
reasonable in light of previous FERC rulings. In those rulings, the FERC held
that an interstate pipeline is not entitled to a tax allowance for income
attributable to limited partnership interests held by individuals. The
settlement of our 1995 rate case provided that until at least December 2005, we
could continue to calculate the allowance for income taxes in the manner we had
historically used. In addition, a settlement adjustment mechanism was
implemented, which effectively reduced the return on rate base. These provisions
of the 1995 rate case were maintained in the settlement of our 1999 rate case.
We also provide interruptible transportation service. Interruptible
transportation service is transportation in circumstances when capacity is
available after satisfying firm service requests. The maximum rate that may be
charged to interruptible shippers is the sum of the firm transportation maximum
demand and commodity charges. From the settlement of the 1999 rate case through
October 31, 2003, we shared net interruptible transportation service revenue and
any new services revenue on an equal basis with our firm shippers, however, we
were permitted to retain revenue from interruptible transportation service to
offset any decontracted firm capacity. Beginning November 1, 2003, we retain all
revenues from these services.
We are subject to the requirements of the FERC Order Nos. 497 and 566,
which prohibit preferential treatment by interstate natural gas pipelines of
their marketing affiliates and govern how information may be provided to those
marketing affiliates. On November 25, 2003, the
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FERC issued a final rule, Order No. 2004, adopting new standards of conduct for
transmission providers when dealing with their energy affiliates. All
transmission providers must comply with the standards of conduct by June 1,
2004. The standards of conduct are designed to prevent transmission providers
from giving undue preference to any of their energy affiliates. The final rule
generally requires that transmission function employees operate independently of
the marketing function employees and energy affiliates. As required of all
transmission providers, we posted a compliance plan to our website on February
9, 2004. By definition, two of our energy affiliates are Bear Paw Energy, LLC
and Crestone Energy L.L.C., both of which are gathering companies owned by
Northern Border Partners. Our operator, Northern Plains, provides after hours
and weekend gas control services for Bear Paw and Crestone that results in some
cost savings to us. We have requested a waiver to permit Northern Plains to
continue to provide after hours and weekend gas control services for Bear Paw
Energy and Crestone. If the waiver is not granted, the cost to maintain gas
control for us will increase slightly. Several parties have filed for rehearing
on a number of issues, including whether gathering companies should be included
in the definition of energy affiliate.
On August 1, 2002, the FERC issued a Notice of Proposed Rulemaking
regarding the regulation of cash management practices of the natural gas and
other companies that it regulates. On June 26, 2003, the FERC issued an interim
rule in that proceeding that amended its regulations to provide for
documentation requirements for cash management programs and to implement new
reporting requirements. Specifically, under the interim rule, all cash
management agreements between regulated entities and their affiliates must be in
writing, must specify the duties and responsibilities of cash management
participants and administrators, must specify the methods for calculating
interest and for allocating interest income and expense, and must specify any
restrictions on deposits or borrowings by participants. A FERC-regulated entity
must file with the FERC any cash management agreements to which it is a party,
as well as any subsequent changes to such agreements. In addition, a
FERC-regulated entity must notify the FERC when its equity component of
proprietary capital ratio falls below 30%. We do not have a cash management
agreement nor are we required to have one and the FERC was notified. We do not
expect that the FERC policy will have an impact on our cash management
practices.
On July 17, 2002, the FERC issued a Notice of Inquiry Concerning
Natural Gas Pipeline Negotiated Rate Policies and Practices. Subsequently, the
FERC issued an order on July 25, 2003, modifying its prior policy on negotiated
rates. The FERC ruled that it would no longer permit the pricing of negotiated
rates based upon natural gas commodity price indices. Negotiated rates based
upon such indices may continue until the end of the contract period for which
such rates were negotiated, but such rates will not be prospectively approved by
FERC. FERC also imposed certain requirements on other types of negotiated rate
transactions to ensure that the agreements embodying such transactions do not
materially differ from the terms and conditions set forth in the tariff of the
pipeline entering into the transaction. Since our business does not derive a
significant amount of our revenues from negotiated rate transactions, this FERC
ruling is not expected to have a material effect on our business.
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Recent FERC orders in proceedings involving other natural gas pipelines
have addressed certain aspects of the pipelines' creditworthiness provisions set
forth in their tariffs. In addition, industry groups, such as the North American
Energy Standards Board ("NAESB"), are studying creditworthiness standards. On
February 12, 2004, the FERC issued a Notice of Proposed Rulemaking to require
interstate pipelines to follow standardized procedures for determining the
creditworthiness of their shippers. The proposed rule would incorporate by
reference ten consensus standards passed within NAESB and would adopt additional
standards requiring, among other things, standardization of information shippers
provide to establish credit, collateral requirements for service, procedures for
suspension and termination for non-creditworthy shippers and procedures
governing capacity release transactions. Comments are due on the proposed rule
by March 26,2004. Recent FERC orders, and this proposed rule, support greater
collateral requirements for credit on shippers for the construction of new
facilities by a pipeline. The enactment of some of these standards may have the
effect of easing certain creditworthiness requirements and parameters currently
reflected in our tariff. Recent FERC orders have indicated, however, that
pipelines are free to negotiate credit terms relative to the construction of new
facilities by a pipeline, which are then effective for the term of the contract
and are not superceded by tariff provisions once the facilities are completed.
However, we cannot predict the ultimate impact, if any, on us of any resulting
final rule.
In February 2004, the FERC adopted new quarterly financial reporting
requirements and accelerated the filing date for interstate pipeline's annual
financial report. The quarterly reports will include a basic set of financial
statements and other selected data and will be submitted electronically. For
2004, each quarterly report will be due approximately 70 days following the end
of the quarter except for the first quarter report which is due on or before
July 9, 2004. Subsequent reports will be due 60 days after the end of each
quarter. The annual report, previously required to be filed each year on or
before April 30, will be required on or before April 25, 2005 for 2004 and on
April 18 thereafter. No impact is anticipated for complying with these
requirements other than the time and additional expenses for preparation of
these reports.
From time to time, we file to make changes to our tariff to clarify
provisions, to reflect current industry practices and to reflect recent FERC
rulings. In February 2003, we filed to amend the definition of company use gas,
which is gas supplied by our shippers for the operation of our compressor
stations, to clarify the language by adding detail to the broad categories that
comprise company use gas. However, in its March 2003 order, the FERC directed us
to cease collecting electric costs through our company use gas provisions and to
refund with interest, within 90 days, all electric costs that had been collected
through our company use gas provisions. Refunds of approximately $10 million
were made in May 2003.
In August 2003 we filed revised tariff sheets to clarify our procedures
for the awarding of capacity. Several parties protested the filing. One party
requested a show cause proceeding to examine past tariff practices alleging that
we had violated our tariff by denying a service request that would have involved
a short distance for less than
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one year. On September 10, 2003, the FERC rejected our tariff sheets based upon
the conclusion that certain aspects of the proposal were not in accordance with
Commission policy. The FERC did affirm that, up to ninety days prior to the
effective date, we had the right not to sell capacity requested for short
distances or on a short-term basis. We filed a timely request for rehearing of
the Commission's Order in October 2003 which is still pending. We also filed
responses to requests for further information on the award of capacity in the
summer of 2003. We filed our compliance tariff sheets in early December 2003 and
are awaiting a Commission decision on these tariff sheets. Our tariff sheets and
the final orders to be entered in this proceeding will impact how we award
available capacity. With contracts expiring before November 1, 2004, if timely
bids for one year of service or longer on the entire transportation path
available are not received, we may potentially be required to accept bids for
shorter distances that may result in creating segments of capacity of minimal
value.
In March 2004, we filed tariff sheets to implement two balancing
services to assist deliveries at variable load points, such as electrical
generation plant. We also filed with the FERC certain agreements for third party
balancing which we believe are administrative in nature and which will be
terminated upon approval of the new balancing services. Under current orders and
rulings in other proceedings before the FERC, it is unclear whether these
agreements would be deemed non-conforming. However, we do not expect that orders
on these tariff sheets and agreements will have a material adverse impact on our
business.
ENVIRONMENTAL AND SAFETY MATTERS
Our operations are subject to federal, state and local laws and
regulations relating to safety and the protection of the environment, which
include the Resource Conservation and Recovery Act, the Comprehensive
Environmental Response, Compensation and Liability Act of 1980, as amended,
Clean Air Act, as amended, the Clean Water Act, as amended, the Natural Gas
Pipeline Safety Act of 1969, as amended, the Pipeline Safety Act of 1992 and the
Pipeline Safety Improvement Act of 2002.
The Pipeline Safety Improvement Act ("Act") of 2002 was signed into law
in December 2002, providing guidelines for interstate pipelines in the areas of
risk analysis and integrity management, public education programs, verification
of operator qualification programs and filings with the National Pipeline
Mapping System. The Act requires pipeline companies to perform integrity
assessments on pipeline segments that exist in high population density areas or
near specifically identified sites that are designated as high consequence
areas. Pipeline companies are required to perform the integrity assessments
within ten years of the date of enactment and must perform subsequent integrity
assessments on a seven-year cycle. At least 50% of the highest risk segments
must be assessed within five years of the enactment date. In addition, within
one year of enactment, the pipeline's operator qualification programs, in force
since the mandatory compliance date of October 2002, must also conform to
standards provided by the Department of Transportation. The regulations
implementing the Act are not yet final. Rules on integrity management, direct
assessment usage, and the operator qualification
11
standards have been issued. We have made the required filings with the National
Pipeline Mapping System and have reviewed and revised our public education
program. Compliance with the Act is expected to increase our operating costs
particularly related to integrity assessments for our pipeline. As required, we
have developed an overall plan for pipeline integrity management. Detailed
analysis is being performed to determine the priorities and costs for inspecting
and testing our pipeline. However, the plan will be modified as a result of the
findings noted and could result in additional assessment or remediation costs.
Although we expect to include these costs in future rate case filings, total
recovery is not assured. Presently we expect our costs for 2004 for integrity
assessments to be approximately $0.5 million.
Although we believe that our operations and facilities are in general
compliance in all material respects with applicable environmental and safety
regulations, risks of substantial costs and liabilities are inherent in pipeline
operations, and we cannot provide any assurances that we will not incur such
costs and liabilities. Moreover, it is possible that other developments, such as
the enactment of increasingly strict environmental and safety laws, regulations
and enforcement policies by Congress, the FERC, the Department of Transportation
and other federal agencies, state regulatory bodies and the courts, and claims
for damages to property or persons resulting from our operations, could result
in substantial costs and liabilities to us. If we are unable to recover such
resulting costs, earnings and cash distributions could be adversely affected.
ITEM 2. PROPERTIES
We hold the right, title and interest in our pipeline system. With
respect to real property, the pipeline system falls into two basic categories:
(a) parcels which are owned in fee, such as sites for compressor stations, meter
stations, pipeline field offices, and microwave towers; and (b) parcels where
the interest 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 system across certain property was obtained through
exercise of the power of eminent domain. We continue to have the power of
eminent domain in each of the states in which we operate, although we may not
have the power of eminent domain with respect to Native American tribal lands.
Approximately 90 miles of our pipeline are 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. We do have the right of eminent
domain with respect to allotted lands.
In 1980, we entered into a pipeline right-of-way lease with the Fort
Peck Tribal Executive Board, for and on behalf of the Assiniboine and Sioux
Tribes of the Fort Peck Indian Reservation ("Tribes"). This pipeline
right-of-way lease, which was approved by the Department of the Interior in
1981, granted to us the right and privilege to construct
12
and operate our pipeline on certain tribal lands. This pipeline right-of-way
lease expires in 2011. See Item 3. "Legal Proceedings".
In conjunction with obtaining a pipeline right-of-way lease across
tribal lands located within the exterior boundaries of the Fort Peck Indian
Reservation, we also obtained a right-of-way across allotted lands located
within the reservation boundaries. Most of the allotted lands are subject to a
perpetual easement either granted by the Bureau of Indian Affairs ("BIA") for
and on behalf of individual Indian owners or obtained through condemnation.
Several tracts are subject to a right-of-way grant that has a term of 15 years,
expiring in 2015.
ITEM 3. LEGAL PROCEEDINGS
On July 31, 2001, the Tribes of the Fort Peck Indian Reservation filed
a lawsuit in Tribal Court against us to collect more than $3 million in back
taxes, together with interest and penalties. The lawsuit relates to a utilities
tax on certain of our properties within the Fort Peck Indian Reservation. We and
the Tribes, through a mediation process, reached a settlement in principle on
pipeline right-of-way lease and taxation issues. Final documentation has been
completed and is subject to the approval of the BIA which the parties believe
will be obtained in the very near term. This settlement grants to us, among
other things, (i) an option to renew the pipeline right-of-way lease upon agreed
terms and conditions on or before April 1, 2011 for a term of 25 years with a
renewal right for an additional 25 years; (ii) a present right to use additional
tribal lands for expanded facilities; and (iii) release and satisfaction of all
tribal taxes against us. In consideration of this option and other benefits, we
will pay a lump sum amount of $5.9 million and an annual amount of approximately
$1.5 million beginning April 2004. We intend to seek regulatory recovery of the
costs resulting from the settlement. See Item 7. "Management's Discussion and
Analysis of Financial Condition and Results of Operations - Risk Factors and
Information Regarding Forward-Looking Statements."
See Item 1. "Business - FERC Regulation" for a discussion on the
proceeding before the FERC.
We are not currently parties to any other legal proceedings that,
individually or in the aggregate, would reasonably be expected to have a
material adverse impact on our results of operations or financial position.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security holders during
2003.
13
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS
The general partnership interests of Northern Border Pipeline Company
are not traded in an established public market. See Item 12. "Security
Ownership of Certain Beneficial Owners and Management."
In December 2003, our management committee voted to (i) issue equity
cash calls to our general partners in the total amount of $130 million in early
2004 and $90 million in 2007; (ii) fund future growth capital expenditures with
50% equity capital contributions from our general partners; and (iii) change our
cash distribution policy to be effective January 1, 2004, when cash
distributions will be based upon 100% of distributable cash flow as determined
from the Company's financial statements as earnings before interest, taxes,
depreciation and amortization less interest expense and less maintenance capital
expenditures, until January 1, 2008 when the cash distribution policy will be
adjusted to maintain a consistent capital structure. Under the previous cash
distribution policy, approximately $28-$30 million was retained annually by us
to periodically repay outstanding bank debt. The additional equity contributions
in 2004 will be utilized to fully repay our existing bank debt and thereby
reduce our debt leverage in light of existing business conditions. Upon
repayment of the existing bank debt, our next scheduled debt maturity is May
2007. Pursuant to a cash call in January 2004, Northern Border Partners and TC
PipeLines contributed $45.5 million and $19.5 million, respectively, to us to be
used to repay a portion of our existing indebtedness under the 2002 Pipeline
Credit Agreement.
14
ITEM 6. SELECTED FINANCIAL DATA
(in thousands, except other financial and operating data)
The following table sets forth, for the periods and at the dates
indicated, selected historical financial data for us. The selected financial
information should be read in conjunction with the Financial Statements and the
Notes and Item 7. "Management's Discussion and Analysis of Financial Condition
and Results of Operations," which are included elsewhere in this report.
YEAR ENDED DECEMBER 31,
--------------------------------------------------------------------------------
2003 2002 2001 2000 1999
---------- ---------- ---------- ---------- ----------
INCOME DATA:
Operating revenues, net $ 324,185 $ 321,050 $ 313,088 $ 311,022 $ 298,347
Operations and
maintenance 43,791 41,442 33,695 41,548 38,708
Depreciation and
amortization 57,779 58,714 57,516 57,328 51,908
Taxes other than income 29,634 28,436 25,636 27,979 30,320
Regulatory credit - - - - -
---------- ---------- ---------- ---------- ----------
Operating income 192,981 192,458 196,241 184,167 177,411
Interest expense, net 44,857 51,525 55,351 65,161 60,214
Other income (expense) 76 1,786 (432) 8,058 1,363
---------- ---------- ---------- ---------- ----------
Net income to partners $ 148,200 $ 142,719 $ 140,458 $ 127,064 $ 118,560
========== ========== ========== ========== ==========
CASH FLOW DATA:
Net cash provided by
operating activities $ 193,270 $ 224,356 $ 197,322 $ 175,967 $ 171,466
Capital expenditures 12,918 9,243 54,659 15,523 101,678
Distributions to
partners 153,978 164,126 143,032 134,904 127,163
BALANCE SHEET DATA
(AT END OF YEAR):
Property, plant
and equipment, net $1,591,755 $1,635,961 $1,685,665 $1,686,992 $1,731,394
Total assets 1,691,309 1,740,037 1,751,869 1,768,505 1,796,691
Long-term debt,
including current
maturities 821,498 848,906 863,666 863,267 900,459
Partners' equity 802,438 809,772 833,594 826,995 834,835
OTHER FINANCIAL DATA:
Ratio of earnings to
fixed charges (1) 4.3 3.8 3.5 2.9 3.0
OPERATING DATA:
Natural gas delivered
(millions of cubic
feet) 849,920 838,736 820,851 852,674 834,833
Average throughput
(millions of cubic
feet per day) 2,396 2,369 2,312 2,400 2,353
- --------------------
(1) "Earnings" means the sum of pre-tax income from continuing operations
and fixed charges. "Fixed charges" means the sum of (a) interest
expensed and capitalized; (b) amortized premiums, discounts and
capitalized expenses related to indebtedness; and (c) an estimate of
interest within rental expenses.
15
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
Our discussion and analysis of our financial condition and operations
are based on our Financial Statements, which were prepared in accordance with
accounting principles generally accepted in the United States of America. You
should read the following discussion and analysis in conjunction with our
Financial Statements included elsewhere in this report.
OVERVIEW
For Northern Border Pipeline, there are several major business drivers.
First, a healthy long-term supply outlook is critical. Because the primary
source of gas supply that is transported on our pipeline system is in the
western Canadian sedimentary basin, western Canadian supply trends are
particularly important to us. The current outlook for western Canadian supply
looks stable for the foreseeable future however production has exceeded new
reserve addition in recent years. Increased Canadian consumption related to the
extraction process for oil sands projects as well as restrictions on gas
production to protect oil sand reserves could also impact supplies of natural
gas for export. The supply outlook may be significantly enhanced over time by
new proposed Alaskan and Mackenzie Delta supplies reaching the western Canadian
pipeline grid potentially beginning by the end of this decade.
Natural gas markets are also critical to our financial performance. Our
pipeline system serves natural gas markets in the upper midwestern area of the
United States and accesses a major trading hub in the Chicago area. Market
growth has been steady with both heating load growth and direct end-user growth
such as power plants and ethanol plants. However, competitive pipeline projects
may have a negative impact on our profitability.
We charge fees for transportation, which are primarily fixed and are
based on the amount of capacity reserved by each shipper. Contracting with
shippers to reserve the available pipeline capacity as existing contracts expire
is a critical factor in our success. The weighted average life of our contracts
as of December 31, 2003 was approximately three and one third years. During
2003, we were successful in recontracting, at maximum rates, all the capacity
under contracts that expired on or before November 2003.
The composition of natural gas affects the volume of natural gas that
is transported through a pipeline system. Beginning in 2000, the energy content
of natural gas that we receive at the Canadian border has declined modestly from
1,023 British Thermal Units (Btus) per cubit foot (cf) to 1,005 Btus/cf. Our
transportation contracts in conjunction with our tariff define both the volume
and equivalent Btu value of the gas to be transported. A reduction in the Btu
level results in a higher volume of natural gas to be transported to meet an
overall equivalent Btu value of the gas. The Btu level decline that is being
experienced is primarily the result of greater processing capacity in Alberta,
Canada. The change has caused us to reduce our available capacity by almost 2
percent to be able to maintain our high standard of system reliability
16
for our customers. Although Btu levels could theoretically go lower, we believe
the Btu level will stabilize near the current level of 1,005 Btus/cf.
As was the case last year, we are in re-contracting discussions with
our customers for contracts that will expire prior to November 1, 2004, which
represents approximately 30% of our system capacity. The value of capacity on
interstate pipelines is driven by supply and demand conditions. In particular,
the relationship between gas prices in Canada and prices in the midwestern U.S.
markets will determine the underlying value of transportation. The current gas
balance in western Canada is such that our transportation has been commercially
attractive for available supply that is not consumed within western Canada or
committed to transportation capacity on other pipelines reaching downstream
markets. To maintain an adequate gas balance in western Canada, production will
need to grow moderately in the future to meet anticipated demand primarily
driven by gas consumption in the extraction and processing associated with
Canadian oil sands development. Canada holds an estimated 1.6 trillion barrels
of bitumen reserves. Bitumen, after it is extracted from sand, can be upgraded
to synthesized crude oil through several processes. The extraction and
processing of bitumen require significant quantities of natural gas. We do not
know how many of the announced oil sands development projects will be approved
and constructed but the demand for transportation on our pipeline systems could
be affected adversely by the additional competition for Canadian gas supply that
would result.
We continue to work with producers and marketers to develop the
contractual support for a new proposed 300-mile pipeline project, the Bison
Pipeline, to connect the coal bed methane reserves in the Powder River Basin to
markets served by us. We intend to hold a new open season for the Bison Pipeline
when production increases to levels that we believe will support the project. If
sufficient interest commitments are received, we will pursue regulatory
approvals.
We will continue to focus on safe, efficient, and reliable operations
and the further development of our pipeline. We are working to maintain our
position as a low cost transporter of Canadian gas to the midwestern U.S. and
provide highly valued services to our customers. Growth may occur through
incremental projects intended to access new markets or supply areas and
supported by long-term contracts.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
Certain amounts included in or affecting our Financial Statements and
related disclosures must be estimated, requiring us to make certain assumptions
with respect to values or conditions that cannot be known with certainty at the
time the financial statements are prepared. The preparation of financial
statements in conformity with accounting principles generally accepted in the
United States of America 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. Any effects on our business,
financial position or results of operations resulting from revisions to these
estimates are recorded in the period in which the
17
facts that gave rise to the revision become known.
Our significant accounting policies are summarized in Note 2 - Notes to
Financial Statements included elsewhere in this report. Certain of our
accounting policies are of more significance in our financial statement
preparation process than others. Our accounting policies conform to Statement of
Financial Accounting Standards ("SFAS") No. 71, "Accounting for the Effects of
Certain Types of Regulation." Accordingly, certain assets that result from the
regulated ratemaking process are recorded that would not be recorded under
accounting principles generally accepted in the United States of America for
nonregulated entities. We continually assess whether the regulatory assets are
probable of future recovery by considering such factors as regulatory changes
and the impact of competition. If future recovery ceases to be probable, we
would be required to write-off the regulatory assets at that time. At December
31, 2003, we have reflected regulatory assets of $8.2 million, which are being
recovered from our shippers over varying periods of time.
Our long-lived assets are stated at original cost. We must use
estimates in determining the economic useful lives of those assets. For utility
property, no retirement gain or loss is included in income except in the case of
retirements or sales of entire regulated operating units. The original cost of
utility property retired is charged to accumulated depreciation and
amortization, net of salvage and cost of removal.
Our accounting for financial instruments is in accordance with SFAS No.
133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No.
133 requires that every derivative instrument be recorded on the balance sheet
as either an asset or liability measured at its fair value. The statement
requires that changes in the derivative's fair value be recognized currently in
earnings unless specific hedge accounting criteria are met. Special accounting
for qualifying hedges allows a derivative's gains and losses to offset related
results on the hedged item in the income statement. At December 31, 2003, our
balance sheet included assets from derivative financial instruments of $16.6
million.
RESULTS OF OPERATIONS
Our net income to partners was $148.2 million in 2003, compared to net
income of $142.7 million in 2002 and $140.5 million in 2001. Our 2003 operating
results benefited from increased operating revenues from Northern Border
Pipeline's Order 637 Compliance filing which went into effect October 1, 2003
and the ability to enter into short-term contracts effective November 1, 2003,
the re-contracting of capacity previously held by Enron North America Corp.
("ENA"), and reductions in interest expense due to lower interest rates.
Partially offsetting these increases to our operating results were higher
operations and maintenance expenses for 2003 as compared to 2002. Our increase
in net income in 2002 over 2001 resulted from reductions in interest rates,
which reduced our interest expense for 2002 as compared to 2001. In addition we
realized increased operating revenues in 2002 resulting from Project 2000, our
pipeline expansion and extension placed in service in October 2001. Our 2001
results were reduced by reserves for uncollectible receivables.
18
Operating revenues were $324.2 million in 2003, $321.1 million in 2002
and $313.1 million in 2001. The $3.1 million increase in operating revenues in
2003 over 2002 resulted primarily from additional revenues of approximately $1.8
million related to the re-contracted capacity of ENA contracts. ENA filed for
Chapter 11 bankruptcy protection in December 2001 (see "The Impact Of Enron's
Chapter 11 Filing On Our Business"). In addition we recognized revenues from our
ability to now offer short-term firm contracts and also transportation service
beyond a shipper's contracted transportation path. The increase in operating
revenues in 2002 over 2001 was primarily due to additional revenues of
approximately $10.3 million associated with the completion of Project 2000 in
October 2001. The impact of the additional revenues associated with Project 2000
was partially offset by uncollected revenues associated with the transportation
capacity formerly held by ENA. For 2002, the revenues lost on this capacity
totaled approximately $1.8 million.
Operations and maintenance expenses were $43.8 million in 2003, $41.4
million in 2002 and $33.7 million in 2001. The 2003 expense included a $3.1
million charge for our allocation from Northern Plains related to the Enron cash
balance plan under funding (see "The Impact of Enron's Chapter 11 Filing On Our
Business"). In 2003, we also had increases in salaries and benefits,
rights-of-way damages, and telecommunication expenses offset by decreases in
electric power costs, as compared to 2002. The 2002 expense included a $10.0
million reserve for costs associated with the treatment of previously collected
quantities of natural gas used in utility operations to cover electric power
costs. The FERC ordered refunds for these costs in 2003 (see "FERC Regulation").
The 2002 expense also included an increase in regulatory commission expense, and
decreases in employee benefit expense, administrative expense, and bad debt
expense as compared to 2001.
Depreciation and amortization expense was $57.8 million in 2003, $58.7
million in 2002 and $57.5 million in 2001. The decrease from 2002 to 2003
primarily reflects asset retirements. The increase between 2001 and 2002
reflects additional expense for the assets related to Project 2000 placed in
service in October 2001.
Taxes other than income were $29.6 million in 2003, $28.4 million in
2002 and $25.6 million in 2001. The increase in 2003 from 2002 is due primarily
to a refund received in 2002 from Minnesota for previously paid use taxes
resulting from a ruling by the Minnesota Supreme Court. The increase in taxes
other than income in 2002 from 2001 was due primarily to adjustments to ad
valorem taxes. We periodically review and adjust our estimates of ad valorem
taxes. Reductions to previous estimates in 2001 exceeded reductions to previous
estimates in 2002 by approximately $2.1 million.
Interest expense was $44.9 million in 2003, $51.5 million in 2002 and
$55.4 million in 2001. Interest expense for both 2003 and 2002 decreased from
prior year levels due to a decrease in our average interest rate as well as a
decrease in our average debt outstanding. The 2001 results included $0.9 million
of interest expense capitalized primarily related to the construction of Project
2000 facilities.
Other income (expense) was $0.1 million in 2003, $1.8 million in
19
2002 and ($0.4 million) in 2001. In 2003, we recorded expense of approximately
$0.6 million for a repayment of amounts previously received for vacated
microwave frequency bands, interest expense of $0.3 million due to the FERC
ordered refunds of electric power costs and $0.2 million of interest income
received related to a sales tax refund on exempt purchases. The amount for 2002
includes approximately $0.6 million for amounts received for previously vacated
microwave frequency bands and income of $0.2 million due to a reduction in
reserves previously established. The amount for 2001 includes a charge of
approximately $1.5 million for an uncollectible receivable from a
telecommunications company that had purchased excess capacity on our
communication system and a $0.7 million charge for reserves established. We
recorded an allowance for equity funds used during construction of $0.9 million
in 2001 primarily due to the construction of Project 2000 facilities.
LIQUIDITY AND CAPITAL RESOURCES
SUMMARY OF CERTAIN CONTRACTUAL OBLIGATIONS
Payments Due by Period
-------------------------------------------
Less Than After
Total 1 Year 1-3 Years 4-5 Years 5 Years
-----------------------------------------------------
(In Thousands)
Senior Notes due 2007 225,000 - 225,000 - -
Senior Notes due 2009 200,000 - - 200,000 -
Senior Notes due 2021 250,000 - - - 250,000
Credit Agreement due
2005 131,000 - 131,000 - -
Operating Leases (a) 19,254 5,757 4,784 4,784 3,929
-------- ------- -------- -------- --------
Total $825,254 $ 5,757 $360,784 $204,784 $253,929
======== ======= ======== ======== ========
(a) See Note 7 - Notes to Financial Statements.
DEBT AND CREDIT FACILITIES
We entered into a $175 million three-year credit agreement ("2002
Pipeline Credit Agreement") with certain financial institutions in May 2002. The
2002 Pipeline Credit Agreement replaced a previous credit agreement. The 2002
Pipeline Credit Agreement is to be used to refinance existing indebtedness and
for general business purposes. At December 31, 2003, $131 million was
outstanding under the 2002 Pipeline Credit Agreement at an average interest rate
of 1.95%. The 2002 Pipeline Credit Agreement requires the maintenance of a ratio
of EBITDA (net income plus interest expense, income taxes and depreciation and
amortization) to interest expense of greater than 3 to 1. The 2002 Pipeline
Credit Agreement also requires the maintenance of the ratio of indebtedness to
EBITDA of no more than 4.5 to 1. At December 31, 2003, we were in compliance
with these covenants.
At December 31, 2002, we had outstanding $65 million of Series D Senior
Notes issued in a $250 million private placement under a July 1992 note purchase
agreement. The Series D Senior Notes matured in August 2003. We borrowed under
the 2002 Pipeline Credit Agreement to repay the Series D Senior Notes.
In April 2002, we completed a private offering of $225 million of
20
6.25% Senior Notes due 2007 ("2002 Pipeline Senior Notes"). In September 2001,
we completed a private offering of $250 million of 7.50% Senior Notes due 2021
("2001 Pipeline Senior Notes"). In August 1999, we completed a private offering
of $200 million of 7.75% Senior Notes due 2009 ("1999 Pipeline Senior Notes").
The 2002 Pipeline Senior Notes, 2001 Pipeline Senior Notes and 1999 Pipeline
Senior Notes (collectively "Pipeline Senior Notes") were subsequently exchanged
in registered offerings for notes with substantially identical terms. The
indentures under which the Pipeline Senior Notes were issued do not limit the
amount of unsecured debt we incur, but they do contain material financial
covenants, including restrictions on incurrence of secured indebtedness. The
proceeds from the Pipeline Senior Notes were used to reduce indebtedness
outstanding.
We entered into interest rate swap agreements with notional amounts
totaling $225 million in May 2002. Under the interest rate swap agreements, we
make payments to counter parties at variable rates based on the London Interbank
Offered Rate and in return receive payments based on a 6.25% fixed rate. The
swaps were entered into to hedge the fluctuations in the market value of the
2002 Pipeline Senior Notes. At December 31, 2003, the average effective interest
rate on our interest rate swap agreements was 2.31%.
Short-term liquidity needs will be met by operating cash flows and
through the 2002 Pipeline Credit Agreement. Long-term capital needs may be met
through the ability to issue long-term indebtedness.
CASH FLOWS FROM OPERATING ACTIVITIES
Cash flows provided by operating activities were $193.3 million in
2003, $224.4 million in 2002 and $197.3 million in 2001. The $31.1 million
decrease in 2003 from 2002 was primarily due to the payment of the FERC ordered
refunds related to the electric power costs and the discontinuance of certain
shipper transportation prepayments. The $27.1 million increase in 2002 from 2001
was primarily due to an increase in operating revenues and the impact of rate
case refunds in 2001. In 2001, we realized net cash outflows of approximately
$4.7 million related to our rate case refunds. During the first quarter of 2001,
we made refunds to our shippers totaling $6.8 million, which included
approximately $2.1 million collected in the first quarter of 2001 with the
remainder collected previously.
CASH FLOWS FROM INVESTING ACTIVITIES
Cash used in investing activities was $12.9 million for 2003 as
compared to $9.2 million for 2002 and $54.7 million for 2001. The 2003, 2002 and
2001 amounts include $0.9 million, $0.3 million and $49.0 million, respectively,
for Project 2000. The remaining capital expenditures for 2003, 2002 and 2001
were primarily related to renewals and replacements of existing facilities.
Total capital expenditures for 2004 are estimated to be $14 million
primarily related to renewals and replacements of existing facilities. We
currently anticipate funding our 2004 capital expenditures primarily by
borrowing on our credit facility and using operating cash flows.
21
CASH FLOWS FROM FINANCING ACTIVITIES
Cash flows used in financing activities were $177.0 million for the
year ended December 31, 2003 as compared to $200.8 million for the same period
in 2002 and $160.7 million for the same period in 2001. Distributions to our
partners were $154.0 million, $164.1 million and $143.0 million for 2003, 2002
and 2001, respectively. The decrease from 2002 to 2003 in distributions was
primarily due to the impact of the electric power refunds ordered by FERC on
March 27, 2003. The increase from 2001 to 2002 in distributions was primarily
due to our improved operating results.
For 2003, 2002 and 2001, our borrowings on long-term debt totaled
$142.0 million, $431.9 million and $385.4 million, respectively, which were
primarily used to repay previously existing indebtedness. For 2002, we received
net proceeds from the 2002 Pipeline Senior Notes of approximately $223.5
million. The net proceeds from the issuance of the 2001 Pipeline Senior Notes
totaled approximately $247.2 million in 2001. Our borrowings under our credit
agreements were $131.0 million in 2003, $207.0 million in 2002 and $136.0
million in 2001. Total payments on debt were $165.0 million, $468.0 million and
$374.0 million in 2003, 2002 and 2001, respectively.
In April 2002, we received $2.4 million from the termination of forward
starting interest rate swaps upon issuance of the 2002 Pipeline Senior Notes
(see Note 6 - Notes to Financial Statements). In September 2001, we paid
approximately $4.1 million to terminate interest rate swap agreements upon
issuance of the 2001 Pipeline Senior Notes. The swaps were entered into to hedge
the fluctuations in Treasury rates and spreads between the execution date of the
swaps and the issuance of the 2002 and 2001 Pipeline Senior Notes. For 2001, we
recognized a decrease in bank overdraft of $22.4 million. At December 31, 2000,
we reflected the bank overdraft primarily due to rate refund checks outstanding.
NEW ACCOUNTING PRONOUNCEMENTS
In the third quarter of 2001, the Financial Accounting Standards Board
issued SFAS No. 143, "Accounting for Asset Retirement Obligations." In November
2002, the FASB issued Interpretation No. 45, "Guarantor's Accounting and
Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others." In 2003, the FASB issued SFAS No. 149, "Amendment of
Statement 133 on Derivative Instruments and Hedging Activities", SFAS No. 150,
"Accounting for Certain Financial Instruments with Characteristics of Both
Liabilities and Equity," and EITF No. 00-21 "Revenue Arrangements with Multiple
Deliverables." See Note 9 - Notes to Financial Statements.
THE IMPACT OF ENRON'S CHAPTER 11 FILING ON OUR BUSINESS
On December 2, 2001, Enron filed a voluntary petition for bankruptcy
protection under Chapter 11 of the United States Bankruptcy Code. Certain wholly
owned Enron subsidiaries also filed for Chapter 11 bankruptcy protection on
December 2, 2001 and thereafter. We have not filed for bankruptcy protection.
Northern Plains, Pan Border and Northwest Border are our general partners. Each
of Northern Plains and Pan Border are wholly owned subsidiaries of Enron, and
Northwest Border is a wholly owned subsidiary of TransCanada. Northern Plains
and Pan Border were not among the Enron companies filing for Chapter 11
protection.
22
The business of Enron and its subsidiaries that have filed for
bankruptcy protection are currently being administered under the direction and
control of the bankruptcy court. An unsecured creditors committee has been
appointed in the Chapter 11 cases. The creditors committee is responsible for
general oversight of the bankruptcy case, and has the power, among other things,
to: investigate the acts, conduct, assets, liabilities, and financial condition
of the debtor, the operation of the debtor's business and the desirability of
the continuance of such business; participate in the formulation of a plan of
reorganization; and file acceptances or rejections to such a plan.
On June 25, 2003, Enron announced the organization of CrossCountry
Energy Corp., a newly formed holding company, to hold, among other assets,
Enron's ownership interest in Northern Plains and Pan Border. The motion filed
in Bankruptcy Court to approve the proposed transfer of those ownership
interests was approved on September 25, 2003. An amended order on December 18,
2003 made the approval applicable to CrossCountry Energy, LLC ("CrossCountry").
In connection with the closing, CrossCountry and Enron will enter into a
transition services agreement pursuant to which Enron will provide to
CrossCountry, on an interim, transitional basis, various services, including but
not limited to (i) information technology services, (ii) accounting system usage
rights and administrative support (iii) contract management and purchasing
support services (iv) corporate secretary services, and (v) payroll, employee
benefits and administrative services. In turn, these services are provided to us
through Northern Plains.
On January 9, 2004, the Bankruptcy Court approved as complete the
amended joint Chapter 11 plan and related disclosure statement ("Chapter 11
Plan"). The Chapter 11 Plan has been submitted to the creditors for approval.
Several creditors have filed objections to the Chapter 11 Plan, including
Pension Benefit Guaranty Corporation ("PBGC"). The Bankruptcy Court has
scheduled a hearing for April 20, 2004 on the approval. Under the Chapter 11
Plan, it is anticipated that if CrossCountry is not sold to a third party, as
permitted by the Chapter 11 Plan, its shares would be distributed directly or
indirectly to creditors of the debtors.
Enron's filing for bankruptcy protection has impacted us. At the time
of the filing of the bankruptcy petition, we had a number of contractual
relationships with Enron and its subsidiaries. Northern Plains provided and
continues to provide operating and administrative services for us. Northern
Plains has continued to meet its operational and administrative service
obligations under the existing agreement, and we believe it will continue to do
so.
ENA, a wholly owned subsidiary of Enron that is in bankruptcy, was a
party to transportation contracts which obligated ENA to pay for 3.5% of our
capacity. In 2002, ENA rejected and terminated all of its contracts on us. We
filed claims against ENA for damages for breach of contract and other claims.
These claims are unsecured claims against Enron and ENA's bankruptcy estate. We
are uncertain regarding the ultimate amount of damages for breach of contract or
other claims that we will be able to establish in the bankruptcy proceeding, and
we cannot predict the amounts that we will
23
collect or the timing of collection. We believe, however, that any such delay in
collecting or failure to collect will not have a material adverse effect on our
financial condition.
On December 31, 2003, Enron filed a motion seeking approval of the
Bankruptcy Court to provide additional funding to, and for authority to
terminate the Enron Corp. Cash Balance Plan ("Plan") and certain other defined
benefit plans of Enron's affiliated in 'standard terminations' within the
meaning of Section 4041 of the Employee Retirement Income Security Act of 1974,
as amended ("ERISA"). Such standard terminations would satisfy all of the
obligations of Enron and its affiliates with respect to funding liabilities
under the Plan. In addition, a standard termination would eliminate the
contingent claims of the PBGC) against Enron and its affiliates with respect to
the funding liabilities under the Plan. On January 30, 2004, the Bankruptcy
Court entered an order authorizing termination, additional funding and other
actions necessary to effect the relief requested. Pursuant to the Bankruptcy
Court order, any contributions to the Plan are subject to the prior receipt of a
favorable determination by the Internal Revenue Service that the Plan is
tax-qualified as of the date of termination. In addition, the Bankruptcy Court
order provides that the rights of PBGC and others to assert that their filed
claims have not been released or adjudicated as a result of the Bankruptcy order
and Enron and all other interested parties retained the right to assert that
such claims had been adjudicated or released.
Enron management has informed Northern Plains that it will seek funding
contributions from each member of its ERISA controlled group of corporations
that employs or employed individuals who are, or were, covered under the Plan.
Northern Plains has advised us that it is a member controlled group of
corporations of Enron that employs, or employed, individuals who are, or were,
covered under the Plan and that an amount of approximately $3.1 million has been
estimated for our share of Northern Plains' proportionate share of the up to
$200 million estimated termination costs authorized by the Bankruptcy Court
order. Under the operating agreement with Northern Plains, these increased costs
may be our responsibility. We have accrued this amount to satisfy claims of
reimbursement for these termination costs. While the final amounts have not been
determined, we believe this accrual is adequate to cover the allocation of these
costs to us.
Enron is the grantor of the Enron Gas Pipeline Employee Benefit Trust
(the "Trust"), which when taken together with the Enron Corp. Medical Plan for
Inactive Participants (the "Medical Plan") constitutes a "voluntary employees'
beneficiary association" or "VEBA" under Section 501(c)(9) of the Internal
Revenue Code. In October 2002, Northern Plains was advised that Enron had
notified the committee that has administrative and fiduciary oversight related
to the Trust and the Medical Plan, that Enron had made the determination to
begin necessary steps to partition the assets of the Trust and the related
liabilities of the Medical Plan among all of the participating employers of the
Trust. The Trust was established as a regulatory requirement for inclusion of
certain costs for post-employment medical benefits in the rates established for
the affected pipelines, including us. Enron requested the enrolled actuary to
prepare an analysis and recommendation for the allocation of the Trust's assets
and associated
24
liabilities among all the participating employers. On July 22, 2003, Enron
sought approval of the Bankruptcy Court to terminate the Trust and to distribute
its assets among certain identified pipeline companies, one being Northern
Plains. If Enron's relief as requested is granted, Northern Plains would assume
retiree benefit liabilities, estimated as of June 30, 2002, of $1.9 million
with an asset allocation of $0.8 million. An objection to the motion has been
filed and no hearing date has been set. An additional actuary has been engaged
by Enron to review the analysis and recommendations for allocations. There can
be no assurances that the allocation of liabilities and assets will not change
from those set forth in the motion.
Enron's filing for bankruptcy protection and related developments have
had other impacts on our business and management. Numerous shareholder and
employee class action lawsuits have been initiated against Enron, its former
independent accountants, legal advisors, executives, and board members. Enron
has received several requests for information from different federal and state
agencies, including the FERC, and committees of the United States House of
Representatives and Senate. Some of the information requested from Enron may
include information about us. While we have not been subject to these
investigations or lawsuits, it is possible that in the documentation production
by Enron and others, confidential proprietary or commercially sensitive
information concerning us may have been produced. It is also possible that some
of this information may be made available to the public.
While Northern Plains and Pan Border have not filed for Chapter 11
bankruptcy protection, their stock is owned by Enron, which is in bankruptcy. As
noted above, Enron could sell its interest in Northern Plains and/or Pan Border,
or take other action with respect to their investment in us. Enron could also
cause Northern Plains and Pan Border to file for bankruptcy protection. We have
had no indication from Enron that it intends to cause such companies to file for
bankruptcy protection.
We are managed by a four-member management committee. Three
representatives are designated by Northern Border Partners, with each of its
general partners selecting one representative, and one representative is
designated by TC PipeLines. The vote among Northern Border Partners'
representatives is in proportion to their general partner interests in Northern
Border Partners. As a result, the 70% voting interest of Northern Border
Partners' three representatives is allocated 35%, 22.75% and 12.25% among
Northern Plains, Pan Border and Northwest Border, respectively. If Enron were to
sell the stock of Northern Plains and Pan Border, the purchaser would have the
right to appoint a majority of our management committee and control our
activities, except for those activities requiring a unanimous vote which include
changes to our cash distribution policy, certain expansions and extensions of
the pipeline, some transfers of general partner interests and settlement of rate
cases.
If Northern Plains and Pan Border were to file for bankruptcy
protection, Northern Border Partners' Partnership Agreement provides that they
would automatically be deemed to have withdrawn as general partners of Northern
Border Partners. It is possible that the
25
enforceability of the automatic withdrawal provisions in this partnership
agreement may be challenged. The success and impact of a challenge are unknown.
Upon the occurrence of such an event of withdrawal, the remaining general
partner of Northern Border Partners would have the right to purchase the
withdrawing partners' general partnership interests. If the remaining general
partner does not purchase such general partnership interests, the limited
partners of Northern Border Partners would have the right to elect new general
partners. In the event that the remaining general partner does not elect to
purchase the general partner interests or a successor is not so elected by the
limited partners, then the partnership shall be dissolved. In either event, the
party acquiring the general partner interests currently held by Northern Plains
and Pan Border would have the right to appoint a majority of our management
committee and control our activities, except for those activities requiring a
unanimous vote.
Northern Plains also serves as our operator. If Northern Plains were to
file for bankruptcy protection, it could potentially be removed as operator. Our
credit agreement provides that it would be an event of default there under if
Northern Plains were replaced as operator without the consent of the lenders
there under.
Other than the items identified above, we are not aware of any claims
made against us that arise out of the Enron bankruptcy cases. We continue to
monitor developments at Enron, to assess the impact on us of our existing
agreements and relationships with Enron and its subsidiaries, and to take
appropriate action to protect our interests.
PUBLIC UTILITY HOLDING COMPANY ACT ("PUHCA") REGULATION
Besides its ownership in Northern Plains and Pan Border, all of the
common stock of Portland General Electric Company ("PGE") is owned by Enron. As
the owner of PGE's common stock, Enron is a holding company for purposes of the
Public Utility Holding Company Act of 1935 ("PUHCA"). Following Enron's
acquisition of PGE in 1997, Enron annually filed a statement claiming an
exemption from all provisions of PUHCA (except the provision which addresses the
acquisition of public utility company affiliates) under Section 3(a)(1). Due to
Enron's bankruptcy filing in December 2001, Enron was no longer able to provide
necessary financial information needed to file the exemption statement. As a
result, in February 2002, Enron applied to the Securities and Exchange
Commission ("SEC") for an order of exemption under Sections 3(a)(1), 3(a)(3) and
3(a)(5).
On December 29, 2003, the SEC issued an order denying the two
applications filed by Enron seeking exemption as a public utility holding
company under Sections 3(a)(1), 3(a)(3) and 3(a)(5) of PUHCA. The SEC order
found, relative to the application under Section 3(a)(1), that Enron's
subsidiary, PGE, is not predominantly and substantially intrastate in character
and does not carry on business substantially in a single state. Relative to the
application under Sections 3(a)(3) and 3(a)(5), the SEC found that Enron was
unable to establish that it is only incidentally a holding company and that it
derives no material part of its income from an electric utility subsidiary.
On December 31, 2003, Enron and other related entities filed an
application under Section 3(a)(4) of PUHCA (the "3(a)(4) Application").
26
This application claims, for each of the applicants, an exemption as a public
utility holding company based on the temporary nature of the applicants' current
or proposed interest in PGE under the Chapter 11 Plan filed by Enron and certain
of its subsidiaries. By SEC order entered January 30, 2004, the hearing date on
Enron's pending application for exemption under PUHCA was postponed until
February 9, 2004 and by SEC order entered February 6, 2004, the hearing date was
postponed until further notice. On March 9, 2004, pursuant to an offer of
settlement that had been previously made to the SEC, Enron, withdrew the 3(a)(4)
Application and registered as a holding company under PUHCA. Immediately after
Enron registered, the SEC issued two orders, one granting Enron and its
subsidiaries authority to undertake certain transactions without further
authorization from the SEC under PUHCA (referred to as the "Omnibus Order") and
the other approving Enron's Fifth Amended Bankruptcy Plan (referred to as the
"Plan Order").
The Omnibus Order authorizes, among other items, certain transactions
specific to Northern Border Partners, L.P. and its subsidiaries, including
authority for Northern Border Partners and us to declare and pay distributions
out of capital. Further, the Omnibus Order authorizes Northern Border Partners
to invest as much as an additional $1 billion in natural gas gathering,
processing, storage and transportation assets and to issue and sell debt and
equity securities as may be required to fund such investments or acquisitions.
The authorizations are effective until the earlier of the deregistration of
Enron under PUHCA or July 31, 2005. We believe that the authority relating to
Northern Border Partners and its affiliates in the Omnibus Order minimizes the
likelihood that our business will be adversely impacted by Enron's registration
under PUHCA.
However, PUHCA imposes a number of restrictions on the operations of a
registered holding company and its subsidiaries within the registered holding
company system that can become materially more expensive and cumbersome than
operations by companies that are not subject to, or exempt, from PUHCA. As a
subsidiary of a registered holding company, we are subject to regulation by the
SEC with respect to the acquisition of the securities of public utilities; the
acquisition of assets and interests in any other business, declaration and
payment of certain cash distributions; intra-system borrowings or
indemnifications; sales, services or construction transactions with other
holding company system companies; and the issuance of debt or equity securities,
among other matters. To the extent those regulated activities are not approved
under the Omnibus Order or otherwise exempt under various rules and the
regulations promulgated under PUHCA, we would need to seek additional approvals
from the SEC. At this time, we do not believe that there is a need to seek any
additional authorizations from the SEC in order to conduct our operations.
Nevertheless, there can be no assurance that PUHCA will not have an adverse
impact on our operations as a result of Enron's registration as a holding
company.
RISK FACTORS AND 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.
These forward-looking statements are identified as any statement that does not
relate strictly to historical or current facts. Forward-looking statements are
not guarantees of
27
performance. They involve risks, uncertainties and assumptions. The future
results of our operations may differ materially from those expressed in these
forward-looking statements. Such forward-looking statements include:
- the discussions in "Management's Discussion and Analysis of Financial
Condition and Results of Operations - The Impact Of Enron's Chapter 11
Filing On Our Business";
- the discussions in "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Overview"; and
- the discussions in "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Liquidity and Capital Resources."
Although we believe that our expectations regarding future events are
based on reasonable assumptions within the bounds of our knowledge of our
business, we cannot assure you that our goals will be achieved or that our
expectations regarding future developments will be realized.
With this in mind, you should consider the following important factors
that could cause actual results to differ materially from those in the
forward-looking statements:
- Any shipper's failure to perform its contractual obligations could
adversely impact our cash flows and financial condition. Some of our
shippers or their owners have experienced a deterioration of their
financial condition. Should one or more file for bankruptcy protection,
our ability to recover amounts owed or to resell the capacity would be
impacted.
- Since Northern Plains, our operator, is a wholly-owned subsidiary of
Enron and depends on Enron and certain of its affiliates for some
services it provides to us, potential further developments in the Enron
Chapter 11 proceeding may cause Northern Plains to be unable to perform
under its agreement or to incur increases in costs to continue or
replace the services provided by Enron and its affiliates. Higher costs
may result from the termination of Enron's pension plan and partition of
the Enron Gas Pipeline Employee Benefit Trust. Also, Enron announced its
intention to create a new pipeline operating entity, which will include
Northern Plains. See " The Impact Of Enron's Chapter 11 Filing On Our
Business" above.
- Our ability to recontract capacity as existing contracts terminate
for maximum transportation rates will be subject to a number of factors
including availability of natural gas supplies from the western Canadian
sedimentary basin, the demand for natural gas in our market areas and
the basis differential between the receipt and delivery points on our
28
system. See "Overview" above and Item 1. "Business - Demand For
Transportation Capacity."
- We are subject to extensive regulation by the FERC governing all
aspects of our business, including our transportation rates. Under our
1999 rate case settlement, neither our existing customers nor we can
seek rate changes until November 2005, at which time we are obligated to
file a rate case. We cannot predict what challenges we may have to our
rates in the future. See Item 1. "Business - FERC Regulation."
- In a rate case proceeding setting the maximum rates that may be
charged, interstate pipeline systems are generally allowed the
opportunity to collect from their customers a return on their assets or
"rate base" as reflected in their financial records as well as recover
that rate base through depreciation. The amount they may collect from
customers, as a result of a subsequent rate case, decreases as the rate
base declines as a result of depreciation and amortization. In order to
avoid a reduction in the level of cash available for distributions to
its owners an interstate pipeline must maintain or increase its rate
base through projects that maintain or add to existing pipeline
facilities and/or increase its rate of return.
- Our operations are subject to federal and state agencies for
environmental protection and operational safety. We may incur
substantial costs and liabilities in the future as a result of stricter
environmental and safety laws, regulations and enforcement policies. See
Item 1. "Business - Environmental and Safety Matters."
- Due to widespread state budget deficits, several states are
evaluating ways to increase revenue through taxation. Such taxation may
adversely impact us.
- Our ability to operate the pipeline on certain tribal lands will
depend on our success in renegotiating before 2011 our right-of-way
rights on tribal lands within the Fort Peck Reservation. See Item 2.
"Properties." We and the Tribes, through a mediation process, reached a
settlement in principle on the pipeline right-of-way lease and taxation
issues. See Item 3. "Legal Proceedings.". If we are unable to recover
the costs of the proposed settlement in our future rates, it could have
a material adverse impact on our results of operation.
ITEM 7a. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Our interest rate exposure results from variable rate borrowings from
commercial banks. To mitigate potential fluctuations in interest rates, we
attempt to maintain a significant portion of our debt portfolio in fixed rate
debt. We also use interest rate swaps as a means to manage interest expense by
converting a portion of fixed rate debt into variable rate debt to take
advantage of declining interest rates. At December 31, 2003, we had $356.0
million of variable rate debt outstanding, $225.0 million of which was
previously fixed rate debt that had been converted to variable rate debt through
the use of interest rate swaps. For additional information on our debt
obligations and derivative instruments, see Note 5 and Note 6 to our
29
Financial Statements, included elsewhere in this report. As of December 31,
2003, approximately 56% of our debt portfolio was in fixed rate debt.
If average interest rates change by one percent compared to rates in
effect as of December 31, 2003, annual interest expense would change by
approximately $3.6 million. This amount has been determined by considering the
impact of the hypothetical interest rates on variable rate borrowings
outstanding as of December 31, 2003.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required hereunder is included in this report as set
forth in the "Index to Financial Statements" on page F-1.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
ITEM 9(a). CONTROLS AND PROCEDURES
Those officers of Northern Plains that are the equivalent of our
principal executive officer and principal financial officer have evaluated the
effectiveness of our "disclosure controls and procedures" as such term is
defined in Rule 13(a)-15(e) or Rule 15(d)-15(e) of the Securities Exchange Act
of 1934, as amended, within 90 days of the filing of this report. Based upon
their evaluation, they have concluded that our disclosure controls and
procedures are effective. There were no significant changes in our internal
controls or in other factors that could significantly affect these controls,
since the date the controls were evaluated.
30
PART III
ITEM 10. PARTNERSHIP MANAGEMENT
Northern Border Pipeline Company is overseen by the management
committee, which is composed of the following individuals:
William R. Cordes, Chairman(1)
Stanley C. Horton(1)
Max Feldman(2)
Paul E. Miller(1)
- --------------
(1) Designated by Northern Border Partners.
(2) Designated by TC PipeLines.
William R. Cordes (55) has been a member and Chairman of our management
committee since October 1, 2000. Mr. Cordes was named Chief Executive Officer of
Northern Border Partners in October 2000. Since October 2000, Mr. Cordes has
been the President and a director of Northern Plains, an Enron subsidiary and
our operator. In 1970, he started his career at Northern Natural Gas Company, an
Enron subsidiary until February 2002, where he worked in several management
positions. From June of 1993 until September of 2000, he was President of
Northern Natural and from May of 1996 until September of 2000, he was also the
President of Transwestern Pipeline, an Enron subsidiary.
Stanley C. Horton (54) was appointed to our management committee in
December 1998. Mr. Horton is the President and Chief Executive Officer of
CrossCountry Energy, L.L.C. and has held that position since November 21, 2003.
He is Chairman of the Boards of Northern Plains and Pan Border and was appointed
to those positions in October 1993 and December 1998, respectively. He is
Chairman, President and Chief Executive Officer of NBP Services Corporation and
was appointed to those positions in August 1993. He is Chairman, President and
Chief Executive Officer of CrossCountry Energy Services, L.L.C. (formerly CGNN,
Inc.) and has held those positions since November 2001. From August 2001 until
November 2003, he was Chairman and Chief Executive Officer of Enron Global
Services. From January 1997 to August 2001, he was Chairman and Chief Executive
Officer of Enron Transportation Services Company, formerly known as the Enron
Gas Pipeline Group. From February 1996 to January 1997, he was Co-Chairman and
Chief Executive Officer of Enron Operations Corp. From June 1993 to February
1996, he was President and Chief Operating Officer of Enron Operations Corp. He
was a Director and Chairman of the Board of EOTT Energy Corp., the general
partner of EOTT Energy Partners, L.P. until his resignation from the office of
Chairman on April 10, 2002 and then his resignation as Director on May 31, 2002.
EOTT Energy Corp. filed for bankruptcy protection on October 21, 2002. From May
2001 until November 2003, Mr. Horton was a member of the Board of Directors of
Portland General Electric. Mr. Horton also holds or held the elected position of
officer and/or director of the following Enron companies that have filed for
Chapter 11 bankruptcy protection:
Calypso Pipeline, L.L.C. (Director, President and Chief Executive
Officer)
31
Enron Transportation Services Company (Chairman, President and Chief
Executive Officer and Director)
Enron Asset Management Resources, Inc. (Chairman, President and Chief
Executive Officer)
Enron Liquid Services Corp. (Chairman, President and Chief Executive
Officer) Enron Machine and Mechanical Services, Inc. (Chairman,
President and Chief Executive Officer)
Enron Operations Services Corp.(n/k/a Enron Operations, LLC)
(President)
Enron Pipeline Construction Services Company (Chairman, President and
Chief Executive Officer)
Enron Processing Properties, Inc. (Director, Chairman and President)
Enron Trailblazer Pipeline Company (Chairman and
President)
Enron Alligator Alley Pipeline Company (Director and President until
February 14, 2003)
Enron Renewable Energy Corp. (Chairman until November 14, 2002)
Enron Pipeline Services Company (Chairman and Chief Executive Officer
until September 19, 2002)
Enron Wind Corp.(n/k/a Enron Wind LLC) (Chairman and Director until
April 19, 2002)
Enron Wind Development Corp. (N/K/A Enron Development LLC) (Director
and Chairman until April 19, 2002)
Enron Wind Systems, Inc.(n/k/a Enron Wind Systems, LLC) (Director until
April 19, 2002)
Enron Wind Energy Systems Corp.(n/k/a Enron Wind Energy Systems, LLC)
(Chairman, Director until April 19, 2002)
Enron Wind Maintenance Corp.(n/k/a Enron Wind Maintenance, LLC)
(Chairman, Director until April 19, 2002)
Enron Wind Constructors Corp.(n/k/a Enron Wind Constructors, LLC)
(Chairman, Director until April 19, 2002)
Portland General Holdings, Inc. (Chairman and Director until October
31, 2002)
Zond Pacific, LLC (Chairman until September 25, 2002)
In September 2003, TC PipeLines, LP designated Max Feldman (55) as its
member on our Management Committee. Mr. Feldman is Vice-President, Gas
Transmission-West, of TransCanada PipeLines Limited, a position he has held
since April 2003. From 1999 to 2003, he was Senior Vice-President, Customer
Sales and Service, and from 1995 to 1999, Mr. Feldman held several
Vice-President positions in the operations, customer service and marketing areas
of TransCanada PipeLines Limited.
In September 2003, TransCanada designated Paul E. Miller (45) as its
member on the Northern Border Partners, L.P. Policy Committee and designated Mr.
Miller as Northwest Border's representative on our Management Committee.
Additionally, Mr. Miller serves as Director Corporate Development of
TransCanada, a position he has held since February 2003. From July 1998 to
January 2003, Mr. Miller was Director Finance of TransCanada. Prior to July
1998, Mr. Miller was Manager, Finance of TransCanada.
Day-to-day management and operations are the responsibility of the
operator, Northern Plains, as set forth in the operating agreement. We have no
employees or executive officers. Officers and employees of Northern Plains, as
well as employees of its affiliates, provide services to our operations and we
reimburse Northern Plains for such costs. We do not compensate members of the
management committee for their services.
32
There is also an audit and compensation committee composed of members
appointed by the management committee. The audit and compensation committee,
consisting of Mr. Lee Hobbs, Vice President and Controller, TransCanada, and Mr.
Max Feldman, oversees the annual audit process and confers with KPMG LLP, our
independent auditors. The committee is also responsible for setting up
guidelines for compensation to be paid to the executive officers of Northern
Plains, each of whom spends at least a portion of his or her time on our
operations, and for which Northern Plains is reimbursed as indicated above.
Currently, there is one vacancy on the committee. The Management Committee has
determined that Mr. Lee Hobbs is a financial expert. Our financial expert is not
independent and does not need to be independent because we do not have
securities that are listed on a national exchange or national securities
association.
Code of Ethics
The management committee has adopted an Accounting and Financial
Reporting Code of Ethics for those officers of Northern Plains that are the
equivalent principal executive officer and principal finance and accounting
officer. The code of ethics is posted on our website, www.nbpl.nborder.com and
we intend to post on our website any amendments to, or waivers from, our
Accounting and Financial Reporting Code of Ethics within five business days
following such amendment or waiver.
33
ITEM 11. EXECUTIVE COMPENSATION
Jerry L. Peters (46) has served as Treasurer of Northern Plains since
October 1998, Vice President of Finance for Northern Plains since July 1994 and
director of Northern Plains since August 1994. He has been associated with
Northern Plains since 1985.
The following table summarizes information regarding compensation paid
or accrued during each of the last three fiscal years to Jerry L. Peters and
William R. Cordes (the "Named Officers") by Northern Plains, our operator.
Messrs. Cordes and Peters are both employees of Northern Plains, but contribute
services to our operations, for which we reimburse Northern Plains.
SUMMARY COMPENSATION TABLE
Annual Compensation Long-Term Compensation
Securities
Restricted Underlying All Other
Other Annual Stock Awards Options / SARs Compensation
------------ ------------ -------------- LTIP Payouts ------------
Name & Position Year Salary Bonus(1) (2) ($) (3) (4) (#) ($) (5) ($) (6)
- ------------------- ---- ------- -------- ------------ ------------ -------------- ------------ ------------
William R. Cordes 2003 $324,583 $200,000 $ -- $ 99,972 -- $ -- $ 3,000
Chief Executive Officer 2002 $319,333 $240,000 $ -- $ 100,051 -- $ -- $ 1,031
2001 $312,000 $250,000 $ 8,550 $ 227,150 6,475 $300,000 $ 255
Jerry L. Peters 2003 $163,324 $107,500 $ -- $ -- -- $ $ 76,386
Chief Financial and 2002 $159,285 $110,000 $ -- $ -- -- $ $ 23,950
Accounting Officer 2001 $154,292 $125,000 $ 3,399 $ 75,063 7,085 $ -- $ 198
(1) For 2001, employees were able to elect to receive Northern Border phantom
units, Enron Corp. phantom stock, and/or Enron Corp. stock options in
lieu of all or a portion of an annual bonus payment. Mr. Cordes and Mr.
Peters elected to receive Northern Border phantom units in lieu of a
portion of the cash bonus payment under the Northern Border Phantom Unit
Plan. Mr. Cordes received 1,914 units in 2001. Mr. Peters received 842
units in 2001. In each case, units will be released to both five years
following the grant date.
(2) Other Annual Compensation includes cash perquisite allowances, service
awards and vacation payouts. Also, Enron maintained three deferral plans
for key employees under which payment of base salary, annual bonus and
long-term incentive awards could 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 2001 was the minimum rate of 12%. No
interest has been reported as Other Annual Compensation under the 1985
Deferral Plan for participating Named Officers because the crediting
rates during 2001 did not exceed 120% of the long-term Applicable Federal
Rate of 14.38% in effect at the time the 1985 Deferral Plan was
implemented. Beginning January 1, 1996, the 1994 Deferral Plan credits
interest based on fund elections chosen by participants. Since earnings
on deferred compensation invested in third-party investment vehicles,
comparable to mutual funds, need not be reported, no interest has been
reported as Other Annual Compensation under the 1994 Deferral Plan during
2001.
(3) The aggregate total of shares in unreleased Enron restricted stock
holdings and their values as of December 31, 2003, for each of the Named
Officers is: Mr. Cordes, 4,295 shares valued at $120, and Mr. Peters,
1,701 shares valued at $48. Dividend equivalents for all restricted stock
awards accrue from date of grant and are paid upon vesting. Any dividends
on Enron Corp. stock accrued and unreleased as of the date of Enron
Corp.'s filing for bankruptcy protection will only be released in
accordance with applicable bankruptcy law.
(4) Mr. Cordes' employment agreement, as executed in September 2001, provided
for a grant of 882 Northern Border Phantom Units valued as of July 30,
2001 at $115.6978 per unit and granted on October 1, 2001. On June 1,
2002 and 2003, additional grants of 697 and 669 Northern Border Phantom
Units valued at $143.5456 and $149.4346 per unit, respectively, were made
in accordance with his employment agreement. The phantom units vest 100%
on the fifth anniversary of the date of the grant.
(5) Reflects cash payments under the Enron Corp. Performance Unit Plan in
2001 for the 1997-2000 period. Payments made under the Performance Unit
Plan are based on Enron's total
34
shareholder return relative to its peers. Enron's performance over the
1997-2000 performance period rendered a value of $2.00 based on a ranking
of first as compared to 11 industry peers.
(6) The amounts shown include matching contributions to employees' Enron
Corp. Savings Plan,. Mr. Peters' employment agreement, as executed in
April 2002, provided for a "stay" bonus in which $23,950 of the amount
was paid six months following the implementation of the agreement. The
remaining amount of $71,853 was paid in March 2003 upon completion of the
term of the agreement.
STOCK OPTION GRANTS DURING 2003
Due to the bankruptcy filing by Enron Corp on December 2, 2001, there were
no 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 2003.
AGGREGATED STOCK OPTION/SAR EXERCISES DURING 2003 AND STOCK OPTION/SAR VALUES AS
OF DECEMBER 31, 2003
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
Options/SARs at In-the-Money Options/SARs
Shares December 31, 2003 December 31, 2003 (1)
Acquired on Value ----------------- ------------------------
Name Exercise (#) Realized Exercisable Unexercisable Exercisable Unexercisable
---- ------------ -------- ----------- ------------- ----------- -------------
William R. Cordes - $ - 242,755 1,845 $ - $ -
Jerry L. Peters - $ - 66,650 935 $ - $ -
(1) The dollar value in this column for Enron Corp. stock options was
calculated by determining the difference between the fair market value
underlying the options as of December 31, 2003 ( $0.028) and the grant
price.
RETIREMENT AND SUPPLEMENTAL BENEFIT PLANS
Enron maintains the Enron Corp. Cash Balance Plan (the "Cash Balance
Plan"), which is a noncontributory defined benefit pension plan to provide
retirement income for employees of Enron and its subsidiaries. Through December
31, 1994, participants in the Cash Balance Plan with five years or more of
service were entitled to retirement benefits in the form of an annuity based on
a formula that uses a percentage of final average pay and years of service. In
1995, Enron's Board of Directors adopted an amendment to and restatement of the
Cash Balance Plan changing the plan's name from the Enron Corp. Retirement Plan
to the Enron Corp. Cash Balance Plan. In connection with a change to the
retirement benefit formula, all employees became fully vested in retirement
benefits earned through December 31, 1994. The formula in place prior to January
1, 1995 was suspended and replaced with a benefit accrual in the form of a cash
balance of 5% of eligible annual base pay beginning January 1, 1996. Effective
January 1, 2003 Enron suspended future 5% benefit accruals under the Cash
Balance Plan. Each employee's accrued benefit will continue to be credited with
interest based on ten-year Treasury Bond yields.
Enron maintained a noncontributory employee stock ownership plan
("ESOP"), which was merged into the Enron Corp. Savings Plan effective August
30, 2002 and covered all eligible employees. Allocations to individual
employees' retirement accounts within the ESOP offset a portion of benefits
earned under the Cash Balance Plan prior to December 31, 1994.
35
December 31, 1993 was the final date on which ESOP allocations were made to
employees' retirement accounts.
Effective December 2, 2001, Enron no longer maintains a Supplemental
Retirement Plan. The following table sets forth the estimated annual benefits
payable under the Cash Balance Plan at normal retirement at age 65, assuming
only interest credits based on ten-year Treasury Bond yields and no future 5%
benefit accruals after January 1, 2003, to the Named Officers under the
provisions of the foregoing retirement plans.
ESTIMATED
CURRENT CREDITED CURRENT ESTIMATED
CREDITED YEARS OF COMPENSATION ANNUAL BENEFIT
YEARS OF SERVICE COVERED PAYABLE UPON
SERVICE AT AGE 65 BY PLANS RETIREMENT
------- --------- -------- ----------
Mr. Cordes 33.4 43.1 $ 0 $ 74,211
Mr. Peters 18.9 37.8 $ 0 $ 23,212
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.
SEVERANCE PLANS
Northern Plains' Severance Pay Plans provide 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 similar
business circumstances. The amount of benefits payable for performance related
terminations is based on length of service and may not exceed eight weeks' pay.
For those terminated as the result of reorganization or similar business
circumstances, the benefit is based on length of service and amount of pay up to
a maximum payment of 52 weeks of base pay. The employee must sign a Waiver and
Release of Claims Agreement in order to receive any severance benefit.
36
ITEM 12. BENEFICIAL OWNERSHIP OF PARTNERSHIP INTERESTS
The following table sets forth the beneficial ownership of our general
partnership interests. There are no limited partnership interests.
GENERAL
NAME OF BENEFICIAL PARTNERSHIP
OWNER INTEREST
----- --------
Northern Border 70%
Partners, L.P. (1)
TC PipeLines, LP (2) 30%
(1) The address of Northern Border Partners is 13710 FNB Parkway, Omaha, NE
68154-5200. Northern Border Partners holds its 70% general partnership
interest through Northern Border Intermediate Limited Partnership, a
subsidiary limited partnership. Northern Border Partners has three general
partners: Northern Plains, Pan Border and Northwest Border. Northern Plains
and Pan Border are wholly-owned subsidiaries of Enron Corp. and Northwest
Border is a wholly-owned subsidiary of TransCanada.
(2) The address of TC PipeLines is 110 Turnpike Road, Suite 203, Westborough,
Massachusetts 01581. TC PipeLines holds its 30% general partnership interest
through TC PipeLines Intermediate Limited Partnership, a subsidiary limited
partnership. TC PipeLines has one general partner, TC PipeLines GP, Inc., a
wholly-owned subsidiary of TransCanada.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
We have extensive ongoing relationships with our general partners and
certain of their affiliates. Since 1980, Northern Plains, an affiliate of Enron,
has acted and will continue to act as the operator of our pipeline system
pursuant to the terms of the operating agreement with Northern Plains. The
initial term of the operating agreement expires in 2007. The operating agreement
will continue in effect thereafter on a year-to-year basis unless terminated by
us or Northern Plains upon six months written notice by either party. The
operator is entitled to reimbursement for all reasonable costs, including
overhead and administrative expenses, incurred by it and its affiliates in
connection with the performance of its responsibilities as operator. In
addition, we have agreed to indemnify the operator against any claims and
liabilities arising out of the good faith performance by the operator of its
responsibilities under our partnership agreement, to the extent the operator is
acting within the scope of its authority and in the course of our business. For
the year ended December 31, 2003, the aggregate amount charged by Northern
Plains, for its services as operator, was approximately $25.6 million. While
Northern Plains continues to perform its obligations, certain of the services
are provided through Enron and other subsidiaries. We continue to monitor and
assess the impacts of the services and relationships with Enron and its
subsidiaries. We believe that any services affected by the Enron bankruptcy
filings may be obtained from other sources in a manner that will not have a
material adverse impact on the Partnership.
37
See Item 7. "Management's Discussion and Analysis of Financial
Condition and Results of Operations - The Impact of Enron's Chapter 11 Filing On
Our Business."
Our interests could conflict with the interests of our general partners
or their affiliates, and in such case the members of our management committee
will generally have a fiduciary duty to resolve such conflicts in a manner that
is in our best interest.
Unless otherwise provided for in a partnership agreement, the laws of
Texas generally require a general partner of a partnership to adhere to
fiduciary duty standards under which it owes its partners the highest duties of
good faith, fairness and loyalty. These rules apply to our management committee.
Because of the competing interests identified above, the Northern Border
Pipeline Company Partnership Agreement contains provisions that modify certain
of these fiduciary duties. For example:
- Our partnership agreement provides that we indemnify the members of
our management committee and Northern Plains, as the operator,
against all actions if such actions were in good faith and within
the scope of their authority in the course of our business. It also
provides that such persons will not be liable for any liabilities
incurred by us as a result of such acts.
- Our partnership agreement states that our general partners will not
be liable to third persons for our losses, deficits, liabilities or
obligations (unless our assets have been exhausted).
- Our partnership agreement requires that any contract entered into on
our behalf must contain a provision limiting the claims of persons
to our assets and expressly waiving any rights of such persons to
proceed against our general partners individually.
- Our partnership agreement relieves Northern Border Partners and TC
PipeLines, their affiliates and their transferees from any duty to
offer business opportunities to us, except that neither our general
partners or their affiliates may pursue any opportunity relating to
expansion or improvements of our pipeline system as it existed on
January 15, 1999.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The following sets forth fees billed for the audit and other services
provided by KPMG LLP for the fiscal years ended December 31, 2003 and December
31, 2002:
Year Ended December 31,
------------------------
2003 2002
-------- ---------
Audit fees(1) $ 83,000 $ 301,310
Audit-related fees(2) $ 28,810 $ 0
Tax fees(3) $ 0 $ 1,400
Other fees $ 0 $ 0
-------- ---------
Total $111,810 $ 302,710
======== =========
(1) Includes fees for the audit of annual financial statements, reviews of the
related quarterly financial statements and reviews and related consents for
documents filed with the SEC. The fees for 2002 also include professional
38
services for the re-audit of the years 1999, 2000, and 2001.
(2) Includes fees related to professional services consultation for internal
controls review and agreed upon procedures review.
(3) Includes fees related to professional services for tax review and
consultation.
All services of KPMG are pre-approved by our management committee or
through the services approved by the audit committee of Northern Border
Partners.
39
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) (1) AND (2) FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
See "Index to Financial Statements" set forth on page F-1.
(a) (3) EXHIBITS
*3.1 Northern Border Pipeline Company General Partnership Agreement
between Northern Plains Natural Gas Company, Northwest Border
Pipeline Company, Pan Border Gas Company, TransCanada Border
Pipeline Ltd. and TransCan Northern Ltd., effective March 9, 1978,
as amended (Exhibit 10.2 to Northern Border Partners, L.P.'s Form
S-1, SEC File No. 33-66158 ("Form S-1")).
*4.1 Indenture, dated as of August 17, 1999, between the registrant and
Bank One Trust Company, NA, successor to The First National Bank of
Chicago, as trustee (Exhibit 4.1 to Northern Border Pipeline
Company's Form S-4 Registration Statement, Registration No.
333-88577 ("Form S-4")).
*4.2 Indenture, dated as of September 17, 2001, between Northern Border
Pipeline Company and Bank One Trust Company, N.A. (Exhibit 4.2 to
Northern Border Pipeline Company's Registration Statement on Form
S-4, Registration No. 333-73282 ("2001 Form S-4")).
*4.3 Indenture, dated as of April 29, 2002, between Northern Border
Pipeline Company and Bank One Trust Company, N.A. (Exhibit 4.1 to
Northern Border Pipeline Company's Form 10-Q for the quarter ended
March 31, 2002).
*10.1 Operating Agreement between Northern Border Pipeline Company and
Northern Plains Natural Gas Company, dated February 28, 1980
(Exhibit 10.3 to Form S-1).
*10.2 Credit Agreement, dated as of May 16, 2002, among Northern Border
Pipeline Company, Bank One, NA, Citibank, N.A., Bank of Montreal,
SunTrust Bank, Wachovia Bank, National Association, Banc One Capital
Markets, Inc, and Lenders (as defined therein) (Exhibit 10.1 to
Northern Border Partners, L.P.'s Current Report on Form 8-K dated
June 26, 2002).
*10.5 Seventh Supplement Amending Northern Border Pipeline Company General
Partnership Agreement (Exhibit 10.15 to Form S-1).
*10.6 Eighth Supplement Amending Northern Border Pipeline Company General
Partnership Agreement (Exhibit 10.15 of Form S-4).
*10.7 Ninth Supplement Amending Northern Border Pipeline Company General
Partnership Agreement (Exhibit 10.37 to 2001 Form S-4).
*10.8 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).
*10.9 Form of Contribution, Conveyance and Assumption Agreement among TC
PipeLines, LP and certain other parties. (Exhibit
40
10.2 to TC PipeLines, LP's Form S-1, SEC File No. 333-69947 ("TC
Form S-1")).
*10.10 Employment Agreement between Northern Plains Natural Gas Company and
William R. Cordes effective June 1, 2001 (Exhibit 10.27 to Northern
Border Partners, L.P.'s Quarterly Report on Form 10-Q for the
quarter ended June 30, 2001).
*10.11 Amendment to Employment Agreement between Northern Plains Natural
Gas Company and William R. Cordes, effective September 25, 2001
(Exhibit 10.36 to 2001 Form S-4).
10.12 Employment Agreement between Northern Plains Natural Gas Company and
Jerry L. Peters effective April 1, 2002 (Exhibit 10.1 to Northern
Border Pipeline Company's Form 10-Q for the quarter ended March 31,
2002).
*10.13 Northern Border Pipeline Company Agreement among Northern Plains
Natural Gas Company, Pan Border Gas Company, Northwest Border
Pipeline Company, TransCanada Border PipeLine Ltd., TransCan
Northern Ltd., Northern Border Intermediate Limited Partnership,
Northern Border Partners, L.P., and the Management Committee of
Northern Border Pipeline, dated as of March 17, 1999 (Exhibit 10.21
to Northern Border Partners, L.P.'s Form 10-K/A for the year ended
December 31, 1998, SEC File No. 1-12202 ("1998 10-K")).
31.1 Certification of principal executive officer pursuant to rule 13-A
or 15d of the Securities Exchange Act of 1934, as adopted pursuant
to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2 Certification of principal financial officer pursuant to rule 13-A
or 15d of the Securities Exchange Act of 1934, as adopted pursuant
to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1 Certification of principal executive officer pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
32.2 Certification of principal financial officer pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
*99.1 Northern Border Phantom Unit Plan (Exhibit 99.1 to Northern Border
Partners, L.P.'s Registration No. 333-66949 and Exhibit 99.1 to
Northern Border Partners, L.P.'s Registration No. 333-72696).
*Indicates exhibits incorporated by reference as indicated; all other
exhibits are filed herewith.
(B)REPORTS
Northern Border Pipeline filed a Current Report on Form 8-K, dated
October 24, 2003, to disclose its project income for 2003. This
information was furnished under Item 9 of the Form.
Northern Border Pipeline filed a Current Report on Form 8-K, dated
December 19, 2003, discussing the changes to the cash distribution
policy and issuance of equity cash calls.
Northern Border Pipeline filed a Current Report on Form 8-K, dated
December 31, 2003, discussing developments in Enron Corp.'s pending
exemption application under the Public Utility Holding Company Act of
1935.
41
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 12 day of
March, 2004.
NORTHERN BORDER PIPELINE COMPANY
(A Texas General partnership)
BY: Northern Plains Natural Gas Company,
As Operator
By: /s/ Jerry L. Peters
----------------------------
Jerry L. Peters
Vice President, Finance and
Treasurer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons in the capacities and on
the dates indicated.
Signature Title Date
--------- ----- ----
/s/ William R. Cordes President, Northern Plains Natural
- --------------------------- Gas Company March 12, 2004
William R. Cordes (functional equivalent to the
registrant's principal executive
officer) and Management Committee
Member
/s/ Jerry L. Peters Vice President, Finance and
- --------------------------- Treasurer, March 12, 2004
Jerry L. Peters Northern Plains Natural Gas Company
(functional equivalent to the
registrant's principal financial
and accounting officer)
/s/ Stanley C. Horton Management Committee Member March 12, 2004
- ---------------------------
Stanley C. Horton
/s/ Max Feldman Management Committee Member March 12, 2004
- ---------------------------
Max Feldman
/s/ Paul E. Miller Management Committee Member March 12, 2004
- ---------------------------
Paul E. Miller
42
NORTHERN BORDER PIPELINE COMPANY
INDEX TO FINANCIAL STATEMENTS
PAGE NO.
--------
Financial Statements
Independent Auditors' Report F-2
Balance Sheet - December 31, 2003 and 2002 F-3
Statement of Income - Years Ended F-4
December 31, 2003, 2002 and 2001
Statement of Comprehensive Income - Years Ended F-4
December 31, 2003, 2002 and 2001
Statement of Cash Flows - Years Ended F-5
December 31, 2003, 2002 and 2001
Statement of Changes in Partners' Equity - F-6
Years Ended December 31, 2003, 2002 and 2001
Notes to Financial Statements F-7 through
F-18
Financial Statements Schedule
Independent Auditors' Report on Schedule S-1
Schedule II - Valuation and Qualifying Accounts S-2
F-1
INDEPENDENT AUDITORS' REPORT
Northern Border Pipeline Company:
We have audited the accompanying balance sheets of Northern Border Pipeline
Company (a Texas partnership) as of December 31, 2003 and 2002, and the related
statements of income, comprehensive income, cash flows, and changes in partners'
equity for each of the years in the three-year period ended December 31, 2003.
These financial statements are the responsibility of the Company's management.
Our responsibility is to express an opinion on these financial statements based
on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Northern Border Pipeline
Company as of December 31, 2003 and 2002, and the results of its operations and
its cash flows for each of the years in the three-year period ended December 31,
2003, in conformity with accounting principles generally accepted in the United
States of America.
KPMG LLP
Omaha, Nebraska
January 27, 2004
F-2
NORTHERN BORDER PIPELINE COMPANY
BALANCE SHEET
(IN THOUSANDS)
DECEMBER 31,
-------------------------------
2003 2002
---------- ---------- -
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 28,732 $ 25,358
Accounts receivable 33,292 32,774
Related party receivables (net of allowance
for doubtful accounts of $4,815 and $4,805
in 2003 and 2002, respectively) 395 1,552
Materials and supplies, at cost 4,818 4,721
Prepaid expenses and other 2,267 1,844
---------- ----------
Total current assets 69,504 66,249
---------- ----------
NATURAL GAS TRANSMISSION PLANT
In service 2,434,369 2,427,459
Construction work in progress 4,447 4,027
---------- ----------
Total property, plant and equipment 2,438,816 2,431,486
Less: Accumulated provision for
depreciation and amortization 847,061 795,525
---------- ----------
Property, plant and equipment, net 1,591,755 1,635,961
---------- ----------
OTHER ASSETS
Derivative financial instruments 16,648 21,204
Unamortized debt expense 5,206 6,142
Regulatory asset 8,196 10,481
---------- ----------
Total other assets 30,050 37,827
---------- ----------
Total assets $1,691,309 $1,740,037
========== ==========
LIABILITIES AND PARTNERS' EQUITY
CURRENT LIABILITIES
Current maturities of long-term debt $ -- $ 65,000
Accounts payable 7,055 17,103
Related party payables 15,582 7,323
Accrued taxes other than income 28,947 28,374
Accrued interest 10,717 13,173
---------- ----------
Total current liabilities 62,301 130,973
---------- ----------
LONG-TERM DEBT, NET OF CURRENT MATURITIES 821,498 783,906
---------- ----------
RESERVES AND DEFERRED CREDITS 5,072 15,386
---------- ----------
COMMITMENTS AND CONTINGENCIES (Note 7)
PARTNERS' EQUITY
Partners' capital 797,236 803,014
Accumulated other comprehensive income 5,202 6,758
---------- ----------
Total partners' equity 802,438 809,772
---------- ----------
Total liabilities and partners' equity $1,691,309 $1,740,037
========== ==========
The accompanying notes are an integral part of these financial statements.
F-3
NORTHERN BORDER PIPELINE COMPANY
STATEMENT OF INCOME
(IN THOUSANDS)
YEAR ENDED DECEMBER 31,
----------------------------------------------
2003 2002 2001
--------- -------- ---------
OPERATING REVENUES
Operating revenues $324,185 $321,050 $315,145
Provision for rate refunds -- -- (2,057)
-------- -------- --------
Operating revenues, net 324,185 321,050 313,088
-------- -------- --------
OPERATING EXPENSES
Operations and maintenance 43,791 41,442 33,695
Depreciation and amortization 57,779 58,714 57,516
Taxes other than income 29,634 28,436 25,636
-------- -------- --------
Operating expenses 131,204 128,592 116,847
-------- -------- --------
OPERATING INCOME 192,981 192,458 196,241
-------- -------- --------
INTEREST EXPENSE
Interest expense 44,903 51,550 56,262
Interest expense capitalized (46) (25) (911)
-------- -------- --------
Interest expense, net 44,857 51,525 55,351
-------- -------- --------
OTHER INCOME (EXPENSE)
Allowance for equity funds used
during construction 53 26 925
Other income 1,373 2,476 1,417
Other expense (1,350) (716) (2,774)
-------- -------- --------
Other income (expense) 76 1,786 (432)
-------- -------- --------
NET INCOME TO PARTNERS $148,200 $142,719 $140,458
======== ======== ========
NORTHERN BORDER PIPELINE COMPANY
STATEMENT OF COMPREHENSIVE INCOME
(IN THOUSANDS)
YEAR ENDED DECEMBER 31,
----------------------------------------------
2003 2002 2001
--------- --------- ---------
Net income to partners $148,200 $142,719 $140,458
Other comprehensive income:
Transition adjustment from
adoption of SFAS No. 133 -- -- 10,347
Change associated with current
period hedging transactions (1,556) (2,415) (1,174)
-------- -------- --------
Total comprehensive income $146,644 $140,304 $149,631
======== ======== ========
The accompanying notes are an integral part of these financial statements.
F-4
NORTHERN BORDER PIPELINE COMPANY
STATEMENT OF CASH FLOWS
(IN THOUSANDS)
YEAR ENDED DECEMBER 31,
----------------------------------------
2003 2002 2001
---------- ---------- ----------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income to partners $ 148,200 $ 142,719 $ 140,458
--------- --------- ---------
Adjustments to reconcile net income to
partners to net cash provided
by operating activities:
Depreciation and amortization 58,144 59,079 57,881
Provision for regulatory refunds 261 10,000 2,036
Regulatory refunds paid (10,261) -- (6,762)
Allowance for equity funds used
during construction (53) (26) (925)
Reserves and deferred credits 1,001 (237) 736
Changes in components of working capital (3,551) 13,268 4,583
Other (471) (447) (685)
--------- --------- ---------
Total adjustments 45,070 81,637 56,864
--------- --------- ---------
Net cash provided by operating activities 193,270 224,356 197,322
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for property, plant
and equipment, net (12,918) (9,243) (54,659)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Distributions to partners (153,978) (164,126) (143,032)
Issuance of long-term debt, net 142,000 431,894 385,400
Retirement of long-term debt (165,000) (468,000) (374,000)
Decrease in bank overdrafts -- -- (22,437)
Proceeds (payments) upon termination of
derivatives -- 2,351 (4,070)
Long-term debt financing costs -- (2,877) (2,567)
--------- --------- ---------
Net cash used in financing activities (176,978) (200,758) (160,706)
--------- --------- ---------
NET CHANGE IN CASH AND CASH EQUIVALENTS 3,374 14,355 (18,043)
Cash and cash equivalents-beginning of year 25,358 11,003 29,046
--------- --------- ---------
Cash and cash equivalents-end of year $ 28,732 $ 25,358 $ 11,003
========= ========= =========
Changes in components of working capital:
Accounts receivable $ (4,908) $ 5,369 $ 3,432
Materials and supplies (97) 152 (163)
Prepaid expenses and other (422) (113) (1,484)
Accounts payable 3,758 10,006 1,643
Accrued taxes other than income 573 1,207 (970)
Accrued interest (2,455) (3,353) 2,125
--------- --------- ---------
Total $ (3,551) $ 13,268 $ 4,583
========= ========= =========
The accompanying notes are an integral part of these financial statements.
F-5
NORTHERN BORDER PIPELINE COMPANY
STATEMENT OF CHANGES IN PARTNERS' EQUITY
(IN THOUSANDS)
TC NORTHERN
PIPELINES BORDER ACCUMULATED
INTERMEDIATE INTERMEDIATE OTHER TOTAL
LIMITED LIMITED COMPREHENSIVE PARTNERS'
PARTNERSHIP PARTNERSHIP INCOME EQUITY
------------ ------------ ------------- ---------
Partners' Equity at
December 31, 2000 248,098 578,897 -- 826,995
Net income to
partners 42,138 98,320 -- 140,458
Transition adjustment
from adoption of
SFAS No. 133 -- -- 10,347 10,347
Change associated
with current period
hedging transactions -- -- (1,174) (1,174)
Distributions paid (42,910) (100,122) -- (143,032)
----------- ----------- ------------ --------
Partners' Equity at
December 31, 2001 247,326 577,095 9,173 833,594
Net income to
partners 42,816 99,903 -- 142,719
Change associated
with current period
hedging transactions -- -- (2,415) (2,415)
Distributions paid (49,238) (114,888) -- (164,126)
----------- ----------- ------------ --------
Partners' Equity at
December 31, 2002 240,904 562,110 6,758 809,772
Net income to
partners 44,460 103,740 -- 148,200
Change associated
with current period
hedging transactions -- -- (1,556) (1,556)
Distributions paid (46,193) (107,785) -- (153,978)
----------- ----------- ------------ --------
Partners' Equity at
December 31, 2003 $239,171 $ 558,065 $ 5,202 $802,438
=========== =========== ============ ========
The accompanying notes are an integral part of these financial statements.
F-6
NORTHERN BORDER PIPELINE COMPANY
NOTES TO FINANCIAL STATEMENTS
1. ORGANIZATION AND MANAGEMENT
Northern Border Pipeline Company (Northern Border Pipeline) is a Texas
general partnership formed in 1978. The ownership percentages of the
partners in Northern Border Pipeline (Partners) at December 31, 2003
and 2002 are as follows:
Ownership
Partner Percentage
------- ----------
Northern Border Intermediate Limited Partnership 70
TC PipeLines Intermediate Limited Partnership 30
Northern Border Pipeline owns a 1,249-mile natural gas transmission
pipeline system extending from the United States-Canadian border near
Port of Morgan, Montana, to a terminus near North Hayden, Indiana.
Northern Border Pipeline is managed by a Management Committee that
includes three representatives from Northern Border Intermediate
Limited Partnership (Partnership) and one representative from TC
PipeLines Intermediate Limited Partnership (TC PipeLines). The
Partnership's representatives selected by its general partners,
Northern Plains Natural Gas Company (Northern Plains), a wholly-owned
subsidiary of Enron Corp. (Enron), Pan Border Gas Company (Pan Border),
a wholly-owned subsidiary of Northern Plains, and Northwest Border
Pipeline Company, a wholly-owned subsidiary of TransCanada PipeLines
Limited, which is a subsidiary of TransCanada Corporation, and
affiliate of TC PipeLines, have 35%, 22.75% and 12.25%, respectively,
of the voting interest on the Management Committee. The representative
designated by TC PipeLines votes the remaining 30% interest. The
day-to-day management of Northern Border Pipeline's affairs is the
responsibility of Northern Plains, as defined by an operating agreement
between Northern Border Pipeline and Northern Plains. Northern Border
Pipeline is charged for the salaries, benefits and expenses of Northern
Plains. Northern Plains also utilizes Enron affiliates for management
services related to Northern Border Pipeline. For the years ended
December 31, 2003, 2002, and 2001, Northern Border Pipeline's charges
from Northern Plains and its affiliates totaled approximately $25.6
million, $22.8 million and $29.5 million, respectively. See Note 10 for
a discussion of Northern Border Pipeline's relationships with Enron and
developments involving Enron.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(A) Use of Estimates
The preparation of financial statements in conformity with
accounting principles generally accepted in the United States
of America requires management to make estimates and
assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and
liabilities at the date of the financial statements and the
reported amounts of revenues and expenses during the reporting
period. Actual results could differ from those estimates.
(B) Government Regulation
Northern Border Pipeline is subject to regulation by the
Federal Energy Regulatory Commission (FERC). Northern Border
Pipeline's accounting policies conform to Statement of
Financial Accounting Standards (SFAS) No. 71, "Accounting for
the Effects of Certain Types of Regulation."
F-7
NORTHERN BORDER PIPELINE COMPANY
NOTES TO FINANCIAL STATEMENTS
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)
(B) Government Regulation (continued)
Accordingly, certain assets that result from the regulated
ratemaking process are recorded that would not be recorded
under accounting principles generally accepted in the United
States of America for nonregulated entities. Northern Border
Pipeline continually assesses whether the recovery of the
regulatory assets is probable by considering such factors as
regulatory changes and the impact of competition. Northern
Border Pipeline believes the recovery of the existing
regulatory assets is probable. If future recovery ceases to be
probable, Northern Border Pipeline would be required to write
off the regulatory assets at that time. At December 31, 2003
and 2002, Northern Border Pipeline has reflected regulatory
assets of approximately $8.2 million and $10.5 million,
respectively, in other assets on the balance sheet. Northern
Border Pipeline is recovering the regulatory assets from its
shippers over varying time periods, which range from five to
44 years.
(C) Revenue Recognition
Northern Border Pipeline transports gas for shippers under a
tariff regulated by the FERC. The tariff specifies the
calculation of amounts to be paid by shippers and the general
terms and conditions of transportation service on the pipeline
system. Northern Border Pipeline's revenues are derived from
agreements for the receipt and delivery of gas at points along
the pipeline system as specified in each shipper's individual
transportation contract. Revenues for Northern Border Pipeline
are recognized based upon contracted capacity and actual
volumes transported under transportation service agreements.
An allowance for doubtful accounts is recorded in situations
where collectibility is not reasonably assured. Northern
Border Pipeline does not own the gas that it transports, and
therefore it does not assume the related natural gas commodity
risk.
(D) Income Taxes
Income taxes are the responsibility of the Partners and are
not reflected in these financial statements. However, the
Northern Border Pipeline FERC tariff establishes the method of
accounting for and calculating income taxes and requires
Northern Border Pipeline to reflect in its rates the income
taxes, which would have been paid or accrued if Northern
Border Pipeline were organized during the period as a
corporation. As a result, for purposes of determining
transportation rates in calculating the return allowed by the
FERC, Partners' capital and rate base are reduced by the
amount equivalent to the net accumulated deferred income
taxes. Such amounts were approximately $350 million and $343
million at December 31, 2003 and 2002, respectively, and are
primarily related to accelerated depreciation and other
plant-related differences.
(E) Cash and Cash Equivalents
Cash equivalents consist of highly liquid investments with
original maturities of three months or less. The carrying
amount of cash and cash equivalents approximates fair value
because of the short maturity of these investments.
F-8
NORTHERN BORDER PIPELINE COMPANY
NOTES TO FINANCIAL STATEMENTS
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)
(F) Property, Plant and Equipment and Related Depreciation and
Amortization
Property, plant and equipment is stated at original cost.
During periods of construction, Northern Border Pipeline is
permitted to capitalize an allowance for funds used during
construction, which represents the estimated costs of funds
used for construction purposes. 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 retirements or sales of entire regulated operating
units.
Maintenance and repairs are charged to operations in the
period incurred. The provision for depreciation and
amortization of the transmission line is an integral part of
Northern Border Pipeline's FERC tariff. The effective
depreciation rate applied to Northern Border Pipeline's
transmission plant is 2.25%. Composite rates are applied to
all other functional groups of property having similar
economic characteristics.
(G) 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. Northern Border
Pipeline does not use these instruments for trading purposes.
SFAS No. 133, "Accounting for Derivative Instruments and
Hedging Activities," as amended by SFAS No. 137 and SFAS No.
138, requires that every derivative instrument (including
certain derivative instruments embedded in other contracts) be
recorded on the balance sheet as either an asset or liability
measured at its fair value. The statement requires that
changes in the derivative's fair value be recognized currently
in earnings unless specific hedge accounting criteria are met.
Special accounting for qualifying hedges allows a derivative's
gains and losses to offset related results on the hedged item
in the income statement, and requires that a company formally
document, designate and assess the effectiveness of
transactions that receive hedge accounting. Northern Border
Pipeline adopted SFAS No. 133 beginning January 1, 2001. See
Note 6 for a discussion of Northern Border Pipeline's
derivative instruments and hedging activities.
(H) Reclassifications
Certain reclassifications have been made to the financial
statements for prior years to conform with the current year
presentation.
3. RATES AND REGULATORY ISSUES
Northern Border Pipeline filed a rate proceeding with the FERC in May
1999 for, among other things, a redetermination of its allowed equity
rate of return. In September 2000, Northern Border Pipeline filed a
stipulation and agreement with the FERC that documented the proposed
settlement of its 1999 rate case. The settlement was approved by the
FERC in December 2000. Under the settlement, both Northern Border
Pipeline and its existing shippers will not be able to seek rate
changes until November 1, 2005, at which time Northern Border Pipeline
must file a new rate case.
F-9
NORTHERN BORDER PIPELINE COMPANY
NOTES TO FINANCIAL STATEMENTS
3. RATES AND REGULATORY ISSUES (continued)
After the FERC approved the rate case settlement and prior to the end
of 2000, Northern Border Pipeline made estimated refund payments to its
shippers totaling approximately $22.7 million, primarily related to the
period from December 1999 to November 2000. During the first quarter of
2001, Northern Border Pipeline paid the remaining refund obligation to
its shippers totaling approximately $6.8 million, which related to
periods through January 2001.
On March 16, 2000, the FERC issued an order granting Northern Border
Pipeline's application for a certificate to construct and operate an
expansion and extension of its pipeline system into Indiana (Project
2000). The facilities for Project 2000 were placed into service on
October 1, 2001.
In February 2003, Northern Border Pipeline filed to amend its FERC
tariff to clarify the definition of company use gas, which is gas
supplied by its shippers for its operations, by adding detailed
language to the broad categories that comprise company use gas.
Northern Border Pipeline had included in its collection of company use
gas, quantities that were equivalent to the cost of electric power at
its electric-driven compressor stations during the period of June 2001
through January 2003. On March 27, 2003, the FERC issued an order
rejecting Northern Border Pipeline's proposed tariff sheet revision and
requiring refunds with interest within 90 days of the order. Northern
Border Pipeline made refunds to its shippers of $10.3 million in May
2003.
4. TRANSPORTATION SERVICE AGREEMENTS
Operating revenues are collected pursuant to the FERC tariff through
firm transportation service agreements. The firm service agreements
extend for various terms with termination dates that range from March
2004 to December 2013. Northern Border Pipeline also has interruptible
transportation service agreements and other transportation service
agreements with numerous shippers.
Under the capacity release provisions of Northern Border Pipeline's
FERC tariff, shippers are allowed to release all or part of their
capacity either permanently for the full term of the contract or
temporarily. A temporary capacity release does not relieve the original
contract shipper from its payment obligations if the replacement
shipper fails to pay for the capacity temporarily released to it.
For the year ended December 31, 2003, Northern Border Pipeline's
largest shippers were BP Canada Energy Marketing Corp. (BP Canada),
Pan-Alberta Gas (U.S.) Inc. (Pan-Alberta) and EnCana Marketing U.S.A.
Inc. (EnCana). At December 31, 2003, BP Canada had approximately 21% of
the contracted firm capacity and EnCana had approximately 19% of the
contracted firm capacity. Pan-Alberta's firm service agreements, which
had been managed by Mirant Americas Energy Marketing, LP, terminated
October 31, 2003. The BP Canada firm service agreements extend for
various terms with termination dates from October 2004 to February
2012. The EnCana firm service agreements extend for various terms with
termination dates from March 2004 to June 2009. Operating revenues from
BP Canada, EnCana, and Pan-Alberta for the year ended December 31,
2003, were $54.7 million, $32.9 million, and $45.5 million,
respectively. For the years ended December 31, 2002 and 2001, Northern
Border Pipeline's largest shippers were Pan-Alberta and Mirant with
combined operating revenues of $105.5 million and $80.7 million,
respectively.
F-10
NORTHERN BORDER PIPELINE COMPANY
NOTES TO FINANCIAL STATEMENTS
4. TRANSPORTATION SERVICE AGREEMENTS (continued)
At December 31, 2003, there is no contracted firm capacity held by
shippers affiliated with Northern Border Pipeline. Previously, some of
Northern Border Pipeline's shippers have been affiliated with its
general partners. Operating revenues from affiliates were $1.4 million
and $52.1 million for the years ended December 31, 2002, and 2001,
respectively.
5. CREDIT FACILITIES AND LONG-TERM DEBT
Detailed information on long-term debt is as follows:
December 31,
(Thousands of dollars) 2003 2002
- ----------------------------------------------------------------------------------------------
1992 Pipeline Senior Notes - average 8.57%
at December 31, 2002, paid in 2003 $ -- $ 65,000
2002 Pipeline Credit Agreement - average 1.95%
and 2.05% at December 31, 2003 and 2002,
respectively, due 2005 131,000 89,000
1999 Pipeline Senior Notes - 7.75%, due 2009 200,000 200,000
2001 Pipeline Senior Notes - 7.50%, due 2021 250,000 250,000
2002 Pipeline Senior Notes - 6.25%, due 2007 225,000 225,000
Fair value adjustment for interest rate
swaps (Note 6) 16,648 21,204
Unamortized debt discount (1,150) (1,298)
-------- --------
Total 821,498 848,906
Less: Current maturities of long-term debt - 65,000
-------- --------
Long-term debt $821,498 $783,906
======== ========
Northern Border Pipeline has entered into revolving credit facilities,
which are used for capital expenditures, acquisitions and general
business purposes and for refinancing existing indebtedness. Northern
Border Pipeline entered into a $175 million three-year credit agreement
(2002 Pipeline Credit Agreement) with certain financial institutions in
May 2002. The 2002 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. Northern Border
Pipeline is required to pay a fee on the principal commitment amount of
$175 million.
In April 2002, Northern Border Pipeline completed a private offering of
$225 million of 6.25% Senior Notes due 2007 (2002 Pipeline Senior
Notes) and in September 2001, Northern Border Pipeline completed a
private offering of $250 million of 7.50% Senior Notes due 2021 (2001
Pipeline Senior Notes). The 2002 Pipeline Senior Notes and 2001
Pipeline Senior Notes were subsequently exchanged in registered
offerings for notes with substantially identical terms. The proceeds
from the senior notes were used to reduce indebtedness outstanding.
F-11
NORTHERN BORDER PIPELINE COMPANY
NOTES TO FINANCIAL STATEMENTS
5. CREDIT FACILITIES AND LONG-TERM DEBT (continued)
Interest paid, net of amounts capitalized, during the years ended
December 31, 2003, 2002 and 2001 was $47.8 million, $55.3 million and
$53.9 million, respectively.
Aggregate required repayments of long-term debt are as follows: $131
million and $225 million for 2005 and 2007, respectively. Aggregate
required repayments of long-term debt thereafter total $450 million.
There are no required repayment obligations for 2004, 2006 or 2008.
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, leverage ratios
and interest coverage ratios that restrict the incurrence of other
indebtedness by Northern Border Pipeline and also place certain
restrictions on distributions to the partners of Northern Border
Pipeline. The 2002 Pipeline Credit Agreement requires the maintenance
of a ratio of EBITDA (net income plus interest expense, income taxes
and depreciation and amortization) to interest expense of greater than
3 to 1. The 2002 Pipeline Credit Agreement also requires the
maintenance of the ratio of indebtedness to EBITDA of no more than 4.5
to 1. At December 31, 2003, Northern Border Pipeline was in compliance
with its financial covenants.
The following estimated fair values of financial instruments represent
the amount at which each instrument could be exchanged in a current
transaction between willing parties. Based on quoted market prices for
similar issues with similar terms and remaining maturities, the
estimated fair value of the 1992 Pipeline Senior Notes, 1999 Pipeline
Senior Notes, 2001 Pipeline Senior Notes and 2002 Pipeline Senior Notes
was approximately $675 million and $827 million at December 31, 2003
and 2002, respectively. Northern Border Pipeline presently intends to
maintain the current schedule of maturities for the 1999 Pipeline
Senior Notes, the 2001 Pipeline Senior Notes and the 2002 Pipeline
Senior Notes, which will result in no gains or losses on their
respective repayments. The fair value of Northern Border Pipeline's
variable rate debt approximates the carrying value since the interest
rates are periodically adjusted to reflect current market conditions.
6. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
As a result of the adoption of SFAS No. 133 on January 1, 2001,
Northern Border Pipeline reclassified approximately $11.1 million from
long-term debt to accumulated other comprehensive income related to
unamortized proceeds from the termination of interest rate swap
agreements. Also upon adoption of SFAS No. 133, Northern Border
Pipeline designated an outstanding interest rate swap agreement with a
notional amount of $40 million as a cash flow hedge. As a result,
Northern Border Pipeline recorded a non-cash loss in accumulated other
comprehensive income of approximately $0.8 million. The $40 million
interest rate swap agreement terminated in November 2001.
Prior to the anticipated issuance of fixed rate debt, Northern Border
Pipeline entered into forward starting interest rate swap agreements.
The interest rate swaps were designated as cash flow hedges as they were
entered into to hedge the fluctuations in Treasury rates and spreads
between the execution date of the swaps and the issuance of the fixed
rate debt. The notional amount of the interest rate swaps did not exceed
the expected principal amount of fixed rate debt to be issued. Upon
issuance of the fixed rate debt, the swaps were terminated and the
proceeds received or
F-12
NORTHERN BORDER PIPELINE COMPANY
NOTES TO FINANCIAL STATEMENTS
6. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (continued)
amounts paid to terminate the swaps were recorded in accumulated other
comprehensive income and amortized to interest expense over the term of
the debt.
For the year ended December 31, 2002, Northern Border Pipeline received
$2.4 million from terminated interest rate swaps. For the year ended
December 31, 2001, Northern Border Pipeline paid approximately $4.1
million to terminate interest rate swaps.
During the years ended December 31, 2003, 2002, and 2001 respectively,
Northern Border Pipeline amortized approximately $1.6 million, $1.4
million, and $1.2 million related to the terminated derivatives as a
reduction to interest expense from accumulated other comprehensive
income. Northern Border Pipeline expects to amortize approximately $1.6
million as a reduction to interest expense in 2004.
Northern Border Pipeline entered into interest rate swap agreements
with notional amounts totaling $225 million in May 2002. Under the
interest rate swap agreements, Northern Border Pipeline makes payments
to counterparties at variable rates based on the London Interbank
Offered Rate and in return receives payments based on a 6.25% fixed
rate. At December 31, 2003 and 2002, the average effective interest
rate on Northern Border Pipeline's interest rate swap agreements was
2.31% and 2.70%, respectively. Northern Border Pipeline's interest rate
swap agreements have been designated as fair value hedges as they were
entered into to hedge the fluctuations in the market value of the 2002
Pipeline Senior Notes. The accompanying balance sheet at December 31,
2002, reflects a non-cash gain of approximately $21.2 million in
derivative financial assets with a corresponding increase in long-term
debt. The accompanying balance sheet at December 31, 2003, reflects a
non-cash gain of approximately $16.6 million in derivative financial
assets with a corresponding increase in long-term debt.
7. COMMITMENTS AND CONTINGENCIES
Operating Leases
Future minimum lease payments under non-cancelable operating leases on
office space and rights-of-way are as follows (in thousands):
Year ending December 31,
2004 $ 5,757
2005 2,392
2006 2,392
2007 2,392
2008 2,392
Thereafter 3,929
---------
$ 19,254
=========
F-13
NORTHERN BORDER PIPELINE COMPANY
NOTES TO FINANCIAL STATEMENTS
7. COMMITMENTS AND CONTINGENCIES (continued)
Cash Balance Plan
As further discussed in Note 11, on December 31, 2003, Enron filed a
motion seeking approval of the Bankruptcy Court to provide additional
funding to, and for authority to terminate the Enron Corp. Cash Balance
Plan and certain other defined benefit plans. Northern Border Pipeline
recorded charges associated with the termination of the cash balance
plan of $3.1 million in 2003. Northern Border Pipeline believes this
accrual is adequate to cover the likely allocation of these costs.
Capital expenditures
Total capital expenditures for 2004 are estimated to be $14 million.
Funds required to meet the capital expenditures for 2004 are
anticipated to be provided primarily by borrowings under the 2002
Pipeline Credit Agreement and using operating cash flows.
Environmental Matters
Northern Border Pipeline is not aware of any material contingent
liabilities with respect to compliance with applicable environmental
laws and regulations.
Other
On July 31, 2001, the Assiniboine and Sioux Tribes of the Fort Peck
Indian Reservation (Tribes) filed a lawsuit in Tribal Court against
Northern Border Pipeline to collect more than $3 million in back taxes,
together with interest and penalties. The lawsuit relates to a
utilities tax on certain of Northern Border Pipeline's properties
within the Fort Peck Indian Reservation. The Tribes and Northern Border
Pipeline, through a mediation process, have held settlement discussions
and have reached a settlement in principle on pipeline rights-of-way
lease and taxation issues. Final documentation has been completed and
is subject to the approval of the Bureau of Indian Affairs, which the
parties believe will be obtained in the very near term. This settlement
grants to Northern Border Pipeline, among other things, (i) an option
to renew the pipeline rights-of-way lease upon agreed terms and
conditions on or before April 11, 2011 for a term of 25 years with a
renewal right for an additional 25 years; (ii) a present right to use
additional tribal lands for expanded facilities; and (iii) release and
satisfaction of all tribal taxes against Northern Border Pipeline. In
consideration of this option and other benefits, Northern Border
Pipeline will pay a lump sum amount of $5.9 million and an annual
amount of approximately $1.5 million beginning April 2004. Northern
Border Pipeline intends to seek regulatory recovery of the costs
resulting from the settlement.
Various legal actions that have arisen in the ordinary course of
business are pending. Northern Border Pipeline believes that the
resolution of these issues will not have a material adverse impact on
Northern Border Pipeline's results of operations or financial position.
F-14
NORTHERN BORDER PIPELINE COMPANY
NOTES TO FINANCIAL STATEMENTS
8. QUARTERLY FINANCIAL DATA (Unaudited)
Operating Operating Net Income
(In thousands) Revenues, net Income to Partners
- -------------- ------------- --------- -----------
2003
First Quarter $ 79,892 $ 48,639 $ 36,734
Second Quarter 80,659 48,915 37,617
Third Quarter 81,192 48,050 37,195
Fourth Quarter 82,442 47,377 36,654
2002
First Quarter $ 78,155 $ 49,895 $ 37,670
Second Quarter 80,173 52,014 38,506
Third Quarter 81,553 51,843 39,197
Fourth Quarter 81,169 38,706 27,346
9. ACCOUNTING PRONOUNCEMENTS
In 2001, the Financial Accounting Standards Board ("FASB") issued
SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No.
143 requires entities to record the fair value of a liability for an
asset retirement obligation in the period in which it is incurred, if
the liability can be reasonably estimated. When the liability is
initially recorded, the carrying amount of the related asset is
increased by the same amount. Over time, the liability is accreted to
its future value and the accretion is recorded to expense. The initial
adjustment to the asset is depreciated over its useful life. Upon
settlement of the liability, an entity either settles the obligation
for its recorded amount or incurs a gain or loss. In some instances,
Northern Border Pipeline is obligated by contractual terms or
regulatory requirements to remove facilities or perform other
remediation upon retirement. Northern Border Pipeline was unable to
estimate and record liabilities for its obligations that fall under the
provisions of this statement because it cannot reasonably estimate when
such obligations would be settled. Effective January 1, 2003, Northern
Border Pipeline adopted SFAS No. 143, which did not have a material
impact on its financial position or results of operations.
In November 2002, the FASB issued Interpretation No. (FIN) 45,
"Guarantor's Accounting and Disclosure Requirements for Guarantees,
Including Indirect Guarantees of Indebtedness of Others". This
interpretation elaborates on the disclosures to be made by a guarantor
in its interim and annual financial statements about its obligations
under certain guarantees that it has issued. It also clarifies that a
guarantor is required to recognize, at the inception of a guarantee, a
liability for the fair value of the obligation undertaken in issuing
the guarantee. The initial recognition and initial measurement
provisions of this interpretation are applicable on a prospective basis
to guarantees issued or modified after December 31, 2002. FIN 45 did
not have a material impact on Northern Border Pipeline's financial
position or results of operations.
In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement
No. 133 on Derivative Instruments and Hedging Activities." SFAS No. 149
amends and clarifies accounting for derivative instruments, including
certain derivative instruments embedded in other contracts, and for
hedging activities under SFAS No. 133. SFAS No. 149 did not have a
material impact on Northern Border Pipeline's financial position or
results of operations.
F-15
NORTHERN BORDER PIPELINE COMPANY
NOTES TO FINANCIAL STATEMENTS
9. ACCOUNTING PRONOUNCEMENTS (continued)
In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and
Equity." This statement establishes standards for how an issuer
classifies and measures certain financial instruments with
characteristics of both liabilities and equity. SFAS No. 150 is
effective for financial instruments entered into or modified after May
31, 2003. SFAS No. 150 did not have a material impact on Northern
Border Pipeline's financial position or results of operations.
In May 2003, the Emerging Issues Task Force of the FASB issued EITF No.
00-21, "Revenue Arrangements with Multiple Deliverables." EITF 00-21
requires companies to separate components of a complex contract into
separate units of accounting. EITF 00-21 was effective for contracts
signed after June 30, 2003, although retroactive application to
existing contracts was permitted. EITF 00-21 did not have a material
impact on Northern Border Pipeline's financial position or results of
operations.
10. OTHER INCOME (EXPENSE)
Other income (expense) on the statement of income includes such items
as investment income, nonoperating revenues and expenses, and
nonrecurring other income and expense items. For the year ended
December 31, 2003, other expense included $0.6 million for a repayment
of amounts previously received for vacated microwave frequency bands.
For the year ended December 31, 2002, other income included $0.6
million for amounts received for previously vacated microwave frequency
bands. For the year ended December 31, 2001, other income included bad
debt expense of $1.5 million related to the bankruptcy of a
telecommunications company that had purchased excess capacity on
Northern Border Pipeline's communication system and a $0.7 million
charge for reserves established.
11. RELATIONSHIPS WITH ENRON
In December 2001, Enron and certain of its subsidiaries filed voluntary
petitions for Chapter 11 reorganization with the U.S. Bankruptcy Court.
Northern Plains was not included in the bankruptcy filing and
management believes that Northern Plains will continue to be able to
meet its operational and administrative service obligations under the
existing operating agreement. Enron North America Corp. (ENA), a
subsidiary of Enron, was included in the bankruptcy filing.
At the time of the bankruptcy filing, ENA had firm service agreements
representing approximately 3.5% of contracted capacity, a portion of
which (1.1%) had been temporarily released to a third party until
October 31, 2002. Northern Border Pipeline recorded a bad debt expense
of approximately $1.3 million representing ENA's unpaid November and
December 2001 transportation, which is included in operations and
maintenance expense on the statement of income.
F-16
NORTHERN BORDER PIPELINE COMPANY
NOTES TO FINANCIAL STATEMENTS
11. RELATIONSHIPS WITH ENRON(continued)
On June 13, 2002, the Bankruptcy Court approved a Stipulation and Order
entered into on May 15, 2002, by ENA and Northern Border Pipeline
pursuant to which ENA agreed that all but one of the shipper contracts,
representing 1.7% of pipeline capacity, would be deemed rejected and
terminated. The remaining contract was terminated in the third quarter
of 2002. For the year ended December 31, 2002, Northern Border Pipeline
has experienced lost revenues of approximately $1.8 million related to
ENA's capacity. Northern Border Pipeline has filed proofs of claims
regarding the amount of damages for breach of contract and other claims
in the bankruptcy proceeding. However, Northern Border Pipeline cannot
predict the amounts, if any, that it will collect or the timing of
collection. Northern Border Pipeline believes, however, that any
amounts collected will not be material.
On December 31, 2003, Enron filed a motion seeking approval of the
Bankruptcy Court to provide additional funding to, and for authority to
terminate the Enron Corp. Cash Balance Plan (Plan) and certain other
defined benefit plans of Enron's affiliates in 'standard terminations'
within the meaning of Section 4041 of the Employee Retirement Income
Security Act of 1974, as amended (ERISA). Such standard terminations
would satisfy all of the obligations of Enron and its affiliates with
respect to funding liabilities under the Plan. In addition, a standard
termination would eliminate the contingent claims of Pension Benefit
Guaranty Corporation (PBGC) against Enron and its affiliates with
respect to funding liabilities under the Plan. On January 30, 2004, the
Bankruptcy Court entered an order authorizing termination, additional
funding and other actions necessary to effect the relief requested.
Pursuant to the Bankruptcy Court order, any contributions to the Plan
are subject to the prior receipt of a favorable determination by the
Internal Revenue Service that the Plan is tax-qualified as of the date
of termination. In addition, the Bankruptcy Court order provides that
the rights of PBGC and others to assert that their filed claims have
not been released or adjudicated as a result of the Bankruptcy Court
order and Enron and all other interested parties retained the right to
assert that such claims had been adjudicated or released.
Enron management has informed Northern Plains that it will seek funding
contributions from each member of its ERISA controlled group of
corporations that employs, or employed, individuals who are, or were,
covered under the Plan. Northern Plains has advised us that it is a
member of a controlled group of corporations of Enron that employs, or
employed, individuals who are, or were, covered under the Plan and that
an amount of approximately $3.1 million has been assessed for our
proportionate allocation of Northern Plains' proportionate share of the
up to $200 million estimated termination costs authorized by the
Bankruptcy Court order. Under the operating agreement with Northern
Plains, these increased costs may be Northern Border Pipeline's
responsibility. While the final amounts have not been determined,
Northern Border Pipeline believes this accrual is adequate to cover the
allocation of these costs.
Northern Border Pipeline continues to monitor developments at Enron, to
assess the impact on Northern Border Pipeline of its existing
agreements and relationships with Enron, and to take appropriate action
to protect Northern Border Pipeline's interests.
F-17
NORTHERN BORDER PIPELINE COMPANY
NOTES TO FINANCIAL STATEMENTS
12. SUBSEQUENT EVENTS
In December 2003, Northern Border Pipeline's management committee
voted to (i) issue equity cash calls to its partners in the total
amount of $130 million in early 2004 and $90 million in 2007; (ii) fund
future growth capital expenditures with 50% equity capital
contributions from its partners; and (iii) change the cash distribution
policy of Northern Border Pipeline. Effective January 1, 2004,
at that time cash distributions will be equal to 100% of distributable
cash flow as determined from Northern Border Pipeline's financial
statements based upon earnings before interest, taxes, depreciation
and amortization less interest expense and less maintenance capital
expenditures. Effective until January 1, 2008 the cash distribution
policy will be adjusted to maintain a consistent capital structure.
Under the previous cash distribution policy, approximately
$28-$30 million was retained annually within Northern Border
Pipeline to periodically repay outstanding bank debt.
The additional equity contributions in 2004 will
be utilized to fully repay Northern Border Pipeline's existing bank
debt and thereby reduce its debt leverage in light of existing business
conditions. Upon repayment of the existing bank debt, Northern Border
Pipeline's next scheduled debt maturity is May 2007.
Northern Border Pipeline makes distributions to it general partners
approximately one month following the end of the quarter. The
distribution for the fourth quarter of 2003 of approximately $48.1
million was declared in January 2004 to be paid in January 2004.
In January 2004, the Partnership and TC PipeLines contributed $45.5
million and $19.5 million, respectively, to Northern Border Pipeline to
be used by Northern Border Pipeline to repay a portion of its existing
indebtedness under the 2002 Pipeline Credit Agreement.
F-18
INDEPENDENT AUDITORS' REPORT ON SCHEDULE
Northern Border Pipeline Company:
We have audited in accordance with auditing standards generally accepted in the
United States of America, the financial statements of Northern Border Pipeline
Company as of December 31, 2003 and 2002 and for each of the years in the
three-year period ended December 31, 2003 included in this Form 10-K, and have
issued our report thereon dated January 27, 2004.
Our audits were made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The schedule of Northern Border Pipeline
Company listed in Item 14 of Part IV of this Form 10-K is the responsibility of
the Company's management and is presented for purposes of complying with the
Securities and Exchange Commission's rules and is not part of the basic
financial statements. This schedule has been subjected to the auditing
procedures applied in the audits of the basic financial statements and, in our
opinion, fairly states in all material respects, the financial data required to
be set forth therein in relation to the basic financial statements taken as a
whole.
KPMG LLP
Omaha, Nebraska
January 27, 2004
S-1
SCHEDULE II
NORTHERN BORDER PIPELINE COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001
(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
2003 $ 12,294 $ 4,282 $ -- $ 10,261 $ 6,315
2002 $ 2,531 $ 9,763 $ -- $ -- $ 12,294
2001 $ 1,800 $ 731 $ -- $ -- $ 2,531
Allowance for
doubtful accounts
2003 $ 4,805 $ 10 $ -- $ -- $ 4,815
2002 $ 3,176 $ 3,452 $ -- $ 1,823 $ 4,805
2001 $ -- $ 3,176 $ -- $ -- $ 3,176
S-2
EXHIBIT INDEX
*3.1 Northern Border Pipeline Company General Partnership Agreement
between Northern Plains Natural Gas Company, Northwest Border
Pipeline Company, Pan Border Gas Company, TransCanada Border
Pipeline Ltd. and TransCan Northern Ltd., effective March 9, 1978,
as amended (Exhibit 10.2 to Northern Border Partners, L.P.'s Form
S-1, SEC File No. 33-66158 ("Form S-1")).
*4.1 Indenture, dated as of August 17, 1999, between the registrant and
Bank One Trust Company, NA, successor to The First National Bank of
Chicago, as trustee (Exhibit 4.1 to Northern Border Pipeline
Company's Form S-4 Registration Statement, Registration No.
333-88577 ("Form S-4")).
*4.2 Indenture, dated as of September 17, 2001, between Northern Border
Pipeline Company and Bank One Trust Company, N.A. (Exhibit 4.2 to
Northern Border Pipeline Company's Registration Statement on Form
S-4, Registration No. 333-73282 ("2001 Form S-4")).
*4.3 Indenture, dated as of April 29, 2002, between Northern Border
Pipeline Company and Bank One Trust Company, N.A. (Exhibit 4.1 to
Northern Border Pipeline Company's Form 10-Q for the quarter ended
March 31, 2002).
*10.1 Operating Agreement between Northern Border Pipeline Company and
Northern Plains Natural Gas Company, dated February 28, 1980
(Exhibit 10.3 to Form S-1).
*10.2 Credit Agreement, dated as of May 16, 2002, among Northern Border
Pipeline Company, Bank One, NA, Citibank, N.A., Bank of Montreal,
SunTrust Bank, Wachovia Bank, National Association, Banc One Capital
Markets, Inc, and Lenders (as defined therein) (Exhibit 10.1 to
Northern Border Partners, L.P.'s Current Report on Form 8-K dated
June 26, 2002).
*10.5 Seventh Supplement Amending Northern Border Pipeline Company General
Partnership Agreement (Exhibit 10.15 to Form S-1).
*10.6 Eighth Supplement Amending Northern Border Pipeline Company General
Partnership Agreement (Exhibit 10.15 of Form S-4).
*10.7 Ninth Supplement Amending Northern Border Pipeline Company General
Partnership Agreement (Exhibit 10.37 to 2001 Form S-4).
*10.8 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).
*10.9 Form of Contribution, Conveyance and Assumption Agreement among TC
PipeLines, LP and certain other parties. (Exhibit
10.2 to TC PipeLines, LP's Form S-1, SEC File No. 333-69947 ("TC
Form S-1")).
*10.10 Employment Agreement between Northern Plains Natural Gas Company and
William R. Cordes effective June 1, 2001 (Exhibit 10.27 to Northern
Border Partners, L.P.'s Quarterly Report on Form 10-Q for the
quarter ended June 30, 2001).
*10.11 Amendment to Employment Agreement between Northern Plains Natural
Gas Company and William R. Cordes, effective September 25, 2001
(Exhibit 10.36 to 2001 Form S-4).
*10.12 Employment Agreement between Northern Plains Natural Gas Company and
Jerry L. Peters effective April 1, 2002 (Exhibit 10.1 to Northern
Border Pipeline Company's Form 10-Q for the quarter ended March 31,
2002).
*10.13 Northern Border Pipeline Company Agreement among Northern Plains
Natural Gas Company, Pan Border Gas Company, Northwest Border
Pipeline Company, TransCanada Border PipeLine Ltd., TransCan
Northern Ltd., Northern Border Intermediate Limited Partnership,
Northern Border Partners, L.P., and the Management Committee of
Northern Border Pipeline, dated as of March 17, 1999 (Exhibit 10.21
to Northern Border Partners, L.P.'s Form 10-K/A for the year ended
December 31, 1998, SEC File No. 1-12202 ("1998 10-K")).
*16.1 Letter of Arthur Andersen LLP, former auditors of Northern Border
Pipeline Company, dated February 11, 2002 (Exhibit 99.3 to Northern
Border Pipeline Company's Form 8-K filed on February 13, 2002).
31.1 Certification of principal executive officer pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
31.2 Certification of principal financial officer pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
32.1 Certification of principal executive officer pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
32.2 Certification of principal financial officer pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
*99.1 Northern Border Phantom Unit Plan (Exhibit 99.1 to Northern Border
Partners, L.P.'s Registration No. 333-66949 and Exhibit 99.1 to
Northern Border Partners, L.P.'s Registration No. 333-72696).