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UNITED STATES SECURITIES AND EXCHANGE
COMMISSION
WASHINGTON, D.C. 20549
-----------------------
FORM 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: 1-12202
NORTHERN BORDER PARTNERS, L.P.
(Exact name of registrant as specified in its charter)
DELAWARE 93-1120873
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)
13710 FNB PARKWAY, OMAHA, NEBRASKA 68154-5200
(Address of principal executive offices)(zip code)
Registrant's telephone number, including area code: 402-492-7300
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SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Title of each class Name of each exchange on which registered
- ------------------- -----------------------------------------
Common Units New York Stock Exchange
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to 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 [X]
No [ ]
Aggregate market value of the Common Units held by non-affiliates of
the registrant, based on closing prices in the daily composite list for
transactions on the New York Stock Exchange on June 30, 2003, was approximately
$1,802,117,583.
NORTHERN BORDER PARTNERS, L.P.
TABLE OF CONTENTS
PAGE NO.
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PART I
Item 1. Business 1
Item 2. Properties 20
Item 3. Legal Proceedings 21
Item 4. Submission of Matters to a Vote of Security Holders 22
PART II
Item 5. Market for Registrant's Common Units and Related
Security Holder Matters 23
Item 6. Selected Financial Data 26
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations 28
Item 7a. Quantitative and Qualitative Disclosures About Market
Risk 56
Item 8. Financial Statements and Supplementary Data 57
Item 9. Changes in and Disagreements With Accountants on
Accounting and Financial Disclosure 58
Item 9a. Controls and Procedures 58
PART III
Item 10. Partnership Management 59
Item 11. Executive Compensation 66
Item 12. Security Ownership of Certain Beneficial Owners
and Management 69
Item 13. Certain Relationships and Related Transactions 69
Item 14. Principal Accounting Fees and Services 72
PART IV
Item 15. Exhibits, Financial Statement Schedules and
Reports on Form 8-K 73
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PART I
ITEM 1. BUSINESS
GENERAL
We are a publicly-traded limited partnership formed in 1993 and a
leading transporter of natural gas imported from Canada to the United States.
Our business operations are comprised of the following segments:
- Interstate Natural Gas Pipelines
- Natural Gas Gathering and Processing
- Coal Slurry Pipeline
Our interstate natural gas pipelines segment includes companies that
provide natural gas transmission services in the midwestern United States. The
companies in this segment transport gas for shippers under tariffs regulated by
the Federal Energy Regulatory Commission ("FERC"). The interstate pipelines'
revenues are derived from agreements for the receipt and delivery of gas at
points along the pipeline systems as specified in each shipper's individual
transportation contract. In mid January 2003, we expanded this segment with our
acquisition of Viking Gas Transmission Company, including a one-third interest
in Guardian Pipeline, L.L.C.
Our gas gathering and processing segment provides services for the
gathering, treating, processing and compression of natural gas and the
fractionation of natural gas liquids ("NGLs") for third parties and related
field services. We do not explore for, or produce, crude oil or natural gas, and
do not own crude oil or natural gas reserves. We have extensive gas gathering
operations in the Powder River Basin in Wyoming. We also have natural gas
gathering, processing and fractionation operations in the Williston Basin in
Montana and North Dakota. In June 2003, we sold our processing plants and
related facilities in Alberta, Canada but we still hold an interest in gathering
pipelines in the region.
Our coal slurry pipeline segment is comprised of our ownership of Black
Mesa Pipeline, Inc. The 273-mile pipeline is the only coal slurry pipeline in
operation in the United States.
We are managed under the direction of a partnership policy committee
(similar to a board of directors). The partnership policy committee consists of
three members, each of whom has been appointed by one of our general partners.
Our general partners and the general partners of our subsidiary limited
partnership, Northern Border Intermediate Limited Partnership, are Northern
Plains Natural Gas Company ("Northern Plains") and Pan Border Gas Company, both
subsidiaries of Enron Corp. ("Enron"), and Northwest Border Pipeline Company, a
subsidiary of TransCanada PipeLines Limited which is a subsidiary of TransCanada
Corporation, collectively referred to as "TransCanada". In this report,
references to "we", "us", "our" or the "Partnership" collectively refer to
Northern Border Partners and our subsidiary, Northern Border Intermediate
Limited Partnership. See Item 10. "Partnership Management."
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Our general partners hold an aggregate 2% general partner interest in
the Partnership. Northern Plains also owns common units representing a 1.06%
limited partner interest and Sundance Assets, L.P., an affiliate of Enron, holds
a 5.72% limited partner interest. See Item 12. "Security Ownership of Certain
Beneficial Owners and Management." The combined general and limited partner
interests in the Partnership held by Enron and TransCanada are 8.43% and 0.35%,
respectively.
NBP Services Corporation, an Enron subsidiary, provides administrative
services for us and operating services for our natural gas gathering and
processing segment. NBP Services has approximately 135 employees and also
utilizes employees and information technology systems of its affiliates to
provide these services. Northern Plains provides operating services to our
interstate pipelines pursuant to operating agreements and to the coal slurry
pipeline segment. Northern Plains employs approximately 285 individuals located
at our headquarters in Omaha, Nebraska, and at various locations near the
pipelines and also utilizes employees and information technology systems of its
affiliates to provide its services. NBP Services' and Northern Plains' employees
are not represented by any labor union and are not covered by any collective
bargaining agreements.
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, Pan Border
and NBP Services 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," Item 13. "Certain Relationships and Related Transactions" and
Item 10. "Partnership Management."
We make available free of charge, through our website,
www.northernborderpartners.com, our annual reports on Form 10-K, quarterly
reports on Form 10-Q, current reports on Form 8-K and amendments to those
reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange
Act as soon as reasonably practicable after we electronically file such material
with, or furnish it to, the Securities and Exchange Commission.
For additional information about our business segments, see Note 14 -
Notes to Consolidated Financial Statements included in this report.
INTERSTATE NATURAL GAS PIPELINES
Our interstate pipelines segment provides natural gas transmission
services in the midwestern United States. Our interstate pipelines transport gas
for shippers under tariffs regulated by the FERC. The tariffs specify the
maximum and minimum transportation rates and the general terms and conditions of
transportation service on the pipeline systems. The interstate pipelines'
revenues are derived from agreements for the receipt and delivery of gas at
points along the pipeline systems as specified in each shipper's individual
transportation contract. The interstate pipelines do not own the gas that they
transport and therefore do not assume natural gas commodity
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price risk for quantities transported. Any exposure to commodity risk for
imbalances on the pipeline systems that may result from under or over deliveries
to customers or interconnecting pipelines is either recovered through provisions
in the tariffs or is immaterial. The interstate pipelines do own the line pack,
which is the amount of gas necessary to maintain efficient operations of the
pipeline. Shippers on each system are responsible to provide fuel gas necessary
for the operation of the gas compressor stations on the pipelines. For 2003,
Northern Border Pipeline Company, Midwestern Gas Transmission Company and Viking
Gas Transmission Company accounted for 86%, 6% and 8%, respectively of the
revenues in the interstate pipeline segment.
NORTHERN BORDER PIPELINE SYSTEM
We own a 70% general partnership interest in Northern Border Pipeline
Company, a Texas general partnership. Northern Border Pipeline owns 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. The pipeline system was expanded and/or extended in 1991,
1992, 1998 and 2001. This pipeline system connects directly and through multiple
pipelines to various natural gas markets in the United States. In the year ended
December 31, 2003, we estimate that Northern Border Pipeline 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.
Our interest in Northern Border Pipeline represents the largest
proportion of our assets, earnings and cash flows. The remaining 30% general
partner interest in Northern Border Pipeline is owned by TC PipeLines
Intermediate Limited Partnership, a subsidiary limited partnership of TC
PipeLines, LP, a publicly-traded partnership ("TC PipeLines"). The general
partner of TC PipeLines and its subsidiary limited partnership is TC PipeLines
GP, Inc., which is a subsidiary of TransCanada.
Management of Northern Border Pipeline is overseen by the Northern
Border Management Committee, which is comprised of three representatives from
the Partnership (one designated by each of our general partners) and one
representative from 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 our three representatives on the management committee is
allocated as follows: 35% to the representative designated by Northern Plains,
22.75% to the representative designated by Pan Border and 12.25% to the
representative designated by Northwest Border. Therefore, Enron controls 57.75%
of the voting power of the management committee and has the right to select two
of its members. For a discussion of specific relationships with affiliates,
refer to Item 13. "Certain Relationships and Related Transactions."
The pipeline system consists of 822 miles of 42-inch diameter pipe from
the Canadian border to Ventura, Iowa, capable of transporting
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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.
The pipeline system has pipeline access to natural gas reserves in the
western Canadian sedimentary basin in the provinces of Alberta, British Columbia
and Saskatchewan in Canada, domestic natural gas produced within the Williston
Basin and the Powder River 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 pipeline system connects to a
domestic natural gas gathering system owned by Omimex Ltd. In North Dakota, the
pipeline system connects with facilities of Northern Natural Gas Company at
Buford, which facilities in turn are connected to Williston Basin Interstate and
the gathering system owned by us through Bear Paw Energy. In December 2003, an
interconnection with a newly constructed pipeline owned by Williston Basin
Interstate Pipeline Company 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 the pipeline can receive gas are interconnections with Williston
Basin Interstate Pipeline at Glen Ullin, Amerada Hess Corporation at Watford
City, and 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 at
Channahon, Illinois. For the year ended December 31, 2003, of the natural gas
transported on the 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.
To access markets, the pipeline system interconnects with pipeline
facilities of various interstate and intrastate pipeline companies and local
distribution companies, as well as with end-users. The larger interconnections
are:
- Northern Natural Gas Company at Ventura, Iowa as well as
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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. 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 consuming markets in the
Midwest and to interconnecting pipeline facilities, have developed on the
pipeline system. The largest of these market centers is at Northern Border
Pipeline's Ventura, Iowa interconnection with Northern Natural Gas Company. Two
other market center locations are the Harper, Iowa connection with Natural Gas
Pipeline Company of America and the 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.
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
Northern Border Pipeline's 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."
5
Northern Border Pipeline's shippers may change throughout the year as a
result of its shippers utilizing capacity release provisions that allow them to
release all or part of their capacity, either permanently for the full term of
their contract or temporarily. Under the terms of Northern Border Pipeline's
tariff, a temporary capacity release does not relieve the original contract
shipper from its payment obligations if the new shipper fails to pay.
For the year ended 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
Northern Border Pipeline's revenues. As of December 31, 2003, Northern Border
Pipeline's 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 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."
MIDWESTERN GAS TRANSMISSION SYSTEM
Midwestern Gas Transmission Company, our wholly-owned subsidiary, owns
a 350-mile pipeline system extending from an interconnection with Tennessee Gas
Transmission near Portland, Tennessee to a point of interconnection with several
interstate pipeline systems near Joliet, Illinois. Midwestern Gas Transmission
serves markets in Chicago, Kentucky, southern Illinois and Indiana.
The Midwestern Gas Transmission system consists of 350 miles of 30-inch
and 24-inch diameter pipe with a capacity of 650 mmcfd for volumes transported
from Portland, Tennessee to the north. There are seven compressor stations with
total rated horsepower of 65,570. Midwestern Gas Transmission system is also
capable of moving approximately 350 mmcfd south-bound depending upon receipt and
delivery point locations.
The Midwestern Gas Transmission system connects with multiple pipeline
systems that provide its shippers access to various supply sources and markets.
Because of its position in the natural gas pipeline grid, Midwestern Gas
Transmission is designed to receive gas volumes at both ends of its system. On
the north end, Midwestern Gas Transmission can physically receive gas from ANR
Pipeline Company, Northern Border Pipeline, Natural Gas Pipeline Company of
America, Alliance Pipeline, The Peoples Gas Light and Coke Company and Trunkline
Gas Company. The significant receipt point on the southern end of the system is
the interconnection with Tennessee Gas Transmission at Portland. Additionally,
Midwestern Gas Transmission is capable of receiving gas at five other
interconnections along its pipeline system. With respect to market access,
Midwestern Gas Transmission is capable of delivering natural gas at points of
interconnection with the interstate pipeline systems of ANR Pipeline Company,
Guardian Pipeline,
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L.L.C., Natural Gas Pipeline Company of America, Northern Border Pipeline, and
Texas Gas Transmission Company as well as interconnections with local
distribution companies such as Northern Illinois Gas Company, The Peoples Gas
Light and Coke Company, Illinois Power, and Vectren Energy Delivery. In
addition, a number of end users and electric power generation facilities can be
served by connections off the pipeline system.
The Midwestern Gas Transmission system serves approximately 30 firm
transportation shippers. Based upon shipper contractual obligations as of
December 31, 2003, approximately 49% of the firm transportation capacity is
contracted by local distribution companies, 48% by marketers and 3% by
end-users.
For the year ended December 31, 2003, Midwestern Gas Transmission's
three major customers, Northern Illinois Gas Company, Northern Indiana Public
Service Company and ProLiance Energy LLC accounted for $5.2 million (24%), $2.9
million (13%) and $2.9 million (13%), respectively, of its revenues.
As of December 31, 2003, the termination dates of Midwestern Gas
Transmission's firm transportation contracts ranged from March 31, 2004 to
October 31, 2019. The weighted average contract life, based upon annual contract
obligations, was approximately two and one-third years. See Item 7.
"Management's Discussion and Analysis of Financial Condition and Results of
Operations - Overview."
One shipper, Enron North America Corp. ("ENA"), which filed for
bankruptcy protection, is affiliated with two of our general partners, Northern
Plains and Pan Border. ENA's contract was rejected in November 2003 by ENA, and
covered less than 1 percent of Midwestern Gas Transmission's firm capacity. 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."
VIKING GAS TRANSMISSION SYSTEM
Effective January 17, 2003, we acquired Viking Gas Transmission
Company, including a one-third interest in Guardian Pipeline, L.L.C. The Viking
Gas Transmission system extends from an interconnection with TransCanada near
Emerson, Manitoba to an interconnection with ANR Pipeline Company near
Marshfield, Wisconsin. Viking Gas Transmission's source of gas supply is the
western Canadian sedimentary basin. Viking Gas Transmission also has
interconnections with Northern Natural Gas Company and Great Lakes Gas
Transmission to serve markets in Minnesota, Wisconsin and North Dakota.
The Viking Gas Transmission system consists of 499 miles of 24-inch
diameter mainline pipe with a design capacity of approximately 500 mmcfd at the
origin near Emerson, Manitoba and 300 mmcfd at the terminus near Marshfield,
Wisconsin, 95 miles of 24-inch mainline looping and 79 miles of smaller diameter
laterals. There are eight compressor stations with total horsepower of 68,650.
The Viking Gas Transmission system serves over 40 firm transportation
shippers. Based upon shipper contractual obligations as
7
of December 31, 2003, approximately 81% of the firm transportation capacity is
contracted by local distribution companies, 12% by marketers and 7% by
end-users. As of December 31, 2003, Viking Gas Transmission's largest customers
were Northern States Power Company-Minnesota, CenterPoint Energy Minnegasco,
Michigan Consolidated Gas Company, Wisconsin Gas Company and Wisconsin Public
Service Corporation, who were obligated for approximately 16%, 12%, 10%, 10% and
9%, respectively, of the contracted firm capacity.
As of December 31, 2003, the termination dates of Viking Gas
Transmission's firm transportation contracts ranged from May 31, 2004 to October
31, 2014. The weighted average contract life, based upon contract obligations,
was approximately four years.
GUARDIAN PIPELINE SYSTEM
Guardian Pipeline is a 141-mile interstate natural gas pipeline system
that went into service on December 7, 2002. This system transports natural gas
from Joliet, Illinois to a point west of Milwaukee, Wisconsin. Subsidiaries of
Wisconsin Public Service and Wisconsin Energy Corporation hold the remaining
interests in this system. Wisconsin Gas Company, a subsidiary of Wisconsin
Energy Corporation, has contracted for 87% of the pipeline's 750 mmcfd capacity.
Guardian Pipeline is currently operated by Trunkline Gas Company, which is part
of the Panhandle Companies. Northern Plains has been selected to be the operator
of Guardian Pipeline effective July 1, 2004. See Item 13. "Certain Relationships
and Related Transactions."
DEMAND FOR INTERSTATE PIPELINE TRANSPORTATION CAPACITY
The long-term financial condition of our interstate natural gas
pipelines segment is dependent on the continued availability of economic natural
gas supplies including western Canadian natural gas for import into the United
States. Natural gas reserves may require significant capital expenditures by
others for exploration and development drilling and the installation of
production, gathering, storage, transportation and other facilities that permit
natural gas to be produced and delivered to pipelines that interconnect with our
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 natural gas supplies. 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. Additional pipeline capacity from producing basins also could
accelerate depletion of these reserves. Excess pipeline capacity could also
affect the demand or value of the transport on our interstate pipelines.
Each of our interstate pipelines' 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 the pipeline systems. Demand for
natural gas to serve other markets also influences the ability and willingness
of shippers to use our pipeline systems to meet demand in the markets that our
interstate
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pipelines serve.
A variety of factors could affect the demand for natural gas in the
markets that our pipeline systems 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.
Our interstate pipelines' primary exposure to market risk occurs at the
time existing transportation contracts expire and are subject to 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 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 interstate pipelines may experience seasonal
fluctuations depending upon the level of winter heating load demand or summer
electric generation usage in the markets served by the pipeline systems.
However, since approximately 98% of the expected revenue for these pipelines 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 interstate pipeline systems or how significant
that adverse effect could be.
INTERSTATE PIPELINE COMPETITION
Northern Border Pipeline and Viking Gas Transmission 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. Their competitive positions are 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
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United States. Demand for transportation services on the systems is affected by
natural gas prices, the relationship between export capacity 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 or to markets on the West Coast.
The Alliance Pipeline competes directly with Northern Border Pipeline
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 Northern Border Pipeline, 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. The Alliance Pipeline has also brought increased supply
access for Midwestern Gas Transmission's customers. The Alliance Pipeline
receipt point into the Midwestern Gas Transmission system near Joliet, Illinois
provided 46% of Midwestern Gas Transmission natural gas receipts during 2003.
In addition, Northern Border Pipeline competes in its markets with
other interstate pipelines that provide access to other supply basins. Northern
Border Pipeline's major deliveries into Northern Natural Gas at Ventura, Iowa
compete with gas supplied from the Rockies, and mid-continent regions. Northern
Border Pipeline also competes with these supply basins at its delivery
interconnect with Natural Gas Pipeline at Harper, Iowa. In the Chicago area,
Northern Border Pipeline competes with many interstate pipelines that transport
gas from the Gulf Coast, mid-continent, Rockies and western Canada.
Midwestern Gas Transmission can receive and deliver gas at either end
of its system, which makes it a header pipeline system. Consequently, Midwestern
Gas Transmission faces competition from multiple supply sources and interstate
pipelines. In the Chicago market, Midwestern Gas Transmission's competition is
from pipelines transporting gas from the gulf coast and the mid-continent and
gas sourced from Canada. In the Indiana and Western Kentucky markets, Midwestern
Gas Transmission's competition is from pipelines transporting gas from the gulf
coast and mid-continent into these markets.
Viking Gas Transmission directly serves markets in North Dakota,
Minnesota and Wisconsin. Northern Natural Gas competes with Viking Gas
Transmission in these states. In addition, Viking Gas Transmission indirectly
serves Wisconsin and Michigan markets through deliveries into ANR Pipeline. The
deliveries into ANR Pipeline compete with other supply sources on ANR Pipeline,
which includes supply from the gulf coast, mid-continent and Chicago market
center.
In October 2003, ANR Pipeline filed a certificate application with the
FERC to expand its capacity in the north leg of
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its pipeline system by approximately 107,000 dekatherms per day to replace
receipts from Viking Gas Transmission at the Marshfield, Wisconsin
interconnection by November 2005. Viking Gas Transmission intervened in ANR's
proceeding and the FERC staff is currently evaluating ANR's proposal. We cannot
predict at this time how this project, if approved, may impact the amount of
capacity contracted after 2005.
INTERSTATE PIPELINE REGULATION
Our interstate pipelines are subject to extensive regulation by the
FERC, each 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 this business segment, 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, our interstate pipelines hold certificates of public
convenience and necessity issued by the FERC covering the facilities, activities
and services. Under Section 8 of the Natural Gas Act, the FERC has the power to
prescribe the accounting treatment for items for regulatory purposes. Our
interstate pipelines' books and records may be periodically audited by the FERC
under Section 8. We were notified in November 2002 that Northern Border Pipeline
and Midwestern Gas Transmission were two 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. During 2003,
the FERC issued its final reports that found both to be 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 for interstate
pipelines 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
11
authorization and rates may be negotiated subject to FERC approval. The rates
and terms and conditions for service are found in the FERC approved tariffs.
Under its tariff, an interstate pipeline is allowed to charge for its
services on the basis of stated transportation rates. Transportation rates are
established periodically in FERC proceedings known as rate cases. The tariff
also allows the interstate pipeline to 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. For our
interstate pipelines, approximately 98% of the revenue generated is attributed
to demand charges. The remaining 2% is attributed to commodity charges based on
the volumes of gas actually transported.
Under the terms of settlement in Northern Border Pipeline's 1999 rate
case, neither Northern Border Pipeline nor its existing shippers can seek rate
changes until November 1, 2005, at which time Northern Border Pipeline must file
a new rate case. Midwestern Gas Transmission and Viking Gas Transmission are
under no obligation to file new rate cases. Prior to a future rate case, the
interstate pipelines will not be permitted to increase rates if costs increase,
nor will they be required to reduce rates based on cost savings. As a result,
the interstate pipelines' earnings and cash flow will depend on future costs,
contracted capacity, the volumes of gas transported and their ability to
recontract capacity at acceptable rates.
Until new depreciation rates are approved by the FERC, the interstate
pipeline continues to depreciate its transmission plant at FERC approved
depreciation rates. For our pipelines, the annual depreciation rates on
transmission plant in service are 2.25% for Northern Border Pipeline, 1.9% for
Midwestern Gas Transmission and 2.0% for Viking Gas Transmission. In order to
avoid a decline in the transportation rates established in future rate cases as
a result of accumulated depreciation, the interstate pipeline must maintain or
increase its rate base by acquiring or constructing assets that replace or add
to existing pipeline facilities or by adding new facilities.
In Northern Border Pipeline's 1995 rate case, the FERC addressed the
issue of whether the federal income tax allowance included in Northern Border
Pipeline's 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 Northern Border Pipeline's 1995
rate case provided that until at least December 2005, Northern Border Pipeline
could continue to calculate the allowance for income taxes in the manner it had
historically used. In addition, a settlement adjustment mechanism was
implemented, which effectively reduces the return on rate base. These provisions
of the 1995 rate case were maintained in the settlement of Northern Border
Pipeline's 1999 rate case.
Our interstate pipelines 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
12
to interruptible shippers is the sum of the firm transportation maximum demand
and commodity charges. From December 1, 1999 through October 31, 2003, Northern
Border Pipeline shared net interruptible transportation service revenue and any
new services revenue on an equal basis with its firm shippers. Beginning
November 1, 2003, Northern Border Pipeline retained all revenues from these
services.
Our interstate pipelines are subject to the requirements of FERC Order
Nos. 497 and 566, which prohibit preferential treatment of their marketing
affiliates and govern how information may be provided to those marketing
affiliates. On November 25, 2003, the 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 preferences 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, each of our interstate
pipelines posted a compliance plan to its website on February 9, 2004. By
definition, Bear Paw Energy, LLC and Crestone Energy Ventures, L.L.C. are energy
affiliates. The operator of our interstate pipelines, Northern Plains, provides
after hours and weekend gas control services for Bear Paw Energy and Crestone
Energy Ventures that results in some cost savings to our interstate pipelines.
Our interstate pipelines 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 Energy Ventures. If the waiver is not granted, the cost to
maintain gas control for these affiliates and our interstate pipelines 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%. The cash management agreements
between Midwestern Gas Transmission, Viking Gas Transmission and us have been
filed with FERC. Northern Border Pipeline does not have a cash management
agreement nor is it required to and FERC was so notified. We do not expect that
the FERC's policy will have a material impact on our cash management practices.
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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
the FERC. The 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 businesses
do not derive a significant amount of their revenues from negotiated rate
transactions, this FERC ruling is not expected to have a material effect on our
businesses.
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. The enactment of some of these standards may have the effect
of easing certain creditworthiness requirements and parameters currently
reflected in our tariffs. Recent FERC orders, and this proposed rule, support
greater collateral requirements for credit on shippers for the construction of
new facilities by a pipeline. However, we cannot predict the ultimate impact, if
any, on our interstate pipelines of any resulting final rule.
In February 2004, the FERC adopted new quarterly financial reporting
requirements and accelerated the filing date for the 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, our interstate pipelines file to make changes to
their tariffs to clarify provisions, to reflect current industry practices and
to reflect recent FERC rulings. In February 2003, Northern Border Pipeline filed
to amend the definition of company use gas, which is gas supplied by its
shippers for its operations, to
14
clarify the language by adding detail to the broad categories that comprise
company use gas. However, in its March 2003 order, the FERC directed Northern
Border Pipeline to cease collecting electric costs through its company use gas
provisions and to refund with interest, within 90 days, all electric costs that
had been collected through its company use gas provisions. Refunds of
approximately $10 million were made in May 2003.
In August 2003, Northern Border Pipeline filed revised tariff sheets to
clarify its 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 Northern Border Pipeline violated its tariff by denying
a request for service that would have involved a short distance for less than
one year. On September 10, 2003, the FERC rejected Northern Border Pipeline's
tariff sheets based on 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, Northern Border Pipeline had the right not to
sell capacity requested for short distances or on a short-term basis. Northern
Border Pipeline filed a timely request for rehearing of the Commission's Order
in October 2003 which is still pending. Northern Border Pipeline also filed
responses to requests for further information on the award of capacity in the
summer of 2003. Northern Border Pipeline filed its compliance tariff sheets in
early December 2003 and is awaiting a Commission decision on these tariff
sheets. Northern Border Pipeline's tariff sheets and the final orders to be
entered in this proceeding will impact how it awards 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,
Northern Border Pipeline may potentially be required to accept bids for shorter
distances or shorter time periods that may result in creating segments of
capacity of minimal value.
In March 2004, Northern Border Pipeline filed tariff sheets to
implement two balancing services to assist deliveries at variable load points,
such as electrical generation plants. Northern Border Pipeline also filed with
the FERC certain agreements related to third party balancing which it believed
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 filed in March 2004 will have a material adverse impact on our
business.
NATURAL GAS GATHERING AND PROCESSING SEGMENT
Our gas gathering and processing segment provides services for the
gathering, treating, processing and compression of natural gas and the
fractionation of natural gas liquids (NGLs) for third parties and related field
services. We do not explore for, or produce, crude oil or natural gas, and do
not own crude oil or natural gas reserves.
Bear Paw Energy, our wholly-owned subsidiary, has extensive natural gas
gathering, processing and fractionation operations in the
15
Williston Basin in Montana and North Dakota as well as gas gathering operations
in the Powder River Basin in Wyoming. In the Williston Basin, Bear Paw Energy
has over 3,000 miles of gathering pipelines and five processing plants with 95
mmcfd of capacity. In the Powder River Basin, Bear Paw Energy has approximately
1,100 miles of high and low pressure gathering pipelines, approximately 92
compressor stations with approximately 130,000 installed horsepower and
long-term volumetric contracts with producers covering approximately 430,000
acres of dedicated reserves in the Powder River Basin. Bear Paw Energy's
revenues are primarily derived under fee-based gathering and percentage of
proceeds agreements.
In addition, through our wholly-owned subsidiary, Crestone Energy
Ventures, we own a 49% interest in Bighorn Gas Gathering, L.L.C., a 33.33%
interest in Fort Union Gas Gathering, L.L.C. and a 35% interest in Lost Creek
Gathering, L.L.C., which collectively own over 300 miles of gas gathering
facilities in the Powder River and Wind River Basins in Wyoming.
The Bighorn and Fort Union systems gather coalbed methane gas produced
in the Powder River Basin in northeastern Wyoming. Under various agreements, the
majority of which are long-term, producers have dedicated their gas reserves to
Bighorn, giving Bighorn the right to gather natural gas produced in areas of
Wyoming covering approximately 800,000 acres. Bighorn's system is capable of
gathering more than 250 mmcfd of natural gas for delivery to the Fort Union
gathering system. Fort Union has the capability of delivering more than 634
mmcfd of gas into the interstate pipeline grid. The Lost Creek system gathers
natural gas produced from conventional gas wells in the Wind River Basin in
central Wyoming and consists of 120 miles of gathering header. The system is
capable of delivering more than 275 mmcfd of gas into the interstate pipeline
grid.
Cantera Natural Gas, LLC (formerly CMS Field Services, Inc.) holds the
remaining ownership interest in Bighorn and is the project manager and operator.
In July 2003, CMS Field Services, Inc. was sold by CMS Energy to Cantera Natural
Gas, LLC. The Bighorn system is managed through a management committee
consisting of representatives of the owners. Cantera Natural Gas, CIG Resources
Company, Western Gas Resources and Bargath, Inc. hold the remaining interests in
Fort Union. Cantera Natural Gas is the managing member, Western Gas Resources is
the field operator and CIG Resources Company is the administrative manager.
Burlington Resources Trading, Inc. holds the remaining interest in Lost Creek
and is the managing member. A subsidiary of Crestone Energy Ventures is the
commercial and administrative manager. This system is operated by Elkhorn Field
Services Company, an unaffiliated third party.
Bear Paw Energy's facilities in the Powder River Basin are
interconnected with the facilities of Bighorn, Fort Union and Thunder Creek Gas
Gathering, and all the gathering facilities interconnect to the interstate gas
pipeline grid serving gas markets in the Rocky Mountains, the Midwest and
California.
Bear Paw Energy's Williston Basin gathering and processing
facilities are located in eastern Montana and western North Dakota, with a small
extension into Saskatchewan, Canada. The Williston Basin system
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consists of approximately 3,000 miles of polyethylene and steel pipeline and 29
compressor stations with a total rated horsepower of 29,000, in addition to
plant compression of approximately 19,000 horsepower. Most of the wells
connected to the facilities produce casinghead gas in association with crude
oil. This gas is generally high in NGLs. The NGLs are separated from the gas at
our processing plants and then fractionated into components and sold. The
residue gas is sold into the interstate market. A substantial portion of Bear
Paw Energy's gathering and processing contracts in the Williston Basin provide
for the sale of the natural gas stream to Bear Paw Energy. Upon sale of the NGLs
and the residue gas processed, Bear Paw Energy pays the producers based upon a
percentage of the net proceeds realized.
Our wholly-owned subsidiary, Border Midstream Services, Ltd. owns an
undivided minority interest in the Gregg Lake/Obed Pipeline located in Alberta,
Canada. Until June 2003, it also owned the Mazeppa and Gladys gas processing
plants, and associated gathering pipelines.
The Gregg Lake/Obed Pipeline is located in west central Alberta and
consists of 85 miles of pipeline with a design capacity of 150 mmcfd. Border
Midstream receives 63% of the cash distributions until such time when it has
been reimbursed its share of the original construction costs of the Gregg Lake
portion of the pipeline, which is expected to occur in 2006. Subsequently,
Border Midstream will receive 36% of the distributions, which is equal to its
ownership interest in the entire Gregg Lake/Obed Pipeline. Central Alberta
Midstream holds the remaining undivided interest in Gregg Lake/Obed Pipeline and
is its operator.
FUTURE DEMAND AND COMPETITION
Our gas gathering and processing segment competes with other natural
gas gathering, processing and pipeline companies in the production areas in the
Powder River, Wind River, Williston and western Canadian sedimentary Basins.
Primary competitors in the Powder River Basin of Wyoming include both
independent gathering companies and gathering companies affiliated with
producers. Primary competitors affiliated with producers include affiliates of
Western Gas Resources, Devon Energy Corporation, Fidelity Exploration &
Production, Yates Petroleum and Anadarko Petroleum Corp. Primary non-producer
affiliated competitors include Bighorn and Optigas. Competition for gathering
and processing services in the Williston Basin includes Amerada Hess and
PetroHunt Corporation in localized areas. Our competitive positions are affected
by the pace of gas drilling, gas production rates, gas reserves, natural gas and
NGLs commodity prices, regulation and the demand for natural gas and NGLs in
North America.
The pace of gas drilling may be impacted by, among other things, the
ability of producers to obtain and maintain the necessary drilling and
production permits in a timely and economic manner, reserve characteristics and
performance, surface access and infrastructure issues as well as commodity
prices. In addition, the regulation of discharge of the significant volumes of
water produced in association with coalbed methane production can be a deterrent
to producers in determining whether to drill or produce. The time period during
which coalbed methane wells dewater before significant gas production becomes
available may be unpredictable. Water quality may vary substantially, and
disposal alternatives and associated costs may also affect
17
producers' decisions to drill or produce. On January 17, 2003, the Bureau of
Land Management ("BLM") released two final environmental impact statements
("EIS") regarding oil and natural gas development on Federal lands. One EIS
pertains to oil and gas development on BLM-administered public lands and federal
mineral leases within the Powder River Basin in northeastern Wyoming. The other
EIS pertains to statewide oil and natural gas development in Montana. Lawsuits
have been filed challenging the EIS in Wyoming and Montana. However, BLM's
issuance of new drilling permits under the regulatory preconditions has
continued, albeit at a slower rate than previous years. Approximately 65% of the
Powder River Basin acreage is on federal lands.
In providing gas gathering, processing and other services, we may
require acreage dedication, long term commitment and/or minimum volume
commitments or demand charges from gas producers. Once a gathering and
processing position is established, the term of the dedication, the likely
economic reserve life and the cost of building duplicative facilities mitigate
the level of competition in the vicinity. Development of future gas gathering
and processing facilities will be staged to reflect the growth in number of
wells and field production, economics, permitting considerations and other
factors impacting producers' decisions to drill and produce. See Item 7.
"Management's Discussion and Analysis of Financial Condition and Results of
Operations - Overview."
We differentiate ourselves by the terms of services offered, our
flexibility and additional value-added services provided. Our relationships with
producers allow us to offer integrated services through all our gathering and
processing facilities, as well. We also provide a variety of delivery choices,
wide coverage area and operational efficiencies. We seek to improve operational
profitability by increasing natural gas throughput through new connections,
expansion, acquisitions, operational efficiencies and prudent deployment of
capital.
COAL SLURRY PIPELINE
Black Mesa Pipeline, Inc., our wholly - owned subsidiary, owns a
273-mile, 18-inch diameter coal slurry pipeline which originates at a coal mine
in Kayenta, Arizona. The coal slurry pipeline transports crushed coal suspended
in water. It traverses westward through northern Arizona to the 1,500 megawatt
Mohave Power Station located in Laughlin, Nevada. The coal slurry pipeline is
the sole source of fuel for the Mohave Power Station, which consumes an average
of 4.8 million tons of coal annually. The capacity of the pipeline is fully
contracted to Peabody Western Coal, the coal supplier for the Mohave Power
Station, through the year 2005. The source of water used is from an aquifer in
The Navajo Nation and Hopi Tribe joint use area. The Navajo Nation and Hopi
Tribe have not agreed to continued use of water from this aquifer after December
31, 2005. Under a consent decree, the Mohave Plant has agreed to install certain
pollution control equipment by December 2005. With questions surrounding the
water supply and renegotiation of the coal supply contracts, Southern California
Edison, as one of the owners of the Mohave Plant, filed a petition before the
California Public Utility Commission ("CPUC") requesting that the CPUC either
recognize the end of Mohave's coal-fired operations as of the end of 2005 with
appropriate ratemaking accounts or authorize
18
expenditures for pollution control activities required for future operation.
Evidentiary hearings are expected this year. If efforts by the parties to
resolve these issues are not successful and the Mohave Plant is permanently
closed, it would be necessary to shut down Black Mesa in 2006. Even with
successful resolution of the issues, it may require that the plant, as well as
the Black Mesa system, be temporarily idled for a two to three year period while
pollution control equipment is installed at the plant and the Black Mesa system
is rebuilt. See Item 7. "Management's Discussion and Analysis of Financial
Condition and Results of Operations - Overview."
Approximately 53 people are employed in the operations of Black Mesa,
of which 25 are eligible to be represented by a labor union, the United Mine
Workers of America ("UMWA"). Black Mesa's collective bargaining agreement with
the UMWA was renewed in 2003 and is effective through December 31, 2005.
ENVIRONMENTAL AND SAFETY MATTERS
Our interstate pipeline and U.S. gathering and processing operations
are subject to federal, state and local laws and regulations relating to safety
and the protection of the environment, which include, as applicable, the
Resource Conservation and Recovery Act, the Comprehensive Environmental
Response, the Compensation and Liability Act of 1980, as amended, the 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 of 2002, ("Act") 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 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 interstate pipelines. 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 pipelines. However, the plan will be modified as a result of the
findings noted and could result in
19
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 integrity assessments for 2004 to be approximately $1.0
million.
In Canada, our gathering facilities are subject to Canadian, provincial
and local laws and regulations relating to safety and the protection of the
environment, which include the following Alberta laws: the Energy Resources
Conservation Act, the Oil and Gas Conservation Act, the Pipeline Act, and the
Environmental Protection and Enhancement Act.
Black Mesa is subject to a judgment and Consent Decree entered in the
United States District Court of Arizona in July 2001. Under the Consent Decree,
the United States Environmental Protection Agency ("EPA"), the Arizona
Department of Environmental Quality ("ADEQ") and Black Mesa agreed to the
payment of penalties for alleged violations of federal and state law due to
unplanned discharges of coal slurry from Black Mesa's pipeline from December
1997 through July 1999. The Consent Decree also sets forth certain preventative
measures, reporting requirements and associated penalties for failure to comply
in the future. Since the Consent Decree was entered, there have been several
unplanned slurry discharges that have been reported to the EPA and ADEQ. In
2003, Black Mesa paid to the EPA and ADEQ total stipulated penalties pursuant to
the Consent Decree of $229,250.
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
and gas processing 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 enactment of increasingly strict environmental and safety
laws, regulations and enforcement policies thereunder 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
Northern Border Pipeline, Midwestern Gas Transmission, Viking Gas
Transmission and Guardian Pipeline hold the right, title and interest in their
pipeline systems. With respect to real property, the pipeline systems fall 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 systems across
certain property was obtained through exercise of the power of eminent domain.
The interstate pipeline systems continue to have the power of eminent domain in
each of the states in which they operate, although Northern
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Border Pipeline may not have the power of eminent domain with respect to Native
American tribal lands.
Approximately 90 miles of Northern Border Pipeline's system 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. Northern Border
Pipeline does have the right of eminent domain with respect to allotted lands.
In 1980, Northern Border Pipeline entered into a pipeline right-of-way
lease with the Fort Peck Tribal Executive Board, for and on behalf of the
Assiniboine and Sioux Tribes of the Fort Peck Indian Reservation ("Tribes").
This pipeline right-of-way lease, which was approved by the Department of the
Interior, Bureau of Indian Affairs ("BIA") in 1981, granted to Northern Border
Pipeline the right and privilege to construct and operate its 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, Northern Border Pipeline 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 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.
Bear Paw Energy, Bighorn, Lost Creek and Fort Union hold the right,
title and interest in their gathering and processing facilities, which consist
of low and high pressure gas gathering lines, compression and measurement
installations and treating, processing and fractionation facilities. The real
property rights for these facilities are derived through fee ownership, leases,
easements, rights-of-way and permits.
Black Mesa holds title to its pipeline and pump stations. The real
property rights for Black Mesa facilities are derived through fee ownership,
leases, easements, rights-of-way and permits. Black Mesa holds rights-of-way
grants from private landowners as well as The Navajo Nation and the Hopi Tribe.
These rights-of-way grants extend for terms at least through December 31, 2005,
the date that Black Mesa's transportation contract with Peabody Western Coal is
presently scheduled to end.
ITEM 3. LEGAL PROCEEDINGS
On July 31, 2001, the 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, reached a settlement in
21
principle on pipeline right-of-way lease and taxation issues, subject to final
documentation and necessary governmental approvals. Final documentation has been
completed and is subject to the approval of the BIA, which the parties believe
will be obtained shortly. This settlement grants to Northern Border Pipeline,
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 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. 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 - Environmental and Safety Matters" for the
discussion on the Consent Decree entered against Black Mesa and "Business - Coal
Slurry Pipeline" for the discussion on the proceeding before the CPUC related to
Black Mesa's continuation of service beyond 2005.
See Item 1. "Business - Interstate Pipeline Regulation" for the
discussion on proceedings 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 financial condition.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security holders during
2003.
22
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON UNITS
AND RELATED SECURITY HOLDER MATTERS
Our common units are traded on the New York Stock Exchange. The
following table sets forth, for the periods indicated, the high and low sale
prices per common unit, as reported on the New York Stock Exchange Composite
Tape, and the amount of cash distributions per common unit declared for each
quarter:
Price Range Cash
High Low Distributions
---- --- -------------
2003
Fourth Quarter................. $43.70 $35.98 $0.80
Third Quarter.................. 44.07 40.50 0.80
Second Quarter................. 42.33 38.10 0.80
First Quarter.................. 39.00 36.57 0.80
2002
Fourth Quarter................. $38.00 $33.46 $0.80
Third Quarter.................. 37.50 29.30 0.80
Second Quarter................. 41.90 35.43 0.80
First Quarter.................. 42.50 34.25 0.80
As a result of pending proceedings by Enron before the Securities and
Exchange Commission on regulation under the Public Utility Holding Company Act
of 1935, we delayed the declaration of distribution for the fourth quarter 2003.
On February 9, 2004, we declared a distribution of $0.80 per unit ($3.20 per
unit on an annualized basis), payable February 20, 2004 to the general partners
and unitholders of record at February 17, 2004. Based upon the order issued by
the Securities and Exchange Commission on March 9, 2004, we have received the
necessary approvals under the Public Utility Holding Company Act of 1935 to
declare and pay future distributions. See Item 7. "Management's Discussion and
Analysis of Financial Condition and Results of Operations - Public Utility
Holding Company Act ("PUHCA") Regulation."
As of February 17, 2004, there were approximately 1,400 record holders
of common units and approximately 60,900 beneficial owners of the common units,
including common units held in street name. On March 3, 2004, the last reported
sale price of our common units on the New York Stock Exchange was $40.09 per
common unit.
We currently have 46,397,214 common units outstanding, representing a
98% limited partner interest. The common units are the only outstanding limited
partner interests. Thus, our equity consists of general partner interests
representing in the aggregate a 2% interest and common units representing in the
aggregate a 98% limited partner interest.
The general partners are entitled to 2% of all cash distributions, and
the holders of common units are entitled to the remaining 98% of all cash
distributions, except that the general partners are entitled to incentive
distributions if the amount
23
distributed with respect to any quarter exceeds $0.605 per common unit ($2.42
annualized). Under the incentive distribution provisions, the general partners
are entitled to 15% of amounts distributed in excess of $0.605 per common unit,
($2.42 annualized) 25% of amounts distributed in excess of $0.715 per common
unit ($2.86 annualized) and 50% of amounts distributed in excess of $0.935 per
common unit ($3.74 annualized). The amounts that trigger incentive distributions
at various levels are subject to adjustment in certain events, as described in
our partnership agreement.
EQUITY COMPENSATION PLAN INFORMATION
Effective November 1, 2001, Northern Plains and NBP Services adopted
the Amended and Restated Northern Border Phantom Unit Plan as an incentive to
attract and retain employees who are essential to the services provided to us
and our subsidiaries. The Administrative Committee under the Plan, which are
appointees of Northern Plains and NBP Services, may grant either phantom units
which are based upon the general partner distribution rate or phantom LP units
which are based on the price of our common units. The Administrative Committee
has complete authority to determine the terms and conditions of a grant,
including the identity of the participants, the time of grant, time and
provisions for settlement and duration of a grant. During the duration of a
grant, the participant's account is credited with distributions paid with
respect to the underlying security. Upon settlement of the phantom units and
phantom LP units, the participant will receive common units or cash or a
combination thereof, as determined by the Administrative Committee. The
settlement value of the phantom units is determined by using a value derived
from the general partner distribution rate and common unit distribution yield on
the settlement date. The settlement payment for the phantom LP units is
determined by the closing price of the common units on the settlement date.
Number of securities
to be issued upon Weighted average
exercise of exercise price of Number of units
outstanding phantom outstanding phantom remaining available
Plan Category units units for future issuance
------------- ------------------- ------------------- -------------------
(a) (b) (c)
- ------------------------------------------------------------------------------------------------------
Equity compensation plans
approved by the
unitholders (1) -- -- --
Equity compensation plans
not approved by the
unitholders (1) 43,989 (2) $ 39.27 (2) 194,500 (3)
- ------------------------------------------------------------------------------------------------------
Total 43,989 194,500
(1) Under our partnership agreement, our partnership policy committee has the
sole authority, without the approval of the unitholders, to adopt employee
benefit or incentive plans or issue common units pursuant to any employee
benefit or incentive plan maintained or sponsored by a general partner or its
affiliates.
(2) Based upon the closing price of the common units on December 31, 2003 and
assumes that all outstanding phantom units were settled in common units as of
December 31, 2003.
24
(3) The Plan limits the number of grants of phantom units and phantom LP units
to an aggregate of 200,000. This assumes all grants are phantom LP units.
On December 23, 2003, the Partnership announced a repurchase program by Northern
Plains to purchase in the open market up to 5,000 common units to satisfy
obligations in January 2004 under the Amended and Restated Northern Border
Phantom Unit Plan. Those units were purchased by December 30, 2003.
25
ITEM 6. SELECTED FINANCIAL DATA
(in thousands, except per unit, other financial data and operating data)
The following table sets forth, for the periods and at the dates indicated,
selected historical financial data for us. The selected consolidated financial
information should be read in conjunction with the Consolidated 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 (1) 2002 2001 (2) 2000 (3) 1999
----------- ---------- ----------- ---------- ----------
INCOME DATA:
Operating revenues, net $ 555,927 $ 487,204 $ 455,997 $ 339,732 $ 318,963
Product purchases 80,774 50,648 39,699 -- --
Operations and
maintenance 127,574 106,331 92,891 62,097 53,451
Depreciation and
amortization (4) 300,199 74,672 75,424 60,699 54,842
Taxes other than income 35,443 32,194 27,863 28,634 30,952
----------- ---------- ----------- ---------- ----------
Operating income 11,937 223,359 220,120 188,302 179,718
Interest expense, net 78,980 82,898 89,908 81,495 67,709
Other income, net 24,861 16,567 719 8,410 4,915
Minority interests
in net income 44,460 42,816 42,138 38,119 35,568
Income taxes 5,365 1,643 499 378 353
----------- ---------- ----------- ---------- ----------
Income (loss) from
continuing operations (92,007) 112,569 88,294 76,720 81,003
Discontinued operations,
net of tax (5) 4,196 1,107 (508) -- --
Cumulative effect of
change in accounting
principle, net of tax (643) -- -- -- --
----------- ---------- ----------- ---------- ----------
Net income (loss) to
partners $ (88,454) $ 113,676 $ 87,786 $ 76,720 $ 81,003
=========== ========== =========== ========== ==========
Per unit income (loss)
from continuing
operations $ (2.16) $ 2.41 $ 2.13 $ 2.50 $ 2.70
=========== ========== =========== ========== ==========
Per unit net income (loss) $ (2.08) $ 2.44 $ 2.12 $ 2.50 $ 2.70
=========== ========== =========== ========== ==========
Number of units used
in computation 45,370 42,709 38,538 29,665 29,347
=========== ========== =========== ========== ==========
CASH FLOW DATA:
Net cash provided by
operating activities $ 224,660 $ 244,006 $ 233,948 $ 169,615 $ 173,368
Capital expenditures 30,282 50,738 126,414 19,721 102,270
Acquisition of businesses 123,194 1,561 345,074 229,505 31,895
Distribution per unit 3.20 3.20 2.99 2.65 2.44
BALANCE SHEET DATA
(AT END OF YEAR):
Property, plant
and equipment, net $ 1,992,104 $2,015,280 $ 2,040,099 $1,732,076 $1,745,356
Total assets 2,570,583 2,715,936 2,687,355 2,082,720 1,863,437
Long-term debt, including
current maturities 1,415,986 1,403,743 1,423,227 1,171,962 1,031,986
Minority interests in
partners' equity 240,731 242,931 250,078 248,098 250,450
Partners' equity 800,573 944,035 914,958 572,274 515,269
26
YEAR ENDED DECEMBER 31,
-----------------------------------------------------
2003 (1) 2002 2001 (2) 2000 (3) 1999
--------- ------- ------- ------- -------
OTHER FINANCIAL DATA:
Ratio of earnings to
fixed charges (6) 0.4 2.8 2.5 2.4 2.7
OPERATING DATA:
Interstate Natural Gas
Pipeline Segment:
Million cubic feet
of gas delivered 1,110,969 935,654 891,935 852,674 834,833
Average daily
throughput (mmcfd) 3,147 2,636 2,605 2,400 2,353
Natural Gas Gathering and
Processing Segment:
Gathering (mmcfd) 1,094 1,089 793 397 --
Processing (mmcfd) 52 55 54 -- --
Coal Slurry
Pipeline Segment:
Thousands of tons
of coal shipped 4,451 4,639 4,932 4,711 4,494
(1) Includes results of operations for Viking Gas Transmission since date
of acquisition in January 2003.
(2) Includes results of operations for Bear Paw Energy (March 2001),
Midwestern Gas Transmission (May 2001) and Border Midstream Services
(April 2001) since dates of acquisition.
(3) Includes results of operations for Crestone Energy Ventures and
Crestone Gathering Services, L.L.C. since date of acquisition in
September 2000. The gathering activities of Crestone Gathering have
been integrated with those of Bear Paw Energy.
(4) Includes goodwill and asset impairment charge of $219,080 in 2003
related to our natural gas gathering and processing business segment.
(5) In June 2003, Border Midstream Services sold its Gladys and Mazeppa
processing plants and related gas gathering facilities.
(6) "Earnings" means the sum of pre-tax income from continuing operations
(before adjustment for minority interests in consolidated subsidiaries
or income from equity investees), fixed charges, amortization of
capitalized interest and distributions from equity investees, less
capitalized interest and the minority interests in pre-tax income of
subsidiaries that have not incurred 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. The ratio of
earnings to fixed charges for 2003 was lower than prior years' ratios
due primarily to the goodwill and asset impairment charges booked in
2003. Excluding the impact of the impairment, the ratio would be 3.2
for 2003.
27
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 Consolidated 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 Consolidated Financial Statements included elsewhere in this report.
OVERVIEW
The Partnership's businesses fall into three major business segments:
- the interstate natural gas pipeline segment, which
comprises 77% of our assets;
- the natural gas gathering and processing segment,
which comprises 22% of our assets; and
- the coal slurry pipeline, which comprises 1% of our
assets.
INTERSTATE NATURAL GAS PIPELINES
In the interstate natural gas pipeline segment, there are several major
business drivers. First, a healthy long-term supply outlook for each pipeline is
critical. Because the primary source of gas supply for two of our pipeline
systems is in the western Canadian sedimentary basin, western Canadian supply
trends are particularly important to this segment. 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 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 long-term financial
performance. Our pipeline systems serve natural gas markets in the upper
midwestern area of the United States and access a major market 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 for our
pipelines.
We charge fees for transportation which are primarily fixed and based
on the amount of capacity reserved for 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 contracts for
Northern Border Pipeline, Midwestern Gas Transmission and Viking Gas
Transmission are three and one third years, two and one third years and four
years, respectively. During 2003, Northern Border Pipeline was successful in
recontracting, at maximum rates, all the capacity under contracts that expired
on or before November 2003.
28
The composition of the natural gas can affect the amount of energy that
is transported through a pipeline system. Beginning in 2000, the energy content
of natural gas that Northern Border Pipeline receives at the Canadian border has
declined modestly from 1,023 British Thermal Units (Btus) per cubic foot (cf) to
1,005 Btus/cf. Northern Border Pipeline's transportation contracts in
conjunction with its 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. This Btu decline that is being experienced is primarily the result
of greater processing capacity in Alberta, Canada. The change has caused
Northern Border Pipeline to reduce its capacity by almost 2 percent to maintain
a high standard of system reliability for its customers. Although Btu levels
could go lower, we believe the Btu level will stabilize near the current level
of 1,005 Btus/cf.
Midwestern Gas Transmission's strategy is to maximize the benefits of
its central location and its connections to multiple pipeline systems. During
the fourth quarter of 2003, it conducted a non-binding open season for
transportation service through new delivery interconnects with interstate
pipelines serving eastern markets. Results were encouraging and we are in final
negotiations for new contracts to support the development of one to two new
interconnects. In addition, competitive pipeline projects may have a negative
impact on our profitability such as the proposed ANR Pipeline Company project to
expand its access to the Chicago hub and reduce its reliance on Viking Gas
Transmission's deliveries at Marshfield, Wisconsin for its Wisconsin customers.
This project would increase the price competition between Canadian supply
entering ANR Pipeline in Wisconsin versus Chicago sourced natural gas in
Illinois and could affect Viking Gas Transmission's future revenues for
Wisconsin markets served through ANR Pipeline.
NATURAL GAS GATHERING AND PROCESSING
The gas gathering and processing segment accepts delivery of raw gas
from natural gas wells at low pressure and gathers that wellhead production to
central points where it is processed as necessary and compressed to high
pressure for entry into the transmission pipeline grid. Key factors that have an
impact on this segment are the pace of reserve development, the decline rate of
existing wells, the composition of the raw gas stream being gathered, and the
value of natural gas and natural gas liquids.
We charge a fee for this service in the Powder River Basin. In the
Williston Basin, we buy the natural gas we gather and then resell the extracted
natural gas liquids and residue, retaining a portion of the resale revenues in
return for our gathering and processing services. In some cases, we charge a fee
as well. The producers receive the balance of the proceeds from the resale.
The Williston Basin has exhibited steady to slow growth in overall
volume levels. The Powder River area has seen net declines in gathering volumes
throughout 2003 where production from existing wells declined and was not
replaced by new wells at the same rate. Growth
29
was limited by the slower than expected issuance of drilling permits on federal
lands, reserve performance and regulatory issues.
In the Powder River Basin, earnings and cash flows have been below
initial expectations as a result of a slower pace of drilling and higher than
expected well production declines. We recorded impairment charges of $219
million and shortened the depreciable life to reflect the current value of these
assets. In addition, we are in the process of renegotiating our gathering
contracts with the purpose of stabilizing the revenue levels by charging a fee
for the use of our facilities instead of fees based upon volumes gathered. We
will also reconfigure systems where possible to reduce costs.
We hold minority interests in Bighorn, Fort Union, and Lost Creek which
are trunk gathering systems in the Powder River and Wind River Basins. These
businesses are also impacted by the pace of drilling, regulatory issues and
declines in upstream areas, however, they are generally more stable in terms of
throughput volumes and revenues because they gather gas from larger areas.
COAL SLURRY PIPELINE
Black Mesa Pipeline Company is our coal slurry pipeline. This pipeline
has one major customer, the coal supplier to the Mohave Generating Station, in
Laughlin, Nevada. This contract on Black Mesa provides a steady, fee for
service, revenue stream through 2005. After that time, the future is uncertain.
The Mohave Plant must complete some significant pollution control investments,
and a new water supply for the coal slurry mixture must be established. In
addition, new contracts for the coal supply, must be completed. We believe that
we will be able to negotiate a new contract for Black Mesa's services, however,
we cannot predict the timing or ultimate outcome. In the event the Mohave Plant
permanently closes, estimated shut down costs could be in the range of $5
million to $7 million for such expenses as environmental reclamation, severance
payments and pension plan funding. We would also be required to take a non-cash
charge of approximately $15 million related to goodwill and the remaining
undepreciated cost of the assets.
For all of our operations, we have continual focus on reliability for
our shippers, safety for the public and our customers, and compliance with
regulatory rules and regulations. In our businesses, these areas are essential.
STRATEGY
We are focused on growing our businesses, our income and cash flow and
our distributions to unitholders. Our strategy involves three main components.
INTERSTATE NATURAL GAS PIPELINES
First, we will continue to focus on safe, efficient, and reliable
operations and the further development of our regulated pipelines. We intend 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. Any growth
in our interstate pipelines would occur through incremental projects intended to
access new markets or supply areas and
30
would be supported by long-term contracts. We continue to work with producers
and marketers to develop the contractual support for a new 300-mile pipeline
project, the Bison Pipeline, to connect the coal bed methane reserves in the
Powder River Basin to markets served by Northern Border Pipeline. Northern
Border Pipeline intends to hold a new open season for the Bison pipeline when
production increases to levels that it believes will support the project. If
sufficient commitments are received, Northern Border Pipeline will pursue
regulatory approvals. In addition, Midwestern Gas Transmission will pursue
expanding existing interconnects and serving new delivery interconnects with
other interstate pipelines to grow transportation revenues. On Viking Gas
Transmission, we will work to minimize any impact on our recontracting efforts
that ANR Pipeline Company's proposal to expand its capacity in the north leg of
its pipeline system may have. We also intend to continue to expand the marketing
of new services to meet our customers' needs on our interstate pipelines.
As was the case last year, each of our interstate pipelines have some
firm transportation contracts expiring in 2004. Similar to other industries, the
value of capacity on interstate pipelines is driven by supply and demand
conditions. In particular, with respect to Northern Border Pipeline and Viking
Gas Transmission, the relationship between gas prices in Canada and prices in
the midwestern U.S. markets will determine the underlying value of
transportation capacity. 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
pipelines reaching downstream markets. With expectations of a continued
favorable commodity pricing environment and successful drilling programs that
will trend toward more non-conventional production, supply may remain stable in
the near-term. 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.
NATURAL GAS GATHERING AND PROCESSING
We also are developing our gas gathering and processing segment where
we are building on our established business relationships with producers and
marketers in the Canadian and Rocky Mountain supply basins. During 2003, the
pricing of gas produced from the Powder River Basin improved as there was some
relief of capacity constraints on pipelines to market hubs. However, the pace of
drilling has been slower than expected due primarily to regulatory issues
(including the basin-wide environmental impact statement ("EIS"), associated
litigation and response, and water disposal issues) and reserve performance. We
expect to see continued build-out of our gathering systems within the areas of
31
acreage dedications we have secured, particularly in the Powder River Basin, but
more slowly than previously expected. Depending on the pace of production
development, response to the basin-wide EIS and resultant litigation and
water-discharge permitting, we expect growth from new well connection to offset
the decline from existing gas wells to result in level to slightly lower in
aggregate gathered volumes on our Powder River systems (Bear Paw Energy, Bighorn
and Fort Union) during 2004. We are also pursuing different approaches to
conducting business in the Powder River Basin to reduce capital and operating
expenditures, improve revenue, and reduce volume and capital recovery risks. We
seek to build extensions to existing facilities on dedicated acreage using lower
risk rate structures, expand our gathering network securing additional acreage
dedications, and encourage utilization of existing facilities. We expect modest
growth in gas volumes for our pipelines in the Wind River, Williston and western
Canadian sedimentary basins, reflecting prospects for drilling activity within
these production areas. In the Williston Basin, we seek to build extensions and
expansions around our existing facilities and also pursue opportunities to
reduce costs and streamline operations. In addition, we are pursuing new acreage
dedications in each of these areas. The build-out of our existing, and the
addition of new, acreage dedications should mitigate production declines and
allow further improvement in cost efficiencies. With regard to our investment in
the Gregg Lake/Obed pipeline in Alberta, Canada, opportunities exist for a
potential expansion of the pipeline and discussions are underway with
prospective customers.
ACQUISITIONS
Finally, our objective is to continue to acquire complementary
businesses. Our goal is approximately $200 to $250 million of capital
expenditures annually in growth through acquisitions and internal development.
We target businesses that leverage our core competencies of energy
transportation, are conservative in terms of commodity price risk, are located
in the U.S. and Canada, and provide immediate earnings and cash flow
contribution. Our strategy is to focus on acquisitions of natural gas assets
including interstate and intrastate natural gas pipelines, storage facilities
and gathering and processing assets. We anticipate financing our capital
expenditures and acquisitions conservatively through an appropriate mix of
additional borrowings and equity issuances. Although we regularly evaluate
various acquisition opportunities, we cannot provide assurance that we will
reach our goal each year and would also expect that, depending on specific
opportunities that develop, acquisitions in some years could significantly
exceed our goal stated above. Our ability to maintain and grow our distributions
to the unitholders is dependent upon the growth of our existing businesses
and/or our acquisitions.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
Certain amounts included in or affecting our Consolidated 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
32
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. Key
estimates used by our management include the economic useful lives of our assets
used to determine depreciation and amortization, the fair values used to
determine possible asset impairment charges, the fair values used to record
derivative assets and liabilities, expense accruals, and the fair values of
assets acquired. 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 facts that give rise to the revision become known.
Our significant accounting policies are summarized in Note 2 - Notes to
Consolidated Financial Statements included elsewhere in this report. Certain of
our accounting policies are of more significance in our financial statement
preparation process than others.
The interstate natural gas pipelines' 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 future recovery of
the regulatory assets is probable 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 recorded regulatory assets of $8.9 million, which are
being recovered from the pipelines' 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. Useful lives
are based on historical experience and are adjusted when changes in planned use,
technological advances or other factors show that a different life would be more
appropriate. The depreciation rate used for utility property is an integral part
of the interstate pipelines' FERC tariffs. Any revisions to the estimated
economic useful lives of our assets will change our depreciation and
amortization expense prospectively. For utility property, no retirement gain or
loss is included in income except in the case of retirements or sales of entire
operating units. The original cost of utility property retired is charged to
accumulated depreciation and amortization, net of salvage and cost of removal.
We review long-lived assets for impairment in accordance with SFAS No.
144, "Accounting for the Impairment or Disposal of Long-Lived Assets."
Long-lived assets are reviewed for impairment whenever events or changes in
circumstances indicate that the carrying amount of an asset may not be
recoverable. Recoverability of the carrying amount of assets is measured by a
comparison of the carrying amount of the asset to future net cash flows expected
to be generated by the asset. Estimates of future net cash flows include
anticipated future revenues, expected future operating costs and other
estimates. If such assets are considered to be impaired, the impairment to be
recognized is measured by the amount by which the carrying amount of the assets
exceeds the
33
fair value of the assets.
Effective January 1, 2002, we adopted SFAS No. 142, "Goodwill and Other
Intangible Assets." The comparative impact of no longer amortizing goodwill is
shown in Note 4, Notes to Consolidated Financial Statements included elsewhere
in this report. We have selected the fourth quarter for the performance of our
annual impairment testing. As discussed below, in 2003, we decided to accelerate
the impairment testing for our natural gas gathering and processing business
segment to the third quarter. Our remaining business segments were tested in the
fourth quarter.
As discussed in Note 13, Notes to Consolidated Financial Statements,
effective January 1, 2003, we adopted 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. We have, where possible,
developed our estimate of the retirement obligations. The implementation of SFAS
No. 143 resulted in an increase in net property, plant and equipment of $2.5
million, an increase in reserves and deferred credits of $3.1 million and a
reduction to net income of $0.6 million for the net-of-tax cumulative effect of
the change in accounting principle.
Our accounting for financial instruments is in accordance with SFAS No.
133, "Accounting for Derivative Instruments and Hedging Activities," which
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, the
consolidated balance sheet included assets from derivative financial instruments
of $19.6 million and liabilities from derivative financial instruments of $5.7
million.
For our interstate natural gas pipelines, operating 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 are recognized based upon contracted capacity and actual
volumes transported under transportation service agreements. For our gas
gathering and processing businesses, operating revenue is recorded when gas is
processed in or transported through company facilities. For our coal slurry
pipeline, operating revenue is derived from a pipeline transportation agreement.
Under the terms of the agreement, we receive a monthly demand payment, a per ton
commodity payment and a reimbursement for certain other expenses.
RESULTS OF OPERATIONS
Our operating results for 2003 reflected several significant events.
Due to lower throughput volumes experienced and anticipated in our wholly owned
subsidiaries in our natural gas gathering and processing business segment, we
recorded impairment charges related to goodwill and tangible assets for that
segment. See Note 4 - Notes to
34
Consolidated Financial Statements, included elsewhere in this report. Effective
January 17, 2003, we acquired all of the common stock of Viking Gas
Transmission, including a one-third interest in Guardian Pipeline. See Note 3 -
Notes to Consolidated Financial Statements, included elsewhere in this report.
In June 2003, we sold our Gladys and Mazeppa processing plants located in
Alberta, Canada. The operating results for these plants are classified as
discontinued operations. See Note 3 - Notes to Consolidated Financial
Statements. Finally, as a result of Enron's decision to terminate its cash
balance plan, we recorded expenses for our expected charges related to the
termination of that plan.
Our operating results for 2002 reflected a full year of operating
results for acquisitions we made in the first half of 2001. During 2001, we made
the following acquisitions: Bear Paw Energy on March 30; the Mazeppa and Gladys
gas processing plants, gas gathering systems and a minority interest in the
Gregg Lake/Obed Pipeline on April 4, which are included in the operating results
of Border Midstream Services; and Midwestern Gas Transmission on May 1. Our 2002
operating results also benefited from the adoption of SFAS No. 142.
Our loss from continuing operations in 2003 was ($92.0 million),
($2.16) per unit, as compared to income from continuing operations of $112.6
million in 2002, $2.41 per unit, and $88.3 million in 2001, $2.13 per unit. Our
loss in 2003 resulted from a $219.1 million goodwill and asset impairment
recorded for our natural gas gathering and processing segment. Excluding the
impairment charges, income from continuing operations increased $14.5 million in
2003 as compared to 2002, which reflects income from Viking Gas Transmission of
$7.1 million, lower interest expense for Northern Border Pipeline of $6.6
million ($4.6 million impact on continuing operations after minority interest)
due to a decrease in average interest rates as well as a decrease in average
debt outstanding, a $2.9 million special income allocation related to a cash
distribution from our preferred A interest in Bighorn Gas Gathering and a $3.3
million payment received for a change in ownership of the other partner in
Bighorn Gas Gathering. These increases to income were partially offset by
charges associated with the termination of Enron's cash balance plan of $6.2
million ($4.8 million, net of tax and minority interest). The calculation of per
unit income (loss) was also impacted by the Partnership's issuance of additional
partnership interests in May and June 2003.
The $24.3 million increase in income from continuing operations in 2002
over 2001 resulted from the acquisitions made in 2001, a decline in interest
expense and the effect of the change in accounting for goodwill. As a result of
adopting SFAS No. 142, we are no longer amortizing goodwill (see Note 4 - Notes
to Consolidated Financial Statements). Our 2001 operating results included $13.3
million of goodwill amortization or $0.34 per unit. Goodwill amortization for
2001 by business segment was as follows: interstate natural gas pipelines - $0.9
million; natural gas gathering and processing - $12.0 million; and coal slurry -
$0.4 million. Interest expense decreased $7.0 million ($6.0 million impact on
continuing operations after tax and minority interest) between 2001 and 2002
primarily due to a decline in interest rates. Our average debt outstanding
increased between 2001 and 2002 due to our acquisitions in 2001.
35
The Partnership's consolidated income statement reflects income (loss)
from discontinued operations of $4.2 million in 2003 as compared to $1.1 million
in 2002 and ($0.5 million) in 2001. Discontinued operations for 2003 include an
after-tax gain of $4.9 million on the sale of the Gladys and Mazeppa processing
plants. In 2001, discontinued operations included a $1.6 million loss on a
forward purchase of Canadian dollars to fund our acquisition of Border Midstream
Service's gathering and processing assets. The consolidated income statement
also reflects a reduction to net income of $0.6 million due to a net-of-tax
cumulative effect of change in accounting principle, which resulted from
adopting SFAS No. 143, "Accounting for Asset Retirement Obligations."
INTERSTATE NATURAL GAS PIPELINES
Our interstate natural gas pipeline segment reported income of $119.6
million in 2003 and $107.5 million in 2002. In 2001, excluding the impact of
goodwill amortization, the segment reported income of $103.2 million. The
increase in 2003 income from 2002 primarily resulted from our acquisition of
Viking Gas Transmission on January 17, 2003, and lower interest expense for
Northern Border Pipeline. Viking Gas Transmission's income for 2003 totaled $7.1
million and Northern Border Pipeline's interest expense decreased by $6.6
million ($4.6 million net impact to income after minority interests). The
increase in 2002 income from 2001 resulted from our acquisition of Midwestern
Gas Transmission in April 2001. Midwestern Gas Transmission's income, excluding
the impact of goodwill amortization, increased $2.7 million from 2001 to 2002 as
the 2001 results included only eight months of revenues and expenses.
Operating revenues for our interstate natural gas pipeline segment were
$375.2 million in 2003, $339.1 million in 2002 and $322.6 million in 2001. The
increase in operating revenues in 2003 over 2002 resulted from Viking Gas
Transmission revenues of $29.0 million, an increase in Midwestern Gas
Transmission revenues of $4.0 million and an increase in Northern Border
Pipeline's revenues of $3.1 million. Midwestern Gas Transmission's revenues in
2003 reflect an increase in contracted capacity as compared to the same period
in 2002. Northern Border Pipeline's revenues for 2002 were affected by $1.8
million of uncollected revenues associated with the transportation capacity
formerly held by ENA, which filed for Chapter 11 bankruptcy protection in
December 2001 (see "The Impact Of Enron's Chapter 11 Filing On Our Business").
The increase in operating revenues in 2002 over 2001 resulted from an $8.5
million increase in Midwestern Gas Transmission's revenues and an $8.0 million
increase in Northern Border Pipeline's revenues. Midwestern Gas Transmission's
revenues in 2002 reflect an increase in contracted capacity as compared to the
same period in 2001. Midwestern Gas Transmission's revenues in 2001 reflected
only eight months of operations. For 2002, Northern Border Pipeline reflected
additional revenues of approximately $10.3 million related to Project 2000,
which was a pipeline expansion and extension placed in service in October 2001.
The impact of the additional revenues associated with Project 2000 was partially
offset by $1.8 million of uncollected revenues associated with the
transportation capacity formerly held by ENA.
Operations and maintenance expenses for our interstate natural
36
gas pipeline segment were $63.6 million in 2003, $48.3 million in 2002, and
$36.9 million in 2001. The increase in expenses in 2003 over 2002 resulted from
Viking Gas Transmission's expense of $10.8 million and an increase in Northern
Border Pipeline's expense and Midwestern Gas Transmission's expense by a
combined $4.5 million. This increase primarily related to the estimated charges
for termination of Enron's cash balance plan of $4.2 million. The increase in
expenses in 2002 over 2001 resulted from an increase in Northern Border
Pipeline's expense by $7.8 million and an increase in Midwestern Gas
Transmission's expense by $3.6 million. Northern Border Pipeline's expenses in
2002 reflected a $10.0 million accrual for costs related to the treatment of
previously collected quantities of natural gas used in utility operations to
cover electric power costs (see Footnote 5 - Notes to Consolidated Financial
Statements, included elsewhere in this report.) 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. Partially offsetting this increase in
expense was a reduction in bad debt expense by $1.3 million. Northern Border
Pipeline's expenses in 2001 included bad debt expense related to ENA's
bankruptcy. Midwestern Gas Transmission's increase for 2002 over 2001 was
primarily due to 2001 results had included only eight months of activity and due
to a $1.3 million increase in employee benefit expenses and administrative
expenses.
Depreciation and amortization expenses, excluding goodwill
amortization, for our interstate natural gas pipeline segment were $65.9 million
in 2003, $61.0 million in 2002 and $58.9 million in 2001. The increase between
2002 and 2003 is primarily due to Viking Gas Transmission. The increase between
2001 and 2002 reflects a $1.2 million increase in Northern Border Pipeline's
expense due to Project 2000 and a $0.9 million increase from Midwestern Gas
Transmission. Midwestern Gas Transmission's 2001 results had included only eight
months of activity.
Taxes other than income for our interstate natural gas pipeline segment
were $32.9 million, $29.2 million in 2002 and $26.1 million in 2001. The
increase in 2003 from 2002 is primarily due to Viking Gas Transmission expenses
of $2.5 million and a $1.2 million increase in Northern Border Pipeline's
expense. Northern Border Pipeline's 2002 expense reflected a refund of use taxes
previously paid on exempt purchases. The increase in 2002 from 2001 is primarily
due to a $2.8 million increase in Northern Border Pipeline's expense. Northern
Border Pipeline periodically reviews and adjusts its estimates of ad valorem
taxes. Reductions to previous estimates in 2001 exceeded reductions to previous
estimates in 2002 by approximately $2.1 million. Northern Border Pipeline's ad
valorem taxes also increased for 2002 due to the completion of Project 2000.
37
Interest expense for our interstate natural gas pipeline segment was
$47.6 million in 2003, $51.5 million in 2002 and $55.4 million in 2001. The 2003
expense included $2.7 million for Viking Gas Transmission. Northern Border
Pipeline's interest expense decreased in both 2003 and 2002 from prior year
levels due to a decrease in average interest rates as well as a decrease in
average debt outstanding.
Other income, net for our interstate natural gas pipeline segment was
$0.5 million in 2003 and $2.0 million in 2002 as compared to other expense of
$0.4 million in 2001. The decrease from 2002 to 2003 relates to a $0.6 million
expense for Northern Border Pipeline's repayment of amounts received in 2002 for
previously vacated microwave frequency bands. The 2001 amount included bad debt
expense of $1.5 million related to the bankruptcy of a telecommunications
company and an allowance for equity funds used during construction of $0.9
million related primarily to Northern Border Pipeline's Project 2000.
Equity earnings from unconsolidated affiliates for our interstate
natural gas pipeline segment were $2.0 million in 2003, which represents
earnings from our one-third interest in Guardian Pipeline.
Minority interests in net income, which represent the 30% minority
interest in Northern Border Pipeline, were $44.5 million for 2003, $42.8 million
for 2002 and $42.1 million for 2001. The increases in 2003 and 2002 from prior
year results were due to increased net income for Northern Border Pipeline.
Income tax expense for our interstate natural gas pipeline segment was
$3.6 million in 2003 and $0.7 million in 2002 as compared to an income tax
benefit of $0.4 million in 2001. The 2003 amount included Viking Gas
Transmission income taxes of $2.6 million. The remaining income tax amounts
relate to Midwestern Gas Transmission.
NATURAL GAS GATHERING AND PROCESSING
Our natural gas gathering and processing segment reported a loss from
continuing operations of ($177.9) million in 2003 and income from continuing
operations of $37.2 million in 2002. Excluding the impact of goodwill
amortization, the segment reported income from continuing operations of $31.2
million in 2001. The segment recorded impairment charges of $219.1 million in
2003 (see Note 4 - Notes to Consolidated Financial Statements, included
elsewhere in this report). Excluding the effect of the impairment charges, the
segment's income from continuing operations increased $4.0 million to $41.2
million between 2002 and 2003 primarily due to a $3.5 million increase in Border
Midstream Services's income from its Gregg Lake/Obed investment. The increase in
2002 earnings over the prior year resulted from our acquisitions made in 2001.
The 2001 results included nine months of activity for Bear Paw Energy and Border
Midstream Services.
Operating revenues for our natural gas gathering and processing segment
were $159.3 million in 2003, $126.6 million in 2002 and $111.3 million in 2001.
The increase in 2003 over 2002 is due to an increase in natural gas and natural
gas liquid prices, which accounted for $31.6 million of the overall increase,
partially offset by lower volumes gathered in the Powder River Basin, which
decreased revenues $3.9 million. The increase in operating revenues in 2002 over
2001 was
38
primarily due to the acquisitions made in 2001. The 2001 revenues for the
segment included only nine months of activity for Bear Paw Energy. Revenues for
2001 included $8.3 million recorded from gas gathering and administrative
services under a master services agreement with ENA that was terminated in 2001.
Product purchases for our natural gas gathering and processing segment
were $80.8 million in 2003, $50.6 million in 2002 and $39.7 million in 2001.
Under certain gathering and processing agreements, Bear Paw Energy purchases raw
natural gas from producers at a price tied to a percentage of the price for
which it sells extracted natural gas liquids and residue gas. Total revenues
from the sale of these products are included in operating revenues. Amounts paid
to the producers to purchase their raw natural gas are reflected in product
purchases. The increase in 2003 over 2002 is due to an increase in natural gas
and natural gas liquid prices. The increase in 2002 over 2001 was due to the
2001 results only including nine months of activity for Bear Paw Energy.
Operations and maintenance expenses for our natural gas gathering and
processing segment were $43.3 million in 2003, $38.2 million in 2002 and $39.6
million in 2001. Employee benefits expenses for 2003 increased $3.6 million as
compared to 2002, which included $1.5 million of charges associated with the
termination of Enron's cash balance plan. In 2001, the nine months of activity
for Bear Paw Energy included bad debt expense of $7.5 million related to ENA's
bankruptcy. See "The Impact of Enron's Chapter 11 Filing On Our Business" and
Item 13. "Certain Relationships and Related Transactions."
For our natural gas gathering and processing segment, depreciation and
amortization expenses, excluding the impairment charge recorded in 2003 and
goodwill amortization recorded in 2001, were $13.4 million in 2003, $12.1
million in 2002 and $7.7 million in 2001. As a result of the goodwill and asset
impairment analysis, we decided to shorten the useful life of our low-pressure
gas gathering assets in the Powder River Basis from 30 to 15 years, which
increased our depreciation expense by $0.6 million for this segment in 2003. We
expect our 2004 depreciation and amortization expense for this segment to
increase $1.8 million, as compared to 2003, due to the shorter useful lives. The
increase in 2002 expense over 2001 was due primarily to the 2001 results only
including nine months of activity for Bear Paw Energy.
Other income, net from our natural gas gathering and processing segment
was $5.6 million in 2003, $0.1 million in 2002 and $0.8 million in 2001. The
increase in other income for 2003 is primarily due a $3.3 million payment
received for a change in ownership of the other partner in Bighorn Gas
Gathering. Other income for 2001 included $0.7 million from a gain on sale of
gas processing assets and fees collected for gas well connections.
Equity earnings from our unconsolidated affiliates, excluding the
impact of goodwill amortization, were $16.8 million in 2003, $14.6 million in
2002 and $8.0 million in 2001. The 2003 equity earnings include $2.9 million
from a special income allocation related to a cash distribution from our
preferred A interest in Bighorn Gas Gathering. This distribution, determined in
accordance with a joint venture
39
agreement, was based on the number of wells connected to the gathering system in
the preceding year. If certain targets are not met, we receive a
disproportionate share of cash distributions. The increase in equity earnings in
2002 over 2001 was primarily due to an increase in gathering volumes and the
acquisitions made in 2001.
COAL SLURRY
Our coal slurry pipeline segment reported income of $3.7 million in
2003 on revenues of $21.4 million and $4.1 million in 2002 on revenues of $21.5
million. In 2001, excluding the impact of goodwill amortization, the segment
reported income of $4.9 million on revenues of $22.1 million. The coal slurry
segment income for 2003 was reduced by $0.4 million for a cumulative effect of
change in accounting principle, which resulted from adopting SFAS No. 143. The
2002 results were impacted by unplanned coal slurry discharges, which increased
operations and maintenance expense by $1.1 million over 2001. The 2001 results
included interest expense of $0.7 million associated with debt that was repaid
in June 2001.
OTHER
Items not attributable to any segment include certain of our general
and administrative expenses, interest expense on our debt, other income and
expense items and a loss on reacquired debt. Our general and administrative
expenses not allocated to any segment were $7.0 million in 2003, $5.5 million in
2002 and $3.1 million in 2001. The 2003 expense included $0.4 million for the
termination of the Enron cash balance plan and an increase in insurance expense
by $0.5 million due to an increase in liability premiums. The amount of general
and administrative expenses recorded in each year has increased due to our
acquisitions and due to additional common units issued, which increased our
unitholder tax return processing expenses.
Interest expense on our debt was $30.8 million in 2003, $30.6 million
in 2002 and $33.1 million in 2001. The decrease in expense for 2002 from 2001
was primarily due to a decrease in average interest rates partially offset by an
increase in average debt outstanding related to the acquisitions made in 2001.
Other expenses, net not allocated to any segment were $0.1 million in
2002 and $1.5 million in 2001. The amount for 2001 included a loss from debt
restructuring of $1.2 million related to the repayment of Black Mesa's 10.7%
Secured Senior Notes. The total repayment of approximately $13.6 million
consisted of remaining principal and interest of $12.4 million and an early
payment premium of $1.2 million.
LIQUIDITY AND CAPITAL RESOURCES
SUMMARY OF CERTAIN CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS
Payments Due by Period
--------------------------------------------
Less Than After
Total 1 Year 1-3 Years 4-5 Years 5 Years
---------- ------- --------- --------- -------
(In Thousands)
2002 Pipeline Senior
Notes due 2007 $ 225,000 $ -- $ -- $225,000 $ --
1999 Pipeline Senior
40
Notes due 2009 200,000 -- -- -- 200,000
2000 Partnership Senior
Notes due 2010 250,000 -- -- -- 250,000
2001 Partnership Senior
Notes due 2011 225,000 -- -- -- 225,000
2001 Pipeline Senior
Notes due 2021 250,000 -- -- -- 250,000
Viking Senior Notes
due 2008 to 2014 35,661 4,760 9,520 9,164 12,217
2002 Pipeline Credit
Agreement due 2005 131,000 -- 131,000 -- --
2003 Partnership Credit
Agreement due 2007 46,000 -- -- 46,000 --
Capital Leases (a) 6,610 3,348 3,262 -- --
Operating Leases (b) 26,608 8,035 8,513 6,132 3,928
Other Long-Term
Obligations (b) 72,915 11,656 23,247 23,279 14,733
---------- ------- -------- -------- --------
Total $1,468,794 $27,799 $175,542 $309,575 $955,878
========== ======= ======== ======== ========
(a) See Note 7 - Notes to Consolidated Financial Statements.
(b) See Note 11 - Notes to Consolidated Financial Statements.
We have guaranteed the performance of certain of our unconsolidated
affiliates in connection with their credit agreements that expire in March 2009
and September 2009. Collectively at December 31, 2003, the amount of both
guarantees was $4.4 million.
DEBT AND CREDIT FACILITIES AND ISSUANCE OF COMMON UNITS
Northern Border Pipeline and we have entered into revolving credit
facilities, which are used for refinancing existing indebtedness, capital
expenditures, acquisitions and general business purposes. Northern Border
Pipeline entered into a $175 million three-year credit agreement ("2002 Pipeline
Credit Agreement") with certain financial institutions in May 2002. We entered
into a $275 million four-year revolving credit agreement ("2003 Partnership
Credit Agreement") with certain financial institutions in November 2003. Both
credit agreements replaced prior credit agreements. At December 31, 2003, $131
million was outstanding under the 2002 Pipeline Credit Agreement at an average
interest rate of 1.95% and $46 million was outstanding under the 2003
Partnership Credit Agreement at an average interest rate of 2.67%.
In January 2004, TC PipeLines and the Partnership contributed $19.5
million and $45.5 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. In May 2004 and May 2007, Northern
Border Pipeline intends to issue additional equity cash calls to its partners
for $65 million and $90 million, respectively. We will be responsible for our
ownership share of each equity cash call (currently 70%).
The 2002 Pipeline Credit Agreement and 2003 Partnership Credit
Agreement require Northern Border Pipeline and us to maintain ratios of EBITDA
(net income plus minority interests in net income, interest expense, income
taxes and depreciation and amortization) to interest expense of greater than 3
to 1. The credit agreements also require the maintenance of the ratio of
indebtedness to adjusted EBITDA (EBITDA
41
adjusted for pro forma operating results of acquisitions made during the year)
of no more than 4.5 to 1. Under the 2003 Partnership Credit Agreement, if we
consummate one or more acquisitions in which the aggregate purchase price is $25
million or more, the allowable ratio of indebtedness to adjusted EBITDA is
temporarily increased to 5 to 1. At December 31, 2003, we were in compliance
with these covenants.
In April 2002, Northern Border Pipeline completed a private offering of
$225 million of 6.25% Senior Notes due 2007 ("2002 Pipeline Senior Notes"). In
September 2001, Northern Border Pipeline completed a private offering of $250
million of 7.50% Senior Notes due 2021 ("2001 Pipeline Senior Notes"). In August
1999, Northern Border Pipeline 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 Northern Border Pipeline may 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.
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. 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 Northern Border Pipeline's
interest rate swap agreements was 2.31%.
In March 2001, we completed a private offering of $225 million of 7.10%
Senior Notes due 2011 ("2001 Partnership Senior Notes"). In June 2000, we
completed a private offering of $150 million of 8 7/8% Senior Notes due 2010
("2000 Partnership Senior Notes") and in September 2000, we completed an
additional private offering of $100 million of 2000 Partnership Senior Notes.
The 2001 and 2000 Partnership Senior Notes were subsequently exchanged in
registered offerings for notes with substantially identical terms. The
indentures under which the 2001 and 2000 Partnership Senior Notes were issued do
not limit the amount of unsecured debt we may incur, but they do contain
material financial covenants, including restrictions on incurrence, assumption
or guarantee of secured indebtedness. The indentures also contain provisions
that would require us to offer to repurchase the 2001 and 2000 Partnership
Senior Notes, if either Standard & Poor's Rating Services or Moodys' Investor
Services, Inc. rate the notes below investment grade and the investment grade
rating is not reinstated for a period of 40 days. We used the proceeds from the
2001 and 2000 Partnership Senior Notes to fund our acquisitions in 2001 and
2000.
We currently have outstanding interest rate swap agreements with
notional amounts totaling $150 million that expire in March 2011. Under the
interest rate swap agreements, we make payments to counterparties at variable
rates based on the London Interbank Offered Rate and in return receives payments
based on a 7.10% fixed rate. The
42
swaps were entered into to hedge the fluctuations in the market value of the
2001 Partnership Senior Notes. At December 31, 2003, the average effective
interest rate on our interest rate swap agreements was 3.72%.
At December 31, 2003, Viking Gas Transmission has four series of senior
notes outstanding. Transportation service agreements have been pledged as
security for these senior notes. Viking Gas Transmission's senior notes
indenture provides for certain restrictions on the payment of cash dividends on
common stock. The most restrictive of these is that the payment of cash
dividends on common stock is prohibited unless debt service funds in an amount
equal to all scheduled payments of principal and interest for the 180-day period
following the current month end would remain on deposit following the dividend
payment. At December 31, 2003, the requirement for accumulation of debt service
funds prior to payment of dividends was $3.7 million.
In May and June 2003, we sold 2,250,000 and 337,500 common units,
respectively. In July 2002, we sold 2,186,700 common units. In April and May of
2001, we sold 407,550 and 4,000,000 common units, respectively. In conjunction
with the issuance of additional common units, our general partners are required
to make capital contributions to maintain a 2% general partner interest in
accordance with the partnership agreements. The net proceeds from the sale of
common units and the general partners' capital contributions totaled
approximately $102.2 million, $75.4 million and $172.2 million in 2003, 2002 and
2001, respectively, and were primarily used to repay indebtedness outstanding.
Short-term liquidity needs will be met by our operating cash flows and
through the 2003 Partnership Credit Agreement and the 2002 Pipeline Credit
Agreement. Long-term capital needs may be met through our ability to issue
long-term indebtedness as well as additional limited partner interests.
CASH FLOWS FROM OPERATING ACTIVITIES
Cash flows provided by operating activities were $224.7 million in
2003, $244.0 million in 2002 and $233.9 million in 2001. The decrease from 2002
to 2003 is primarily due to Northern Border Pipeline's refund to its shippers
for $10.3 million (see Note 5 - Notes to Consolidated Financial Statements,
included elsewhere in this report). Operating cash flows were also decreased due
to payments made to NBP Services and Northern Plains for administrative services
provided prior to 2003 and due to a reduction in prepayments in 2003 that
Northern Border Pipeline had required certain shippers make in 2002 for
transportation service. Distributions received from unconsolidated affiliates
increased $5.4 million to $16.3 million, primarily due to distributions received
from Bighorn Gas Gathering related to our preferred A interest discussed
previously. The increase from 2001 to 2002 reflects a $3.7 million increase in
distributions received from our unconsolidated affiliates and the prepayments
received by Northern Border Pipeline from certain shippers for transportation
service. During 2001, we realized net cash outflows of $4.7 million related to
Northern Border Pipeline's rate case, which included $2.1 million of amounts
collected subject to refund less refunds issued in early 2001 totaling $6.8
million.
43
CASH FLOWS FROM INVESTING ACTIVITIES
Cash used in investing activities was $116.7 million in 2003, $55.3
million in 2002 and $482.7 million in 2001. In 2003 and 2001, we spent higher
amounts primarily related to the acquisitions we made in both years and for
Northern Border Pipeline's Project 2000 facilities.
Our capital expenditures were $30.3 million in 2003, which included
$19.5 million for interstate natural gas pipeline facilities and $9.0 million
for natural gas gathering and processing facilities. For 2002, our capital
expenditures were $50.7 million, which included $33.7 million for natural gas
gathering and processing facilities and $16.5 million for interstate natural gas
pipelines facilities. For 2001, our capital expenditures were $126.4 million,
which included $69.1 million for gas gathering and processing facilities and
$57.0 million for interstate natural gas pipeline facilities. The 2001
expenditures for interstate natural gas pipeline facilities included $49.0
million for Northern Border Pipeline's Project 2000.
Our cash used in acquisitions was $123.2 million in 2003, as compared
to $1.6 million in 2002 and $345.1 million in 2001. In January 2003, we acquired
Viking Gas Transmission. In 2001, we acquired Midwestern Gas Transmission and
the assets of Border Midstream Services in April 2001 and Bear Paw Energy in
March 2001. The purchase of Bear Paw Energy also required us to issue 5.7
million common units valued at $183.0 million, for a total purchase price of
$381.7 million.
Sale of assets were $40.3 million in 2003 due to the sale of the Gladys
and Mazeppa processing plants discussed previously.
Our investments in unconsolidated affiliates were $3.5 million in 2003,
$3.0 million in 2002 and $11.2 million in 2001. The 2003 amount primarily
represents capital contributions to Guardian Pipeline while the 2002 and 2001
amounts primarily reflect capital contributions to Bighorn Gas Gathering.
Total capital expenditures for 2004 are estimated to be $29 million.
Capital expenditures for the interstate pipelines are estimated to be $19
million, including approximately $14 million for Northern Border Pipeline.
Northern Border Pipeline currently anticipates funding its 2004 capital
expenditures primarily by borrowing on its credit facility and using operating
cash flows. Capital expenditures for natural gas gathering and processing
facilities are estimated to be $9 million for 2004. Funds required to meet the
capital requirements for 2004 are anticipated to be provided from our credit
facility, issuance of additional limited partnership interests and operating
cash flows.
CASH FLOWS FROM FINANCING ACTIVITIES
Cash flows used in financing activities were $106.7 million for 2003
and $170.8 million for 2002, as compared to cash provided by financing
activities of $230.1 for 2001. Our cash distributions to our unitholders and our
general partners in 2003, 2002 and 2001 were $155.2 million, $147.0 million and
$120.9 million, respectively. The increase in 2003 over 2002 is due to an
increase in the number of common units outstanding. The increase in 2002 over
2001 results is due to both an increase in the number of common units
44
outstanding and an increase in the distribution rate. The distribution paid in
each quarter of 2003 and 2002 was $0.80 per unit as compared to $0.70 per unit
paid in the first quarter of 2001 and $0.7625 per unit paid in the second
quarter, third quarter and fourth quarter of 2001.
In 2003, 2002 and 2001, we issued additional partnership interests of
$102.2 million (2.6 million common units), $75.4 million (2.2 million common
units) and $172.2 million (4.4 million common units), respectively, which were
primarily used to repay indebtedness outstanding.
For 2003, our borrowings on long-term debt totaled $342.0 million,
which were primarily used for our acquisition of Viking Gas Transmission and to
repay previously existing indebtedness. Issuances of long-term debt included
borrowings under our credit agreements of $200.0 million and borrowings under
Northern Border Pipeline's credit agreement of $142.0 million. Total repayments
of debt in 2003 were $361.1 million.
For 2002, our borrowings on long-term debt totaled $499.9 million,
which were primarily used to repay previously existing indebtedness. Issuances
of long-term debt included net proceeds from the private offering of the 2002
Pipeline Senior Notes of approximately $223.5 million; borrowings under our
prior credit agreement of $68.0 million; and borrowings under Northern Border
Pipeline's credit agreements of $207.0 million. Total repayments of debt in 2002
were $567.5 million.
For 2001, our borrowings on long-term debt totaled $863.1 million,
which were used for both repayments of previously existing indebtedness and to
finance a portion of our acquisitions in March and April of 2001. Issuances of
long-term debt included net proceeds from the private offering of the 2001
Partnership Senior Notes of approximately $223.2 million; borrowings under our
prior credit agreement of $232.0 million; net proceeds from the issuance of the
2001 Pipeline Senior Notes of approximately $247.2 million; and borrowings under
Northern Border Pipeline's prior credit agreement of $136.0 million. The
proceeds from the 2001 Partnership Senior Notes and our prior credit agreement
were primarily used to fund the acquisitions of Bear Paw Energy, Canadian
midstream assets and Midwestern Gas Transmission discussed previously and to
repay indebtedness outstanding. Total repayments of debt were $604.9 million in
2001.
For the year ended December 31, 2001, Northern Border Pipeline
recognized a decrease in bank overdraft of $22.4 million. At December 31, 2000,
Northern Border Pipeline reflected the bank overdraft primarily due to rate
refund checks outstanding.
In March 2003, the Partnership received $12.3 million from the
termination of an interest rate swap agreement with a notional amount of $75
million. The proceeds were primarily used to repay existing indebtedness. In
2002, we agreed to an increase in the variable interest rate on two of our
interest rate swap agreements. As consideration for the change to the variable
interest rate, we received approximately $18.2 million, which represented the
fair value of the
45
financial instruments at the date of the adjustment. We used the proceeds to
repay amounts borrowed under our prior credit agreement. Also, in 2002, Northern
Border Pipeline received $2.4 million from the termination of forward starting
interest rate swap agreements. In March 2001, we paid approximately $4.3 million
to terminate forward starting interest rate swap agreements and in September
2001, Northern Border Pipeline paid approximately $4.1 million to terminate
interest rate swap agreements. The interest rate swaps had been entered into to
hedge the fluctuations in Treasury rates and spreads between the execution date
of the swaps and the issuance of fixed rate debt by Northern Border Pipeline and
us (see Note 8 - Notes to Consolidated Financial Statements).
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 the Company effective January 1, 2004. At
that time, cash distributions will be equal to 100% of distributable cash flow
as determined from the Company's financial statements based upon earnings before
interest, taxes, depreciation and amortization less interest expense and less
maintenance capital expenditures. Effective January 1, 2008, the cash
distribution policy will be adjusted to maintain a consistent capital structure.
NEW ACCOUNTING PRONOUNCEMENTS
In the third quarter of 2001, the Financial Accounting Standards Board
("FASB") 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," EITF No. 00-21 "Revenue Arrangements with Multiple
Deliverables," and Interpretation No. 46, "Consolidation of Variable Interest
Entities." See Note 13 - Notes to Consolidated 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.
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
46
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, Pan Border and NBP Services. 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 and NBP Services.
When the transfer of interests in Northern Plains, Pan Border and NBP
Services to CrossCountry as contemplated above takes place, the articles of
incorporation of Northern Plains, Pan Border and NBP Services will be amended to
reflect certain shareholder protections that will be retained by Enron until
distribution of any common stock of CrossCountry pursuant to the Chapter 11
Plan. Northern Plains and Pan Border, subject to applicable fiduciary duties
and/or contractual obligations, will need the affirmative vote of Enron to vote
its interest at the Partnership Policy Committee to, among other things, (a)
enter into any business other than owning and operating natural gas pipeline,
coal slurry pipelines, natural gas gathering facilities, midstream gas
processing facilities, gas and hydrocarbon liquids storage facilities and
related businesses; and (b) enter into any compromise or settlement of any
action, suit, litigation, arbitration proceeding or any governmental
investigation or audit relating to the assets, liabilities or business of the
entities or the Partnership in excess of $2 million.
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. NBP Services Corporation, a
wholly owned subsidiary of Enron that is not in
47
bankruptcy, and Northern Plains provided and continue to provide operating and
administrative services for us and our subsidiaries. Northern Plains and NBP
Services have continued to meet their operational and administrative service
obligations under the existing agreements, and we believe they 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
Northern Border Pipeline's capacity. Through the proceeding in 2002, ENA
rejected and terminated all of its contracts on Northern Border Pipeline.
Northern Border Pipeline filed claims against ENA for damages for breach of
contract and other claims. ENA was also a party to a transportation contract for
capacity on Midwestern Gas Transmission. ENA rejected and terminated this
contract in November 2003. Midwestern Gas Transmission filed claims against ENA
for breach of contract and other claims.
In addition, Bear Paw Energy filed claims against ENA relating to
terminated swap agreements. In accordance with SFAS No. 133, Bear Paw Energy
ceased to account for these swap agreements as hedge transactions. Bear Paw
Energy had previously recorded approximately $6.7 million in accumulated other
comprehensive income related to these agreements, which is being recorded into
earnings in the same periods of the originally forecasted hedges. In 2003, Bear
Paw Energy recorded approximately $0.3 million in earnings related to the
terminated hedges.
Also, Crestone Energy Ventures filed claims against ENA for unpaid gas
gathering and administrative services fees.
The claims against Enron and ENA referenced above are unsecured claims.
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 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 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 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
48
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 and NBP Services 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 and NBP Services have advised us that each is a
member of the ERISA 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 $6.2 million has been estimated for our share of
Northern Plains' and NBP Services' proportionate share of the up to $200 million
estimated termination costs authorized by the Bankruptcy Court order. Under the
operating agreements with Northern Plains and the administrative services
agreement with NBP Services, these increased costs may be our responsibility. We
have accrued the amount of $6.2 million 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 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 lawsuit 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 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 the Partnership has not been subject to
49
these investigations or lawsuits, it is possible that in the documentation
production by Enron and others, confidential proprietary or commercially
sensitive information concerning the Partnership may have been produced. It is
also possible that some of this information may be made available to the public.
While Northern Plains, Pan Border and NBP Services 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 three member policy committee, with one member
appointed by each general partner. The vote of each member of the policy
committee is weighted by the general partner percentage of the general partner
appointing such member. The general partner percentages for Northern Plains, Pan
Border and Northwest Border are 50%, 32.5% and 17.5%, 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 policy committee and control the
activities of the Partnership. The 2003 Partnership Credit Agreement provides
that it would be a change of control (and consequently an event of default)
thereunder if subsidiaries of Enron, CrossCountry and/or TransCanada PipeLines
Limited do not control, free of any liens, greater than 50% of the general
partner percentages. Consequently, if Enron sells the stock of Northern Plains
and Pan Border or CrossCountry to a third party, a waiver under the 2003
Partnership Credit Agreement would need to be obtained. In addition, the
agreements evidencing the Partnership's other material outstanding debt
obligations provide that an uncured default under one material debt agreement
will result in a default under other debt agreements.
Northern Plains also serves as operator of Northern Border Pipeline. If
Northern Plains were to file for bankruptcy relief, it could potentially be
removed as operator. Certain of Northern Border Pipeline's credit agreements
provide that it would be an event of default thereunder if Northern Plains were
replaced as operator without the consent of the lenders thereunder.
The Administrative Services Agreement between NBP Services and us
provides that it will terminate at such time as Northern Plains is no longer a
general partner of the Partnership. Consequently, since our Partnership
Agreement provides that a general partner is automatically withdrawn as general
partner upon filing of bankruptcy, if Northern Plains were to file for
bankruptcy relief, the Administrative Services Agreement would be terminated.
Our Partnership Agreement requires that each general partner make
additional capital contributions to us when we sell common units. Enron may
determine that it is not in the best interest of its creditors and other
constituencies in bankruptcy to make these capital contributions to Northern
Plains and Pan Border. Enron could therefore decide not to allow us to pursue
acquisitions financed with the issuance of additional common units. Even if
Enron were to permit the
50
general partners to make a capital contribution to us, if the general partners
were to subsequently file for bankruptcy relief, the capital contribution might
be subject to challenge as voidable under applicable law.
Other than the items set forth above, we are not 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 two of our general partners, 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"). 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
51
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 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 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
52
- 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 customer'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, Northern Border Pipeline's operator,
and NBP Services, administrator for us, are wholly-owned
subsidiaries of Enron and depend on Enron and certain of its
affiliates for some services they provide to us, potential
further developments in the Enron Chapter 11 proceeding may
cause either or both Northern Plains and NBP Services to be
unable to perform under their agreements 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
Voluntary Employee Benefit Trust. Also, Enron announced its
intention to create a new pipeline operating entity, which
will include Northern Plains, Pan Border and NBP Services. See
"The Impact Of Enron's Chapter 11 Filing On Our Business"
above.
- Contracts on our interstate pipelines will expire prior to
November 1, 2004. On Northern Border Pipeline, those contracts
represent approximately 30% of its system capacity. The
interstate pipelines' 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 system. See "Overview" above and Item 1. "Business -
Interstate Pipelines - Demand For Transportation Capacity."
- Our interstate pipelines are subject to extensive regulation
by the FERC governing all aspects of our business, including
our transportation rates. Under Northern Border Pipeline's
1999 rate case settlement, neither Northern Border Pipeline
nor its existing customers can seek rate changes until
November 2005, at which time Northern Border Pipeline is
obligated to file a rate case. We cannot predict what
53
challenges our interstate pipelines may have to their rates in
the future. See Item 1. "Business - Interstate Pipelines -
FERC Regulation."
- In a rate case proceeding setting the maximum rates that may
be charged, our 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, each of these pipelines must
maintain or increase its rate base through projects that
maintain or add to existing pipeline facilities and/or
increase its rate of return.
- Conflicts of interest may arise between our general partners
and their affiliates on one hand, and us on the other hand. As
a result of these conflicts, the general partners may favor
their own interests and the interests of their affiliates over
the interests of our limited partners.
- We face competition from third parties in our natural gas
transportation, gathering and processing businesses. See Item
1. "Business - Interstate Pipeline Competition" and "Business
- Interstate Pipelines-Future Demand and Competition."
- 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."
- Northern Border Pipeline's ability to operate its pipeline on
certain tribal lands will depend on Northern Border Pipeline's
success in renegotiating before 2011 its right-of-way rights
on tribal lands within the Fort Peck Reservation. See Item 2.
"Properties." Northern Border Pipeline 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 the settlement is not finalized or if
Northern Border Pipeline is unable to recover the costs of the
proposed settlement in its future rates, it could have a
material adverse impact on our results of operation.
- Black Mesa's contract to transport coal slurry terminates in
December 2005. If Black Mesa is unable to extend or enter into
a new arrangement for transportation of coal slurry, Black
Mesa could incur costs and expenses for employee related
matters, a write-off of recorded goodwill and removal of
certain facilities. See Item 1. "Business, Coal Slurry
Pipeline" and "Overview" above.
54
- Part of our business strategy is to expand existing assets and
acquire additional assets and businesses that will allow us to
increase our cash flow and distributions to unitholders.
Unexpected costs or challenges may arise whenever we acquire
new assets or businesses. Successful acquisitions require
management and other personnel to devote significant amounts
of time to new businesses or integrating the acquired assets
with existing businesses.
- Our ability to maintain and/or expand our midstream gas
gathering business will depend in large part on the pace of
drilling and production activity in the western Canadian
sedimentary, Powder River, Wind River and Williston Basins.
Drilling and production activity will be impacted by a number
of factors beyond our control, including demand for and prices
of natural gas and refinery grade crude oil, producer response
to the recently issued EIS, reserve performance, the ability
of producers to obtain necessary permits and capacity
constraints on natural gas transmission pipelines that
transport gas from the producing areas. See Item 1. "Business
- Natural Gas Gathering and Processing Segment - Future Demand
and Competition."
- Our financial performance will depend on our ability to
successfully restructure certain gathering contracts to
improve revenues, reduce operating expenditures and reduce
volume and capital recovery risks in the Powder River Basin
operations.
- Initiatives by states to regulate the rates that we charge for
our gathering and processing of natural gas and/or to assess
taxes on certain aspects of our gas gathering and processing
and interstate pipeline businesses may adversely impact us.
- The impact of changing quality of natural gas received into
our gathering and processing facilities may adversely affect
our revenues and operations. In particular, the energy content
of our gathered Powder River Basin production exhibited a
decline of approximately 2% during 2003 to approximately 940
Btu/cubic foot. Most natural gas quality standards of
interstate pipelines require a minimum of 950 Btu/cubic foot.
If we are unable to blend customers' gas, additional treatment
may be necessary to avoid curtailment of certain volumes.
- Although our business strategy is to pursue fee-based and
fixed-rate contracts, some of our gas processing facilities
are subject to certain contracts that give us quantities of
natural gas liquids as payment of our processing services. The
income and cash flow from these contracts will be impacted
directly by changes in these commodity prices. See Item 7A.
"Quantitative and Qualitative Disclosures About Market Risk"
below.
55
- We may need new capital to finance future acquisitions and
expansions. If our access to capital is limited, this will
impair our ability to execute our growth strategy. Enron's
circumstances have caused the credit rating agencies to review
the capital structure and earnings power of energy companies,
including us. As we acquire new businesses and make additional
investments in existing businesses, we may need to increase
borrowings and issue additional equity in order to maintain an
appropriate capital structure. This may be dilutive to our
unitholders and impact the market value of our common units.
See "Debt and Credit Facilities and Issuance of Common Units"
above.
- Our indentures contain provisions that would require us to
offer to repurchase our Senior Notes if Moodys or Standard &
Poor's rating services rate our notes below investment grade.
See "Debt and Credit Facilities and Issuance of Common Units"
above.
- We may be adversely impacted by the potential enactment of
legislation in various states to modify existing provisions
for income tax withholding on partners' distributions.
- Under current law, we are treated as a partnership for federal
income tax purposes and do not pay any income tax at the
entity level. In order to qualify for this treatment, we must
derive more than 90% of our annual gross income from specified
investments and activities. While we believe that we currently
do qualify and intend to meet this income requirement, if we
should fail we would be treated as if we were a newly formed
corporation and the income we generate from the date of such
failure would be subject to corporate income tax. Because the
tax would be imposed on us, the cash available for
distribution to our unitholders would be substantially
reduced. In addition, the entire amount of cash received by
each unitholder would generally be taxed as a corporate
dividend when received.
- In addition, because of widespread state budget deficits,
several states are evaluating ways to subject partnerships to
entity-level taxation through the imposition of state income,
franchise or other forms of taxation. If any state were to
impose a tax upon us as an entity, the cash available to pay
distributions would be reduced. The partnership agreement
provides that, if a law is enacted or existing law is modified
or interpreted in a manner that subjects us to taxation as a
corporation or otherwise subjects us to entity-level taxation
for federal, state or local income tax purposes, then the
minimum quarterly distribution and the target distribution
levels will be decreased to reflect that impact on us.
Additional risks and uncertainties not currently known to us, or risks
that we currently deem immaterial may impair our business operations. Any of the
risk factors described above could significantly and adversely impair our
operating results.
ITEM 7a. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
56
We may be exposed to market risk through changes in commodity prices,
exchange rates and interest rates as discussed below. A control environment has
been established which includes policies and procedures for risk assessment and
the approval, reporting and monitoring of financial instrument activities.
We have utilized and expect to continue to utilize financial
instruments in the management of interest rate risks and our natural gas and
natural gas liquids marketing activities to achieve a more predictable cash flow
by reducing our exposure to interest rate and price fluctuations. Other than
entering into a forward purchase of Canadian dollars in 2001 to fund our
acquisition of the Canadian midstream assets, we have not used financial
instruments in the management of exchange rates.
INTEREST RATE RISK
Our interest rate exposure results from variable rate borrowings from
commercial banks. To mitigate potential fluctuations in interest rates, we
attempt to maintain a significant portion of our consolidated debt portfolio in
fixed rate debt. We also use interest rate swaps as a means to manage interest
expense by converting a portion of fixed rate debt to variable rate debt to take
advantage of declining interest rates. At December 31, 2003, we had $552.0
million of variable rate debt outstanding, $375.0 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 7 and Note 8 to our
Consolidated Financial Statements, included elsewhere in this report. As of
December 31, 2003, approximately 59% 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, consolidated annual interest expense would
change by approximately $5.5 million. This amount has been determined by
considering the impact of the hypothetical interest rates on our variable rate
borrowings outstanding as of December 31, 2003.
COMMODITY PRICE RISK
Bear Paw Energy is subject to certain contracts that give it quantities
of natural gas and natural gas liquids as partial consideration for processing
services. The income and cash flows from these contracts will be impacted by
changes in prices for these commodities. Prior to considering the effects of any
hedging, for each $0.10 per million British thermal unit change in natural gas
prices or for each $0.01 per gallon change in natural gas liquid prices, our
annual net income would change by approximately $0.3 million. This amount has
been determined by considering the impact of the hypothetical commodity prices
on our projected gathering and processing volumes for 2004. We have hedged 45%
to 50% of our commodity price risk in 2004.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required hereunder is included in this report as
57
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 9A. CONTROLS AND PROCEDURES
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, the principal executive officer and principal
financial officer 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.
58
PART III
ITEM 10. PARTNERSHIP MANAGEMENT
We are managed under the direction of the Partnership Policy Committee
consisting of three members, each of which has been appointed by one of our
general partners. The members appointed by Northern Plains, Pan Border and
Northwest Border have 50%, 32.5% and 17.5%, respectively, of the voting power.
We also have an audit committee comprised of individuals who are
neither officers nor employees of any general partner or any affiliate of a
general partner, to serve as a committee of the Partnership (the "Audit
Committee"). The Audit Committee members are not members of, and do not vote on
matters, submitted to the Partnership Policy Committee. The Partnership Policy
Committee has delegated to the Audit Committee oversight responsibility with
respect to the integrity of our financial statements, the performance of our
internal audit function, the independent auditor's qualification and
independence and compliance with legal and regulatory requirements. The Audit
Committee directly appoints, retains, evaluates and may terminate our
independent auditors. The Audit Committee reviews the annual financial
statements and resolves, if necessary, any significant disputes between
management and the independent auditor that arise in connection with the
preparation of the financial statements. The Audit Committee also has the
authority to review, at the request of a general partner, specific matters as to
which a general partner believes there may be a conflict of interest in order to
determine if the resolution of such conflict proposed by the Partnership Policy
Committee is fair and reasonable to us.
As is commonly the case with publicly-traded partnerships, we do not
directly employ any of the persons responsible for managing or operating the
Partnership or for providing it with services relating to its day-to-day
business affairs. We have entered into an Administrative Services Agreement with
NBP Services a wholly-owned subsidiary of Enron that has not filed for
bankruptcy protection, pursuant to which NBP Services provides tax, accounting,
legal, cash management, investor relations, operating and other services for the
Partnership. NBP Services has approximately 135 employees. It also uses
employees of Enron or its affiliates who have duties and responsibilities other
than those relating to the Administrative Services Agreement. In consideration
for its services under the Administrative Services Agreement, NBP Services is
reimbursed for its direct and indirect costs and expenses, including an
allocated portion of employee time and Enron's overhead costs. See Item 13.
"Certain Relationships and Related Transactions."
Set forth below is certain information concerning the members of the
Partnership Policy Committee, our representatives on the Northern Border
Management Committee and the persons designated by the Partnership Policy
Committee as our executive officers and as Audit Committee members. All members
of the Partnership Policy Committee and our representatives on the Northern
Border Management Committee serve at the discretion of the general partner that
appointed them. The persons designated as executive officers serve in that
capacity at the discretion of the Partnership Policy Committee. The members of
the Partnership Policy Committee receive no management fee or other remuneration
for serving on this committee. The Audit Committee members are elected, and may
be removed, by the Partnership Policy Committee. On March 4, 2004, the Policy
Committee appointed Gerald
59
B. Smith as the Chairman of the Audit Committee. Also, the Policy Committee
determined that all of the Audit Committee members are financial experts and
that they are independent. The Chairman of the Audit Committee receives an
annual fee of $50,000 and other Audit Committee members receive an annual fee of
$40,000 and each is paid $1,500 for each meeting attended. Effective September
2003, Paul E. Miller was designated by TransCanada as its member on the
Partnership Policy Committee and one of our representatives on the Northern
Border Management Committee, replacing Paul MacGregor. There are no family
relationships between any of our executive officers or members of the
Partnership Policy and Audit Committees.
60
NAME AGE POSITIONS
---- --- ---------
Executive Officers:
William R. Cordes 55 Chief Executive Officer
Jerry L. Peters 46 Chief Financial and Accounting Officer
Members of Partnership Policy
Committee and Partnership's
representatives on Northern
Border Management Committee:
William R. Cordes 55 Chairman
Stanley C. Horton 54 Member
Paul E. Miller 45 Member
Members of Audit Committee:
Gerald B. Smith 53 Chairman
Daniel P. Whitty 72 Member
Gary N. Petersen 52 Member
William R. Cordes was named Chief Executive Officer of the Partnership
and Chairman of the Partnership Policy Committee in October 2000. Mr. Cordes is
the President of Northern Plains, an Enron subsidiary, having been appointed to
that position on October 1, 2000, and is a director of Northern Plains. Mr.
Cordes was named Chairman of the Northern Border Management Committee October 1,
2000. In 1970, he started his career with 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 President of
Transwestern Pipeline, a subsidiary of Enron.
Stanley C. Horton was appointed to the Partnership Policy Committee and
to the Northern Border 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 the Chairman, President and Chief
Executive Officer of NBP Services 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 to November 2001, 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:
61
Calypso Pipeline, L.L.C. (Director, President and Chief Executive
Officer)
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, TransCanada designated Paul E. Miller as its member
on the Partnership Policy Committee. Mr. Miller is also a representative on the
Northern Border 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.
Jerry L. Peters was named Chief Financial and Accounting Officer in
July 1994. Mr. Peters has held several management positions with Northern Plains
since 1985 and was elected Vice President of Finance in July 1994, director in
August 1994 and Treasurer in October 1998. Mr. Peters was also Vice President,
Finance of: Florida Gas Transmission Company from February 2001 to May 2002;
Transportation Trading Services Company from September 2001 to July 2002; Citrus
Corp. from October 2001 to July 2002; and Transwestern Pipeline Company from
November 2001 to May 2002. Prior to joining Northern Plains in 1985, Mr. Peters
was employed as a Certified Public Accountant by KPMG LLP.
62
Gerald B. Smith was appointed to the Audit Committee in April 1994. He
is Chairman and Chief Executive Officer and co-founder of Smith, Graham &
Company Investment Advisors, a global investment management firm, which was
founded in 1990. He is a member of the Board of Trustees of Charles Schwab
Family of Fund; a director and member of the audit committee of Cooper
Industries; and a director of the Fund Management Board of Robeco Group,Rorento
N.V. (Netherlands). He served as a director of Pennzoil-Quaker States and was a
member of the Audit Committee and Executive Committee of its board until October
2002.
Daniel P. Whitty was appointed to the Audit Committee in December 1993.
Mr. Whitty is an independent financial consultant. He has served as a member of
the Board of Directors of Methodist Retirement Communities Inc., and a Trustee
of the Methodist Retirement Trust. Mr. Whitty was a partner at Arthur Andersen
LLP ("Andersen") until his retirement on January 31, 1988. At Andersen, he had
firm wide responsibility for the natural gas transmission industry for many
years. Until his resignation in December 2001, Mr. Whitty served as a director
of EOTT Energy Corp., a subsidiary of Enron and the general partner of EOTT
Energy Partners, L.P. EOTT Energy Corp. filed for bankruptcy protection on
October 21, 2002.
Gary N. Petersen was appointed to the Audit Committee on March 19,
2002. Since 1998, he has provided consulting services related to strategic and
financial planning. Additionally, he is currently the President of Endres
Processing LLC. From 1977 to 1998, Mr. Petersen was employed by Reliant
Energy-Minnegasco. He served as Reliant Energy-Minnegasco's President and Chief
Operating Officer from 1991 to 1998. Prior to his employment at Minnegasco, he
was a senior auditor with Andersen. He currently serves on the boards of the
YMCA of Metropolitan Minneapolis and the Dunwoody Institute.
Also at the meeting of the Partnership Policy Committee on March 4,
2004, the following persons were deemed to be officers for purposes of Section
16 of the Securities Exchange Act of 1934.
Some of these individuals are officers at certain subsidiaries of the
Partnership:
NAME AGE POSITIONS
---- --- ---------
Vice President of Marketing, Interstate
Paul F. Miller 37 Pipelines
Vice President, Regulatory Affairs and Market
Raymond D. Neppl 59 Services, Interstate Pipelines
Vice President, General Counsel and Assistant
Janet K. Place 55 Secretary
Randy K. Rice 46 Vice President, Operations, Interstate Pipelines
Vice President, Business Development and Strategic
Gaye Lynn Schaffart 44 Planning
Pierce H. Norton 44 President, Bear Paw Energy, LLC
Fred G. Rimington 53 President, Black Mesa Pipeline, Inc.
63
Paul F. Miller is Vice President of Marketing, Interstate Pipelines of
Northern Plains, having been elected in March 2002. Mr. Miller was previously
Account Executive, Marketing from December 1998 until August 2000, when he was
promoted to Director, Marketing. Mr. Miller joined Northern Plains in 1990.
Raymond D. Neppl is Vice President, Regulatory Affairs and Market
Services, a position he has held since July 1994. Mr. Neppl was previously Vice
President of Regulatory Affairs from 1991-1994. Mr Neppl joined Northern Natural
Gas Company, formerly affiliated with Northern Plains, in 1975 and transferred
to Northern Plains in 1981.
Janet K. Place is Vice President, General Counsel and Assistant
Secretary of Northern Plains, having been elected in August 1994. In 1993, Ms.
Place was named General Counsel. Ms. Place joined Northern Plains in 1980 as an
Attorney.
Randy K. Rice is Vice President, Operations for Northern Plains, having
been elected in March 2002. Mr. Rice was previously Vice President of North
Operations for a division of Enron from 2001 to 2002, and from 1999 to 2001,
held various management positions within the operations division supporting
various pipeline assets owned by Enron. Mr. Rice joined Northern Natural Gas
Company, formerly affiliated with Northern Plains, in 1980.
Gaye Lynn Schaffart is Vice President, Business Development and
Strategic Planning, having been elected in March 2004. Ms. Schaffart was
previously Director, Business Development and Planning from 1993 to 2004. Ms.
Schaffart joined Northern Plains in 1982.
Pierce H. Norton is President of Bear Paw Energy, LLC, a subsidiary of
Northern Border, having been appointed in February 2003. Mr. Norton, from 2001
to 2003 served as Vice President, Business Development for Bear Paw. Prior to
the Company's purchase of Bear Paw, Mr. Norton was Vice President -- Business
Development for Bear Paw Energy, LLC and its predecessor from 1999 to 2001 where
he was responsible for managing contracts and asset acquisitions.
Fred G. Rimington is President of Black Mesa Pipeline, Inc., having
been appointed in January 2000. Mr. Rimington was Director, Business Development
from 1994 to 1999 for Northern Plains. Mr. Rimington joined Northern Plains in
1980.
SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
Section 16(a) of the Securities Exchange Act of 1934 requires executive
officers, members of the Partnership Policy Committee and persons who own more
than ten percent of a registered class of the equity securities issued by us to
file reports of ownership and changes in ownership with the SEC and the New York
Stock Exchange and to furnish the Partnership with copies of all Section 16(a)
forms they file. Based solely on our review of the copies of such reports
received by us, or written representations from certain reporting persons that
no Form 5's were required for those persons, we believe that during 2003 our
reporting persons complied with all applicable filing requirements in a timely
manner.
64
CODE OF ETHICS
We have adopted an Accounting and Financial Reporting Code of Ethics
applicable to the Partnership's chief executive officer and chief financial and
accounting officer. A copy of the Accounting and Financial Reporting Code of
Ethics is posted on our website, www.northernborderpartners.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.
65
ITEM 11. EXECUTIVE COMPENSATION
The following table summarizes certain information regarding
compensation paid or accrued during each of Northern Plains' last three fiscal
years to the executive officers of the Partnership (the "Named Officers") for
services performed in their capacities as executive officers of Northern Plains:
SUMMARY COMPENSATION TABLE
All Other
Annual Compensation Long-Term Compensation Compensation
Securities
Restricted Underlying
Other Annual Stock Awards Options / SARs LTIP Payouts
Name & Position Year Salary Bonus (1) Compensation ($)(3)(4) (#) ($) (5) ($) (6)
--------------- ---- -------- -------- ------------ -------- ----- -------- --------
(2)
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 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 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 includes 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
66
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
Shares Options/SARs at In-the-Money Options/SARs
Acquired on Value December 31, 2003 December 31, 2003 (1)
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. 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
67
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, with 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' and NBP Services' 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.
68
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
OWNERS AND MANAGEMENT
The following table sets forth the beneficial ownership of the voting
securities of the Partnership as of March 3, 2004 by our executive officers,
members of the Partnership Policy Committee and the Audit Committee who own
units and by certain beneficial owners. Other than as set forth below, no person
is known by the general partners to own beneficially more than 5% of the voting
securities.
Amount and Nature of Beneficial Ownership
Common Units
------------
Number Percent
of Units/ of Class
-------- --------
William R. Cordes 1/ 1,000 *
13710 FNB Parkway Omaha, NE 68154-5200
Jerry L. Peters 1/ 1,000 *
13710 FNB Parkway Omaha, NE 68154-5200
Stanley C. Horton 1/ 20,000 *
1331 Lamar Street
Houston, TX 77010
Gary N. Petersen 5,854 *
3520 Wedgewood Ln. N
Plymouth, MN 55441-2262
Enron Corp.2/ 3,210,000 6.9
1331 Lamar Street
Houston, TX 77010
- ---------------------
* Less than 1%.
1/ All units involve sole voting and investment power.
2/Indirect ownership through its subsidiaries. Northern Plains is the beneficial
owner of 500,000 Common Units. Sundance Assets, L.P. is the beneficial owner of
2,710,000. In a Schedule 13D/A filing in January 2002, it was disclosed that
dispositive power of Sundance Assets, L.P. is shared by Enron and Citibank, N.A.
For information on equity compensation plans of the Partnership, see
Item 5. "Market for Registrant's Common Units and Related Securities Holder
Matters."
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
On December 2, 2001, Enron and certain of its subsidiaries filed
voluntary petitions for Chapter 11 reorganization under the Bankruptcy Code. We
have a number of relationships with Enron and its subsidiaries. Through
69
Enron's ownership of two of our general partners, Enron is able to elect members
with a majority of the voting power on the Partnership Policy Committee and
Northern Border Pipeline Management Committee. Such other relationships include
the following:
- Northern Plains, a subsidiary of Enron, provides certain
administrative, operating and management services to the
Partnership through Operating Agreements with Northern Border
Pipeline, Midwestern Gas Transmission and Viking Gas
Transmission. For the year ended December 31, 2003, the
aggregate amount charged by Northern Plains for its services
was approximately $38.5 million.
- NBP Services, a subsidiary of Enron, provides the Partnership
services in connection with the operation and management of
the Partnership and operating services for Crestone Energy
Ventures and Bear Paw Energy pursuant to the terms of an
Administrative Services Agreement between the Partnership and
NBP Services. For the year ended December 31, 2003, the
aggregate amount charged by NBP Services for its services was
approximately $16.2 million.
- ENA held a contract for firm transportation on Midwestern Gas
Transmission until it was rejected and terminated on November
12, 2003.
- Northern Plains, has been selected on a fixed fee and cost
reimbursement basis to provide, commencing on July 1, 2004,
certain administrative, operating and management services
through an Operating Agreement with Guardian Pipeline, L.L.C.,
of which we own a one third interest. The annual amount of the
fixed fee to be charged by Northern Plains for its services is
$3.6 million. Guardian Pipeline, L.L.C. has agreed to
reimburse up to $800,000 of certain of Northern Plains' costs
associated with the transition of the role of operator of
Guardian Pipeline from Trunkline Gas Company to Northern
Plains and has agreed to compensate Northern Plains for any
services provided to Guardian Pipeline prior to July 1, 2004.
- In conjunction with the selection of Northern Plains, as
operator of Guardian Pipeline, L.L.C., we agreed to contract
with Northern Plains to assume the financial risks and
benefits resulting from and arising out of Northern Plains'
responsibilities and obligations as operator of Guardian
Pipeline.
- 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."
The Partnership Policy Committee, whose members are designated by our
three general partners, establishes the business policies of the Partnership. We
have three representatives on the Northern Border Management Committee, each of
whom votes a portion of our 70% interest on the Northern Border Management
Committee, with the other 30% interest being voted by a representative of TC
PipeLines, which is an affiliate of one of our general partners.
Our general partners (subsidiaries of Enron and a subsidiary of
TransCanada) and their respective affiliates, currently actively engage or may
engage in the businesses in which we engage or in which we may engage in the
future. As a result, conflicts of interest may arise between our general
partners and their affiliates on the one hand, and the Partnership on the other
hand. In such case the members of the Partnership Policy Committee
70
will generally have a fiduciary duty to resolve such conflicts in a manner that
is in our best interest.
Enron (the parent of two of our general partners) and its affiliates
and TC PipeLines (a 30% owner of Northern Border Pipeline whose general partner
is an affiliate of one of our general partners) and its affiliates also actively
engage in interstate pipeline transportation of natural gas in the United States
separate from their interests in Northern Border Pipeline. As a result,
conflicts also may arise between Enron and its affiliates, TransCanada and its
affiliates or TC PipeLines and its affiliates, on the one hand, and the Northern
Border Pipeline on the other hand. If such conflicts arise, the representatives
on the Northern Border Pipeline Management Committee will generally have a
fiduciary duty to resolve such conflicts in a manner that is in the best
interest of Northern Border Pipeline.
Unless otherwise provided for in a partnership agreement, the laws of
Delaware and Texas generally require a general partner of a partnership to
adhere to fiduciary duty standards under which it owes its partners the highest
duties of good faith, fairness and loyalty. Similar rules apply to persons
serving on the Partnership Policy Committee or the Northern Border Management
Committee. Because of the competing interests identified above, our Partnership
Agreement and the partnership agreement for Northern Border Pipeline contain
provisions that modify certain of these fiduciary duties. For example:
- Our Partnership Agreement states that our general partners,
their affiliates and their officers and directors will not be
liable for damages to us, our limited partners or their
assignees for errors of judgment or for any acts or omissions
if the general partners and such other persons acted in good
faith.
- Our Partnership Agreement allows our general partners and our
Partnership Policy Committee to take into account the
interests of parties in addition to our interest in resolving
conflicts of interest.
- Our Partnership Agreement provides that the general partners
will not be in breach of their obligations under our
Partnership Agreement or their duties to us or our unitholders
if the resolution of a conflict is fair and reasonable to us.
The latitude given in our Partnership Agreement in connection
with resolving conflicts of interest may significantly limit
the ability of a unitholder to challenge what might otherwise
be a breach of fiduciary duty.
- Our Partnership Agreement provides that a purchaser of Common
Units is deemed to have consented to certain conflicts of
interest and actions of the general partners and their
affiliates that might otherwise be prohibited and to have
agreed that such conflicts of interest and actions do not
constitute a breach by the general partners of any duty stated
or implied by law or equity.
- Our Audit Committee will, at the request of a general partner
or a member of the Partnership Policy Committee, review
conflicts of interest that may arise between a general partner
and its affiliates (or the member of the
71
Partnership Policy Committee designated by it), on the one
hand, and the unitholders or us, on the other. Any resolution
of a conflict approved by the Audit Committee is conclusively
deemed fair and reasonable to us.
- We entered into an amendment to the partnership agreement of
Northern Border Pipeline that relieves us and TC PipeLines,
their affiliates and their transferees from any duty to offer
business opportunities to Northern Border Pipeline, subject to
specified exceptions.
We are required to indemnify the members of the Partnership Policy
Committee and general partners, their affiliates and their respective officers,
directors, employees, agents and trustees to the fullest extent permitted by law
against liabilities, costs and expenses incurred by any such person who acted in
good faith and in a manner reasonably believed to be in, or (in the case of a
person other than one of the general partners) not opposed to, our best
interests and with respect to any criminal proceedings, had no reasonable cause
to believe the conduct was unlawful.
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) $ 323,050 $ 644,850
Audit-related fees(2) $ 107,995 $ 800
Tax Fees(3) $ 855 $ 10,425
Other $ 0 $ 0
Total $ 431,900 $ 656,075
(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 Securities and Exchange
Commission. The fees for 2002 also include professional 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.
Our Audit Committee is responsible for reviewing and approving, in
advance, any audit and permissible non-audit engagement or relationship between
us and our independent auditors. KPMG's engagement to conduct our audit was
approved by the Audit Committee on November 7, 2002. Additionally, all
permissible non-audit engagements with KPMG have been reviewed and approved by
the Audit Committee pursuant to procedures established by the Audit Committee.
72
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 Form of Amended and Restated Agreement of Limited
Partnership of Northern Border Partners, L.P.
(Exhibit 3.1 No. 2 to the Partnership's Form S-1
Registration Statement, Registration No. 33-66158
("Form S-1")).
*3.2 Form of Amended and Restated Agreement of Limited
Partnership For Northern Border Intermediate Limited
Partnership (Exhibit 10.1 to Form S-1).
*4.1 Indenture, dated as of June 2, 2000, between the
registrants and Bank One Trust Company, N.A. (Exhibit
4.1 to the Partnership's Quarterly Report on Form
10-Q for the quarterly period ended June 30, 2000
("June 2000 10-Q")).
*4.2 First Supplemental Indenture, dated as of September
14, 2000, between the registrants and Bank One Trust
Company, N.A. (Exhibit 4.2 to Form S-4 Registration
Statement, Registration No. 333-46212 ("NBP Form
S-4")).
*4.3 Indenture, dated as of March 21, 2001, between
Northern Border Partners, L.P. and Northern Border
Intermediate Limited Partnership and Bank One Trust
Company, N.A., Trustee (Exhibit 4.3 to Northern
Border Partners, L.P. Form 10-K for the year ended
December 31, 2001).
*4.4 Indenture, dated as of August 17, 1999, between
Northern Border Pipeline Company and Bank One Trust
Company, NA, successor to The First National Bank of
Chicago, as trustee. (Exhibit No. 4.1 to Northern
Border Pipeline Company's Form S-4 Registration
Statement, Registration No. 333-88577 ("NB Form
S-4")).
*4.5 Indenture, dated as of September 17, 2001, between
Northern Border Pipeline Company and Bank Trust
Company, N.A. (Exhibit 4.2 to Northern Border
Pipeline Company's Registration Statement on Form
S-4, Registration No. 333-73282 ("2001 NB Form
S-4")).
*4.6 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 Northern Border Pipeline Company General Partnership
Agreement between Northern Plains Natural Gas
Company, Northwest Border Pipeline Company, Pan
Border Gas Company, TransCanada Border Pipeline Ltd.
and TransCan Northern Ltd., effective March 9, 1978,
as amended (Exhibit 10.2 to Form S-1).
*10.2 Form of Seventh Supplement Amending Northern Border
Pipeline Company General Partnership Agreement
(Exhibit 10.15 to Form S-1).
*10.3 Eighth Supplement Amending Northern Border Pipeline
Company General Partnership Agreement (Exhibit 10.15
to NB Form S-4).
73
*10.4 Ninth Supplement Amending Northern Border Pipeline
Company General Partnership Agreement (Exhibit 10.37
to 2001 Form S-4).
*10.5 Operating Agreement between Northern Border Pipeline
Company and Northern Plains Natural Gas Company,
dated February 28, 1980 (Exhibit 10.3 to Form S-1).
*10.6 Administrative Services Agreement between NBP
Services Corporation, Northern Border Partners, L.P.
and Northern Border Intermediate Limited Partnership
(Exhibit 10.4 to Form S-1).
10.7 Credit Agreement, dated as of November 24, 2003,
among Northern Border Partners, L.P., SunTrust Bank,
Harris Nesbitt Corp., Wachovia Bank, National
Association, Citigroup, N.A., SunTrust Capital
Markets, Inc., and the Lenders (as named therein).
*10.8 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).
*10.9 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).
*10.10 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).
*10.11 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).
*10.12 Operating Agreement between Midwestern Gas
Transmission Company and Northern Plains Natural Gas
Company dated as of April 1, 2001. (Exhibit 10.38 to
Northern Border Partners, L.P.'s Form 10-K for the
year ended December 31, 2001).
*10.13 Operating Agreement between Viking Gas Transmission
Company and Northern Plains Natural Gas Company dated
as of January 17, 2003. Exhibit 10.18 to Northern
Border Partners, L.P.'s Form 10-K for the year ended
December 31, 2002)
*10.14 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")).
12.1 Statement re computation of ratios
21 The subsidiaries of Northern Border Partners, L.P.
are Northern Border Intermediate Limited Partnership;
Northern Border Pipeline Company; Crestone Energy
Ventures, L.L.C.; Bear Paw Investments, LLC; Bear Paw
Energy, LLC; Border Midwestern Company; Midwestern
Gas Transmission Company; Border Viking Company; and
Viking Gas Transmission Company.
74
23.01 Consent of KPMG LLP.
31.1 Certification of principal executive office 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
Amendment No. 1 to Form S-8, 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.
The total amount of securities of the Partnership authorized under any
instrument with respect to long-term debt not filed as an exhibit does
not exceed 10% of the total assets of the Partnership and its
subsidiaries on a consolidated basis. The Partnership agrees, upon
request of the Securities and Exchange Commission, to furnish copies of
any or all of such instruments to the Securities and Exchange
Commission.
(b)REPORTS
The Partnership filed a Current Report on Form 8-K, dated October 1,
2003, including an announcement and a copy of a press release regarding
a non-cash charge to be recorded by Northern Border Partners, L.P. of
approximately $219 million to reflect asset and goodwill impairments
for its natural gas and processing business. The information was
furnished under Items 9 and 12 of the Form.
The Partnership filed a Current Report on Form 8-K, dated October 24,
2003, including a copy of a press release announcing earnings for the
third quarter of 2003. The information was furnished under Item 9 of
the Form.
The Partnership 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.
The Partnership 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.
75
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 12th day of
March, 2004.
NORTHERN BORDER PARTNERS, L.P.
(A Delaware Limited Partnership)
By: WILLIAM R. CORDES
---------------------------------
William R. Cordes
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons in the capacities and
on the dates indicated.
Signature Title Date
--------- ----- ----
/s/WILLIAM R. CORDES Chief Executive Officer and March 12, 2004
- --------------------------- Chairman of the Partnership
William R. Cordes Policy Committee
(Principal Executive Officer)
/s/STANLEY C. HORTON Member of Partnership Policy March 12, 2004
- --------------------------- Committee
Stanley C. Horton
/s/PAUL E. MILLER Member of Partnership Policy March 12, 2004
- --------------------------- Committee
Paul E. Miller
/s/JERRY L. PETERS Chief Financial and March 12, 2004
- --------------------------- Accounting Officer
Jerry L. Peters
76
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
INDEX TO FINANCIAL STATEMENTS
PAGE NO.
--------
Consolidated Financial Statements
Independent Auditors' Report F-2
Consolidated Balance Sheet - December 31, 2003 and 2002 F-3
Consolidated Statement of Income - Years Ended F-4
December 31, 2003, 2002 and 2001
Consolidated Statement of Comprehensive Income - Years Ended F-5
December 31, 2003, 2002 and 2001
Consolidated Statement of Cash Flows - Years Ended F-6
December 31, 2003, 2002 and 2001
Consolidated Statement of Changes in Partners' Equity - F-7
Years Ended December 31, 2003, 2002 and 2001
Notes to Consolidated Financial Statements F-8 through
F-37
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 Partners, L.P.:
We have audited the accompanying consolidated balance sheets of Northern Border
Partners, L.P. (a Delaware limited partnership) and Subsidiaries as of December
31, 2003 and 2002, and the related consolidated 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 consolidated
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these consolidated 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 consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Northern Border
Partners, L.P. and Subsidiaries as of December 31, 2003 and 2002, and the
results of their operations and their 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.
As discussed in note 13 to the consolidated financial statements, Northern
Border Partners, L.P. and Subsidiaries adopted the provisions of Statement of
Financial Accounting Standards (SFAS) No. 143, Accounting for Asset Retirement
Obligations in 2003. As discussed in note 4 to the consolidated financial
statements, Northern Border Partners, L.P. and Subsidiaries adopted SFAS No.
142, Accounting for Goodwill and Other Intangible Assets in 2002.
KPMG LLP
Omaha, Nebraska
January 27, 2004
F-2
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(IN THOUSANDS, EXCEPT UNIT AMOUNTS)
DECEMBER 31,
-----------------------
2003 2002
---------- ----------
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 35,895 $ 34,689
Accounts receivable 61,503 55,358
Related party receivables (net of allowance
for doubtful accounts of $12,444 and $12,392
in 2003 and 2002, respectively) -- 70
Materials and supplies, at cost 7,826 5,252
Prepaid expenses 6,726 4,456
Other 2,245 332
---------- ----------
Total current assets 114,195 100,157
---------- ----------
PROPERTY, PLANT AND EQUIPMENT
Interstate Natural Gas Pipelines 2,612,241 2,471,627
Gas Gathering and Processing 253,903 354,652
Coal Slurry 45,911 43,092
---------- ----------
Total property, plant and equipment 2,912,055 2,869,371
Less: Accumulated provision for
depreciation and amortization 919,951 854,091
---------- ----------
Property, plant and equipment, net 1,992,104 2,015,280
---------- ----------
INVESTMENTS AND OTHER ASSETS
Investment in unconsolidated affiliates 268,166 244,515
Goodwill 152,782 295,848
Derivative financial instruments 19,553 36,885
Other 23,783 23,251
---------- ----------
Total investments and other assets 464,284 600,499
---------- ----------
Total assets $2,570,583 $2,715,936
========== ==========
LIABILITIES AND PARTNERS' EQUITY
CURRENT LIABILITIES
Current maturities of long-term debt $ 7,740 $ 67,765
Accounts payable 20,834 30,584
Related party payables 25,698 25,927
Accrued taxes other than income 33,708 31,108
Accrued interest 13,206 16,742
Derivative financial instruments 5,736 4,095
---------- ----------
Total current liabilities 106,922 176,221
---------- ----------
LONG-TERM DEBT, net of current maturities 1,408,246 1,335,978
---------- ----------
MINORITY INTERESTS IN PARTNERS' EQUITY 240,731 242,931
---------- ----------
RESERVES AND DEFERRED CREDITS
Deferred income taxes 2,898 450
Other 11,213 16,321
---------- ----------
Total reserves and deferred credits 14,111 16,771
---------- ----------
COMMITMENTS AND CONTINGENCIES (NOTE 11)
PARTNERS' EQUITY
General partners 15,902 18,730
Common units (46,397,214 and 43,809,714 units
issued and outstanding at December 31, 2003
and 2002, respectively) 779,195 917,791
Accumulated other comprehensive income 5,476 7,514
---------- ----------
Total partners' equity 800,573 944,035
---------- ----------
Total liabilities and partners' equity $2,570,583 $2,715,936
========== ==========
The accompanying notes are an integral part of these consolidated financial
statements.
F-3
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF INCOME
(IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)
YEAR ENDED DECEMBER 31,
-----------------------------------
2003 2002 2001
--------- --------- ---------
OPERATING REVENUES
Operating revenues $ 555,927 $ 487,204 $ 458,054
Provision for rate refunds -- -- (2,057)
--------- --------- ---------
Operating revenues, net 555,927 487,204 455,997
--------- --------- ---------
OPERATING EXPENSES
Product purchases 80,774 50,648 39,699
Operations and maintenance 127,574 106,331 92,891
Depreciation and amortization, including
impairment charges of $219,080 in 2003 300,199 74,672 75,424
Taxes other than income 35,443 32,194 27,863
--------- --------- ---------
Operating expenses 543,990 263,845 235,877
--------- --------- ---------
OPERATING INCOME 11,937 223,359 220,120
--------- --------- ---------
INTEREST EXPENSE
Interest expense 79,159 83,227 91,653
Interest expense capitalized (179) (329) (1,745)
--------- --------- ---------
Interest expense, net 78,980 82,898 89,908
--------- --------- ---------
OTHER INCOME (EXPENSE)
Allowance for equity funds used
during construction 331 248 947
Equity earnings of
unconsolidated affiliates 18,815 14,570 1,697
Other income 7,739 2,740 2,997
Other expense (2,024) (991) (4,922)
--------- --------- ---------
Other income, net 24,861 16,567 719
--------- --------- ---------
MINORITY INTERESTS IN NET INCOME 44,460 42,816 42,138
--------- --------- ---------
INCOME (LOSS) FROM CONTINUING OPERATIONS
BEFORE INCOME TAXES (86,642) 114,212 88,793
INCOME TAXES 5,365 1,643 499
--------- --------- ---------
INCOME (LOSS) FROM CONTINUING OPERATIONS (92,007) 112,569 88,294
DISCONTINUED OPERATIONS, NET OF TAX 4,196 1,107 (508)
CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE, NET OF TAX (643) -- --
--------- --------- ---------
NET INCOME (LOSS) TO PARTNERS $ (88,454) $ 113,676 $ 87,786
========= ========= =========
CALCULATION OF LIMITED PARTNERS' INTEREST
IN NET INCOME (LOSS):
Net income (loss) to partners $ (88,454) $ 113,676 $ 87,786
Less: general partners' interest in
net income (loss) 5,969 9,602 6,008
--------- --------- ---------
Limited partners' interest in
net income (loss) $ (94,423) $ 104,074 $ 81,778
========= ========= =========
LIMITED PARTNERS' PER UNIT NET INCOME (LOSS):
Income (loss) from continuing operations $ (2.16) $ 2.41 $ 2.13
Discontinued operations, net of tax 0.09 0.03 (0.01)
Cumulative effect of change in
accounting principle, net of tax (0.01) -- --
--------- --------- ---------
Net income (loss) $ (2.08) $ 2.44 $ 2.12
========= ========= =========
NUMBER OF UNITS USED IN COMPUTATION 45,370 42,709 38,538
========= ========= =========
The accompanying notes are an integral part of these consolidated financial
statements.
F-4
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
(IN THOUSANDS)
YEAR ENDED DECEMBER 31,
-----------------------------------
2003 2002 2001
--------- --------- ---------
Net income (loss) to partners $ (88,454) $ 113,676 $ 87,786
Other comprehensive income:
Transition adjustment from
adoption of SFAS No. 133 -- -- 22,183
Change associated with current
period hedging transactions (4,383) (13,490) (1,100)
Change associated with current
period foreign currency translation 2,345 475 (554)
--------- --------- ---------
Total comprehensive income (loss) $ (90,492) $ 100,661 $ 108,315
========= ========= =========
The accompanying notes are an integral part of these consolidated financial
statements.
F-5
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
(IN THOUSANDS)
YEAR ENDED DECEMBER 31,
-----------------------------------
2003 2002 2001
--------- --------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) to partners $ (88,454) $ 113,676 $ 87,786
--------- --------- ---------
Adjustments to reconcile net income (loss) to partners
to net cash provided by operating activities:
Depreciation and amortization, including
impairment charges of $219,080 in 2003 301,977 76,239 76,675
Minority interests in net income 44,460 42,816 42,138
Non-cash (gains) losses from risk
management activities (209) (4,509) 5,304
Provision for regulatory refunds 261 10,000 2,036
Regulatory refunds paid (10,261) -- (6,762)
Cumulative effect of change in accounting
principle 643 -- --
Gain on sale of gathering and processing assets (4,872) -- --
Equity earnings in unconsolidated affiliates (18,928) (14,570) (1,697)
Distributions received from unconsolidated
affiliates 16,262 10,820 7,083
Allowance for equity funds used
during construction (331) (248) (947)
Reserves and deferred credits 4,472 (24) 119
Changes in components of working capital (18,592) 9,670 20,677
Other (1,768) 136 1,536
--------- --------- ---------
Total adjustments 313,114 130,330 146,162
--------- --------- ---------
Net cash provided by operating activities 224,660 244,006 233,948
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for property, plant
and equipment, net (30,282) (50,738) (126,414)
Acquisition of businesses (123,194) (1,561) (345,074)
Sale of gathering and processing assets 40,250 -- --
Investments in unconsolidated affiliates
and other (3,514) (2,972) (11,197)
--------- --------- ---------
Net cash used in investing activities (116,740) (55,271) (482,685)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Cash distributions
General and limited partners (155,173) (146,960) (120,884)
Minority Interests (46,194) (49,238) (42,910)
Issuance of partnership interests, net 102,203 75,376 172,222
Issuance of long-term debt, net 342,000 499,894 863,103
Retirement of long-term debt (361,129) (567,540) (604,929)
Decrease in bank overdrafts -- -- (22,437)
Proceeds (payments) upon termination of
derivatives 12,250 20,551 (8,417)
Long-term debt financing costs (671) (2,884) (5,619)
--------- --------- ---------
Net cash provided by (used in)
financing activities (106,714) (170,801) 230,129
--------- --------- ---------
NET CHANGE IN CASH AND CASH EQUIVALENTS 1,206 17,934 (18,608)
Cash and cash equivalents-beginning of year 34,689 16,755 35,363
--------- --------- ---------
Cash and cash equivalents-end of year $ 35,895 $ 34,689 $ 16,755
========= ========= =========
Changes in components of working capital:
Accounts receivable $ (3,135) $ 4,303 $ 6,493
Materials and supplies, prepaid expenses
and other (3,833) (2,573) (4,937)
Accounts payable (8,525) 9,370 14,321
Accrued taxes other than income 437 2,378 (115)
Accrued interest (3,536) (3,808) 4,915
--------- --------- ---------
Total $ (18,592) $ 9,670 $ 20,677
========= ========= =========
The accompanying notes are an integral part of these consolidated financial
statements.
F-6
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY
(IN THOUSANDS)
ACCUMULATED
OTHER TOTAL
GENERAL COMMON COMPREHENSIVE PARTNERS'
PARTNERS UNITS INCOME EQUITY
--------- --------- ------------- ---------
Partners' Equity at December 31, 2000 $ 11,445 $ 560,829 $ -- $ 572,274
Net income to partners 6,008 81,778 -- 87,786
Transition adjustment from
adoption of SFAS No. 133 -- -- 22,183 22,183
Change associated with current
period hedging transactions -- -- (1,100) (1,100)
Change associated with current
period foreign currency translation -- -- (554) (554)
Issuance of partnership interests, net
(10,119,451 common units, including
5,711,901 common units issued as
consideration for an acquisition) 7,105 348,148 -- 355,253
Distributions paid (6,669) (114,215) -- (120,884)
--------- --------- --------- ---------
Partners' Equity at December 31, 2001 17,889 876,540 20,529 914,958
Net income to partners 9,602 104,074 -- 113,676
Change associated with current
period hedging transactions -- -- (13,490) (13,490)
Change associated with current
period foreign currency translation -- -- 475 475
Issuance of partnership interests, net
(2,186,700 common units) 1,507 73,869 -- 75,376
Distributions paid (10,268) (136,692) -- (146,960)
--------- --------- --------- ---------
Partners' Equity at December 31, 2002 18,730 917,791 7,514 944,035
Net income (loss) to partners 5,969 (94,423) -- (88,454)
Change associated with current
period hedging transactions -- -- (4,383) (4,383)
Change associated with current
period foreign currency translation -- -- 2,345 2,345
Issuance of partnership interests, net
(2,587,500 common units) 2,044 100,159 -- 102,203
Distributions paid (10,841) (144,332) -- (155,173)
--------- --------- --------- ---------
Partners' Equity at December 31, 2003 $ 15,902 $ 779,195 $ 5,476 $ 800,573
========= ========= ========= =========
The accompanying notes are an integral part of these consolidated financial
statements.
F-7
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND MANAGEMENT
Northern Border Partners, L.P., through a subsidiary limited
partnership, Northern Border Intermediate Limited Partnership, both
Delaware limited partnerships, collectively referred to herein as the
Partnership, owns a 70% general partner interest in Northern Border
Pipeline Company (Northern Border Pipeline). The remaining 30% general
partner interest in Northern Border Pipeline is owned by TC PipeLines
Intermediate Limited Partnership (TC PipeLines). Crestone Energy
Ventures, L.L.C. (Crestone Energy Ventures); Bear Paw Energy, L.L.C.
(Bear Paw Energy); Border Midstream Services, Ltd. (Border Midstream);
Midwestern Gas Transmission Company (Midwestern Gas Transmission);
Viking Gas Transmission Company (Viking Gas Transmission) and Black
Mesa Pipeline, Inc. (Black Mesa) are wholly-owned subsidiaries of the
Partnership. As discussed in Note 3, the Partnership acquired all of
the common stock of Viking Gas Transmission on January 17, 2003.
Northern Plains Natural Gas Company (Northern Plains), a wholly-owned
subsidiary of Enron Corp. (Enron), Pan Border Gas Company (Pan Border),
a wholly-owned subsidiary of Northern Plains, and Northwest Border
Pipeline Company (Northwest Border), a wholly-owned subsidiary of
TransCanada PipeLines Limited, which is a subsidiary of TransCanada
Corporation, and affiliate of TC PipeLines, serve as the General
Partners of the Partnership and collectively own a 2% general partner
interest in the Partnership. Northern Plains also owns common units
representing a 1.1% limited partner interest and Enron, through an
indirect subsidiary, owns common units representing a 5.8% limited
partner interest in the Partnership at December 31, 2003 (see Note 10).
The Partnership is managed under the direction of the Partnership
Policy Committee consisting of one person appointed by each General
Partner. The members appointed by Northern Plains, Pan Border and
Northwest Border have 50%, 32.5% and 17.5%, respectively, of the voting
interest on the Partnership Policy Committee. The Partnership has
entered into an administrative services agreement with NBP Services
Corporation (NBP Services), a wholly owned subsidiary of Enron. NBP
Services provides certain administrative, operating and management
services for the Partnership and its gas gathering and processing and
coal slurry businesses and is reimbursed for its direct and indirect
costs and expenses. NBP Services also utilizes Enron affiliates to
provide these services. For the years ended December 31, 2003, 2002 and
2001, charges from NBP Services and its affiliates totaled
approximately $19.1 million, $16.2 million and $15.3 million,
respectively. See Note 17 for a discussion of the Partnership's
relationships with Enron and developments involving Enron.
Northern Border Pipeline is a Texas general partnership formed in 1978.
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 the Partnership (one representative
appointed by each of the General Partners of the Partnership) and one
representative from TC PipeLines. The Partnership's representatives
selected by Northern Plains, Pan Border and Northwest Border have 35%,
22.75% and 12.25%,
F-8
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND MANAGEMENT (continued)
respectively, of the voting interest on the Northern Border Pipeline
Management Committee. The representative designated by TC PipeLines
votes the remaining 30% interest.
The Northern Border Pipeline partnership agreement provides that
distributions to Northern Border Pipeline's partners are to be made on
a pro rata basis according to each partner's capital account balance.
The Northern Border Pipeline Management Committee determines the amount
and timing of such distributions. Any changes to, or suspension of, the
cash distribution policy of Northern Border Pipeline requires the
unanimous approval of the Northern Border Pipeline Management
Committee.
The Partnership acquired Midwestern Gas Transmission effective May 1,
2001 (see Note 3). The Midwestern Gas Transmission system is a 350-mile
interstate natural gas pipeline extending from Portland, Tennessee to
Joliet, Illinois. Midwestern Gas Transmission's pipeline system
connects with multiple pipeline systems, including Northern Border
Pipeline.
On January 17, 2003, the Partnership acquired Viking Gas Transmission
(see Note 3). The Viking Gas Transmission system is a 578-mile
interstate natural gas pipeline extending from the United
States-Canadian border near Emerson, Manitoba to Marshfield, Wisconsin.
Viking Gas Transmission connects with multiple pipeline systems.
The day-to-day management of Northern Border Pipeline's, Midwestern Gas
Transmission's and Viking Gas Transmission's affairs is the
responsibility of Northern Plains, as defined by their respective
operating agreements with Northern Plains. Northern Border Pipeline,
Midwestern Gas Transmission and Viking Gas Transmission are charged for
the salaries, benefits and expenses of Northern Plains. Northern Plains
also utilizes Enron affiliates for management services related to
Northern Border Pipeline, Midwestern Gas Transmission and Viking Gas
Transmission. For the years ended December 31, 2003, 2002 and 2001,
Northern Plains' and its affiliates' charges to Northern Border
Pipeline, Midwestern Gas Transmission and Viking Gas Transmission
totaled approximately $38.5 million, $29.1 million and $31.5 million,
respectively.
On March 30, 2001, the Partnership acquired Bear Paw Energy (see Note
3). Bear Paw Energy has extensive natural gas gathering, processing and
fractionation operations in the Williston Basin in Montana, North
Dakota and Saskatchewan as well as gas gathering operations in the
Powder River Basin in Wyoming. In the Williston Basin, Bear Paw Energy
has over 3,000 miles of gathering pipelines and five processing plants
with 95 million cubic feet per day of capacity. Bear Paw Energy has
approximately 1,100 miles of high and low pressure gathering pipelines
and approximately 430,000 acres of dedicated reserves in the Powder
River Basin.
On April 4, 2001, Border Midstream completed the acquisition of the
Mazeppa and Gladys gas processing plants, gas gathering systems and an
undivided minority interest in the Gregg Lake/Obed Pipeline (see Note
3). The Gregg Lake/Obed Pipeline system, which is located near
Edmonton, Alberta, is comprised of 85 miles of gathering lines. In June
2003, the Partnership sold its Gladys and Mazeppa processing plants and
related gas gathering facilities (see Note 3).
F-9
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND MANAGEMENT (continued)
The Partnership owns a 49% common membership interest and a 100%
preferred A share interest in Bighorn Gas Gathering, L.L.C. (Bighorn);
a 33% interest in Fort Union Gas Gathering, L.L.C. (Fort Union); a 35%
interest in Lost Creek Gathering, L.L.C. (Lost Creek); a 36% interest
in the Gregg Lake/Obed Pipeline; and a 33% interest in Guardian
Pipeline, L.L.C. (Guardian Pipeline). The Partnership acquired its
interest in Guardian Pipeline in January 2003 (see Note 3).
Collectively, Bighorn, Fort Union and Lost Creek own over 300 miles of
gas gathering facilities in Wyoming. The gathering facilities
interconnect to the interstate gas pipeline grid serving gas markets in
the Rocky Mountains, the Midwest and California. Guardian Pipeline is a
141-mile interstate natural gas pipeline system that went into service
on December 7, 2002. This system transports natural gas from Joliet,
Illinois to a point west of Milwaukee, Wisconsin.
Black Mesa owns a 273-mile, 18-inch diameter coal slurry pipeline that
originates at a coal mine in Kayenta, Arizona and ends at the 1,500
megawatt Mohave Power Station located in Laughlin, Nevada.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(A) Principles of Consolidation and Use of Estimates
The consolidated financial statements include the assets,
liabilities and results of operations of the Partnership and
its majority-owned subsidiaries. The Partnership operates
through a subsidiary limited partnership of which the
Partnership is the sole limited partner and the General
Partners are the sole general partners. The 30% ownership of
Northern Border Pipeline by TC PipeLines is accounted for as a
minority interest. All significant intercompany balances and
transactions have been eliminated in consolidation.
The preparation of financial statements in conformity with
accounting principles generally accepted (GAAP) 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, Midwestern Gas Transmission and
Viking Gas Transmission are subject to regulation by the
Federal Energy Regulatory Commission (FERC). Northern Border
Pipeline's and Viking Gas Transmission's accounting policies
conform to Statement of Financial Accounting Standards (SFAS)
No. 71, "Accounting for the Effects of Certain Types of
Regulation." Accordingly, certain assets that result from the
regulated ratemaking process are recorded that would not be
recorded under accounting principles generally accepted in the
United States of America for nonregulated entities. Northern
Border Pipeline and Viking Gas Transmission continually assess
whether the recovery of
F-10
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)
(B) Government Regulation (continued)
the regulatory assets are probable by considering such factors
as regulatory changes and the impact of competition. Northern
Border Pipeline and Viking Gas Transmission believe the
recovery of the existing regulatory assets is probable. If
future recovery ceases to be probable, Northern Border
Pipeline and Viking Gas Transmission would be required to
write off the regulatory assets at that time. At December 31,
2003 and 2002, Northern Border Pipeline and Viking Gas
Transmission have reflected regulatory assets of approximately
$8.9 million and $10.5 million, respectively, in other assets
on the consolidated balance sheet. Northern Border Pipeline is
recovering the regulatory assets from its shippers over
varying time periods, which range from five to 44 years.
Viking Gas Transmission is recovering the regulatory assets
from its shippers over five years.
Although Northern Border Pipeline is a general partnership,
Northern Border Pipeline's tariff establishes the method of
accounting for and calculating income taxes and requires
Northern Border Pipeline to reflect in its financial records
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.
(C) 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.
(D) Revenue Recognition
Northern Border Pipeline, Midwestern Gas Transmission and
Viking Gas Transmission transport gas for shippers under
tariffs regulated by the FERC. The tariffs specify the
calculation of amounts to be paid by shippers and the general
terms and conditions of transportation service on the
respective pipeline systems. Operating 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 the natural
gas pipelines 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, Midwestern Gas Transmission and
Viking Gas Transmission do not own the gas that they
transport, and therefore do not assume the related natural gas
commodity risk.
F-11
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)
(D) Revenue Recognition (continued)
For the gas gathering and processing businesses, operating
revenue is recorded when gas is processed in or transported
through company facilities. The gas gathering and processing
businesses also receive certain cash payments from customers
in advance for gathering services to be provided in the
future. These cash payments were deferred and recognized into
operating revenues by using a percentage based on the
depletion of natural gas reserves associated with the
gathering system.
Black Mesa's operating revenue is derived from a pipeline
transportation agreement. Under the terms of the agreement,
Black Mesa receives a monthly demand payment, a per ton
commodity payment and a reimbursement for certain other
expenses.
(E) Income Taxes
The Partnership is not a taxable entity for federal income tax
purposes. As such, the Partnership does not directly pay
federal income tax. The Partnership's taxable income or loss,
which may vary substantially from the net income or loss
reported in the consolidated statement of income, is
includable in the federal income tax returns of each partner.
The aggregate difference in the basis of the Partnership's net
assets for financial and income tax purposes cannot be readily
determined as the Partnership does not have access to
information about each partner's tax attributes related to the
Partnership.
The Partnership's corporate subsidiaries are required to pay
federal and state income taxes. Income taxes are accounted for
under the asset and liability method. Deferred income tax
assets and liabilities are recognized by these entities for
the future tax consequences attributable to differences
between the financial statement carrying amount of existing
assets and liabilities and their respective tax bases and
operating loss carryforwards. Deferred tax assets and
liabilities are measured using enacted tax rates expected to
apply to taxable income in the years in which those temporary
differences are expected to be recovered or settled. The
effect on deferred tax assets and liabilities of a change in
tax rates is recognized in income in the period that includes
the enactment date.
(F) Property, Plant and Equipment and Related Depreciation and
Amortization
Property, plant and equipment is stated at original cost.
During periods of construction, utilities are 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 utility property
retired is charged to accumulated depreciation and
amortization, net of salvage and cost of removal. For utility
property, no retirement gain or loss is included in income
except in the case of retirements or sales of entire operating
units. Maintenance and repairs are charged to operations in
the period incurred.
F-12
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)
(F) Property, Plant and Equipment and Related Depreciation and
Amortization (continued)
For utility property, the provision for depreciation and
amortization is an integral part of the interstate pipelines'
FERC tariffs. The effective depreciation rate applied to
Northern Border Pipeline's, Midwestern Gas Transmission's and
Viking Gas Transmission's transmission plant was 2.25%, 1.9%
and 2.0%, respectively. Composite rates are applied to all
other functional groups of utility property having similar
economic characteristics. The effective depreciation rate
applied to natural gas gathering and processing assets ranges
from 5% to 20% (see Note 4). The effective depreciation rate
applied to coal slurry assets ranges from 4% to 20%.
The Partnership evaluates impairment of long-lived assets in
accordance with SFAS No. 144, "Accounting for the Impairment
or Disposal of Long-Lived Assets." Long-lived assets are
reviewed for impairment whenever events or changes in
circumstances indicate that the carrying amount of an asset
may not be recoverable. Recoverability of the carrying amount
of assets is measured by a comparison of the carrying amount
of the asset to future net cash flows expected to be generated
by the asset. If such assets are considered to be impaired,
the impairment to be recognized is measured by the amount by
which the carrying amount of the assets exceeds the fair value
of the assets.
(G) Foreign Currency Translation
For the Partnership's Canadian subsidiary, Border Midstream,
asset and liability accounts are translated from its
functional currency (the Canadian dollar) at year-end rates of
exchange and revenue and expenses are translated at average
exchange rates prevailing during the year. Translation
adjustments are included as a separate component of other
comprehensive income and partners' equity. Currency
transaction gains and losses, which result when Border
Midstream pays Canadian dollars to the Partnership, are
recorded in other income (expense) and discontinued operations
on the consolidated statement of income. During 2003, the
Partnership recorded currency transactions gains of $6.0
million. Currency transaction gains were insignificant in 2002
and 2001.
(H) Goodwill
Beginning January 1, 2002, the excess of cost over fair value
of the net assets acquired in business acquisitions or
goodwill is no longer being amortized and instead is tested
for impairment (see Note 4). Prior to January 1, 2002, the
excess was being amortized using a straight-line method over
30 years. During 2001, the Partnership recorded amortization
expense of $6.3 million related to its investments in
unconsolidated affiliates, which is reflected as a component
of equity earnings of unconsolidated affiliates in the
consolidated statement of income. See Note 9 for details on
the Partnership's investments in unconsolidated affiliates and
related equity earnings. For the Partnership's consolidated
affiliates, during 2001, the Partnership recorded amortization
expense of $7.0 million. This amortization expense is
reflected as a component of depreciation and amortization in
the consolidated statement of income.
F-13
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)
(I) Equity Method of Accounting
The Partnership accounts for its investments, which it does
not control, by the equity method of accounting. Under this
method, an investment is carried at its acquisition cost, plus
the equity in undistributed earnings or losses since
acquisition.
(J) Risk Management
The Partnership uses financial instruments in the management
of its interest rate and commodity price 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. The Partnership
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. The Partnership
adopted SFAS No. 133 beginning January 1, 2001. See Note 8 for
a discussion of the Partnership's derivative instruments and
hedging activities.
(K) Reclassifications
Certain reclassifications have been made to the consolidated
financial statements for prior years to conform with the
current year presentation.
3. BUSINESS ACQUISITIONS AND DISPOSITIONS
On January 17, 2003, the Partnership acquired all of the common stock
of Viking Gas Transmission including a one-third interest in Guardian
Pipeline for approximately $162 million, which included the assumption
of $40 million of debt.
The Partnership completed three acquisitions during 2001. On March 30,
2001, the Partnership acquired Bear Paw Energy for $381.7 million. The
purchase price consisted of $198.7 million in cash and the issuance of
5.7 million common units valued at $183.0 million. Border Midstream
acquired the Mazeppa and Gladys gas processing plants, gas gathering
systems and an undivided minority interest in the Gregg Lake/Obed
Pipeline (Gregg Lake/Obed) for $70 million (Canadian) or $45 million
(U.S.) on April 4, 2001. Effective May 1, 2001, the Partnership
acquired Midwestern Gas Transmission for $102 million.
The Partnership has accounted for these acquisitions using the purchase
method of accounting and accordingly, operations of the acquired
entities have been included since the dates of acquisition. The
purchase price has
F-14
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
3. BUSINESS ACQUISITIONS AND DISPOSITIONS (continued)
been allocated based upon the estimated fair value of the assets and
liabilities acquired as of the acquisition date. The excess of the
purchase price over the fair value of the Bear Paw Energy and
Midwestern Gas Transmission net assets acquired is reflected as
goodwill on the consolidated balance sheet. The investment in Guardian
Pipeline is reflected in investments in unconsolidated affiliates on
the consolidated balance sheet.
The following is a summary of the effects of the acquisitions on the
Partnership's consolidated financial position (amounts in thousands):
2003 2002 2001
-------- -------- ---------
Current assets $ 8,804 $ -- $ 17,257
Property, plant and equipment 127,619 -- 261,225
Investments in unconsolidated
affiliates 27,600 -- --
Goodwill and other assets 5,035 361 275,443
Current liabilities (5,559) 1,200 (14,908)
Long-term debt, including
current maturities (40,025) -- (13,113)
Other liabilities (280) -- (498)
Accumulated other comprehensive
income -- -- 2,699
Common units issued by
the Partnership -- -- (183,031)
-------- -------- ---------
$123,194 $ 1,561 $ 345,074
======== ======== =========
If the Viking Gas Transmission acquisition made in 2003 had occurred at
the beginning of 2002, the Partnership's 2002 consolidated operating
revenues, net income to partners and per unit net income would have
been $517 million, $119 million and $2.55 per unit, respectively. If
the acquisitions made in 2001 had occurred at the beginning of 2001,
the Partnership's 2001 consolidated operating revenues, net income to
partners and per unit net income would have been $506 million, $88
million and $2.12 per unit, respectively. These unaudited pro forma
results are for illustrative purposes only and are not necessarily
indicative of the operating results that would have occurred had the
business acquisitions been consummated at that date, nor are they
necessarily indicative of future operating results.
In June 2003, the Partnership sold its Gladys and Mazeppa processing
plants and related gas gathering facilities located in Alberta, Canada
for approximately $40.3 million. Operating revenues, operating expenses
and other income and expense for 2002 and 2001 have been reclassified
for amounts related to the discontinued operations. Operating revenues
for the years ended December 31, 2003, 2002 and 2001, were $4.9
million, $8.1 million and $5.5 million, respectively. Discontinued
operations on the accompanying consolidated statement of income
consists of the following:
December 31,
------------------------
(in thousands) 2003 2002 2001
- ------------------------------------------ ------ ------ ------
Operating income (loss) $ (796) $1,650 $ (721)
Gain on sale of assets 4,056 -- --
Income tax (expense) benefit 936 (543) 213
------ ------ ------
Income (loss) from discontinued operations $4,196 $1,107 $ (508)
====== ====== ======
F-15
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
4. GOODWILL AND ASSET IMPAIRMENT
In the third quarter of 2001, the Financial Accounting Standards Board
(FASB) issued SFAS No. 142, "Goodwill and Other Intangible Assets."
SFAS No. 142 modifies the accounting and reporting of goodwill and
intangible assets. It requires entities to discontinue the amortization
of goodwill, reallocate goodwill among its reporting segments and
perform impairment tests by applying a fair-value-based analysis on the
goodwill in each reporting segment. The Partnership adopted SFAS No.
142 effective January 1, 2002. At December 31, 2003 and 2002, the
Partnership's balance sheet included goodwill of approximately $334
million and $476 million, respectively. Of the total goodwill,
approximately $182 million and $180 million was recorded in the
Partnership's investment in unconsolidated affiliates at December 31,
2003 and 2002, respectively. The Partnership has selected the fourth
quarter to perform its annual impairment testing. If testing indicates
an impairment of goodwill exists in a reporting segment, the entity
must analyze the carrying value of the tangible assets in that segment
under SFAS No. 144.
During 2002, the Partnership completed its initial and annual
evaluations of approximately $296 million recorded goodwill. The
Partnership determined that it did not have an impairment loss for
2002. For 2003, due to lower throughput volumes experienced and
anticipated in its wholly owned subsidiaries in its natural gas
gathering and processing business segment, the Partnership accelerated
its annual impairment test under SFAS No. 142 from the fourth quarter
to the third quarter for this segment. For the Partnership's remaining
business segments, the annual impairment testing was performed in the
fourth quarter. In future years, unless conditions indicate earlier
testing is needed, the annual impairment testing for all business
segments will occur in the fourth quarter.
The Partnership engaged the services of an outside independent
consultant to assist in the determination of fair value, as defined by
SFAS No. 142, for purposes of computing the amount of the goodwill
impairment. Upon the determination of the existence of a goodwill
impairment, the Partnership further analyzed, under SFAS No. 144, the
carrying value of the tangible assets in its wholly owned subsidiaries
in its natural gas gathering and processing business segment to
determine the impairment attributed to the tangible assets in the
Powder River Basin. The Partnership recorded total impairment charges
of $219.1 million in the third quarter of 2003. This was comprised of
$76.0 million related to the tangible assets in the Powder River Basin
and $143.1 million for the goodwill related to the natural gas
gathering and processing business segment. Beginning October 1, 2003,
the estimated depreciable life of the Partnership's assets in the
Powder River Basin was reduced from 30 years to 15 years to reflect the
results of the analysis performed on the tangible assets in the Powder
River Basin.
F-16
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
4. GOODWILL AND ASSET IMPAIRMENT (continued)
Changes in the carrying amount of goodwill for the years ended December
31, 2003 and 2002, are summarized as follows:
Interstate Gas Gathering
Natural Gas and Coal
(In thousands) Pipelines Processing Slurry Total
- -------------- ----------- ------------- ------ --------
Balance at
December 31, 2001 $68,408 $ 398,651 $8,378 $ 475,437
Goodwill acquired 464 (18) -- 446
------- ---------- ------ ---------
Balance at
December 31, 2002 68,872 398,633 8,378 475,883
Goodwill acquired 1,527 -- -- 1,527
Impairment losses -- (143,066) -- (143,066)
------- ---------- ------ ---------
Balance at
December 31, 2003 $70,399 $ 255,567 $8,378 $ 334,344
======= ========== ====== =========
The following information discloses the effect of goodwill amortization
on the Partnership's net income (loss) to partners and per unit net
income (loss).
December 31,
(Amounts in thousands, ----------------------------------------
except per unit amounts) 2003 2002 2001
- -------------------------------------- ----------- ----------- -----------
Reported net income (loss) to partners $ (88,454) $ 113,676 $ 87,786
Add back: goodwill amortization -- -- 13,286
----------- ----------- -----------
Adjusted net income (loss) to partners $ (88,454) $ 113,676 $ 101,072
=========== =========== ===========
Reported per unit net income (loss) $ (2.08) $ 2.44 $ 2.12
Add back: goodwill amortization -- -- .34
----------- ----------- -----------
Adjusted per unit net income (loss) $ (2.08) $ 2.44 $ 2.46
=========== =========== ===========
5. 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.
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.
F-17
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
5. RATES AND REGULATORY ISSUES (continued)
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.
6. TRANSPORTATION, GATHERING AND PROCESSING AGREEMENTS
Northern Border Pipeline's, Midwestern Gas Transmission's and Viking
Gas Transmission's operating revenues are collected pursuant to their
FERC tariffs through transportation service agreements. Northern Border
Pipeline's firm transportation service agreements extend for various
terms with termination dates that range from March 2004 to December
2013. The termination dates for Midwestern Gas Transmission's firm
service agreements range from March 2004 to October 2019. The
termination dates for Viking Gas Transmission's firm service agreements
range from May 2004 to October 2014. Northern Border Pipeline,
Midwestern Gas Transmission and Viking Gas Transmission also have
interruptible transportation service agreements and other
transportation service agreements with numerous shippers.
Under the capacity release provisions of Northern Border Pipeline's,
Midwestern Gas Transmission's and Viking Gas Transmission's FERC
tariffs, 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 interstate natural gas pipeline segment, Northern Border
Pipeline's revenues represented approximately 86%, 95% and 97% of the
segment's revenues in 2003, 2002 and 2001, respectively. 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-18
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
6. TRANSPORTATION, GATHERING AND PROCESSING AGREEMENTS (continued)
At December 31, 2003 and 2002, 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.
The gas gathering and processing businesses provide services for
gathering, treating, processing and compression of natural gas and the
fractionation of natural gas liquids. For the year ended December 31,
2003, Bear Paw Energy's largest customers, Lodgepole Energy Marketing
(Lodgepole), Tenaska Marketing Ventures (Tenaska) and BP Canada Energy
Marketing Corp. accounted for $62.4 million (40%), $27.3 million (18%)
and $16.6 million (11%), respectively, of Bear Paw Energy's operating
revenue. For the year ended December 31, 2002, Bear Paw Energy's
largest customers, Lodgepole and Tenaska accounted for $44.2 million
(35%) and $20.2 million (16%), respectively, of Bear Paw Energy's
operating revenue. Lodgepole and Tenaska accounted for $34.8 million
(40%) and $8.7 million (10%), respectively, of Bear Paw Energy's
operating revenue for the period from March 31, 2001 to December 2001.
Bear Paw Energy's operating revenue for 2001 also included $1.7 million
from Enron North America (ENA) related to swap arrangements to hedge
risks of changes in commodity prices (see Note 8) and $0.5 million from
TransCanada Energy. In 2001, Crestone Energy Ventures and Crestone
Gathering Services (collectively Crestone) provided gas gathering and
administrative services to ENA under a master services agreement.
Crestone's revenues from ENA totaled $20.6 million for the year ended
December 31, 2001 (see Note 17). Crestone's revenues from other
affiliates totaled $0.1 million, $0.2 million and $0.3 million in 2003,
2002 and 2001, respectively.
Black Mesa's operating revenue is derived from a transportation
agreement with Peabody Western Coal, the coal supplier for the Mohave
Power Station that expires in December 2005. The coal slurry pipeline
is the sole source of fuel for the Mohave plant. Operating revenues
under the agreement totaled $21.4 million, $21.5 million and $22.0
million for the years ended December 31, 2003, 2002, and 2001,
respectively.
F-19
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
7. CREDIT FACILITIES, LONG-TERM DEBT AND CAPITAL LEASES
Detailed information on long-term debt is as follows:
December 31,
-----------------------
(In thousands) 2003 2002
- ---------------------------------------------- ---------- ----------
Northern Border Pipeline
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
Viking Gas Transmission
Senior Notes (Series A) - 6.65%, due 2008 10,311 --
Senior Notes (Series B) - 7.10%, due 2011 2,850 --
Senior Notes (Series C) - 7.31%, due 2012 8,167 --
Senior Notes (Series D) - 8.04%, due 2014 14,333 --
Northern Border Partners, L.P.
2000 Partnership Senior Notes - 8 7/8%,
due 2010 250,000 250,000
2001 Partnership Senior Notes - 7.10%,
due 2011 225,000 225,000
2001 Partnership Credit Agreement -
average 2.27% at December 31, 2002,
paid in 2003 -- 35,000
2003 Partnership Credit Agreement -
average 2.67% at December 31, 2003,
due 2007 46,000 --
Bear Paw Energy
Capital Leases 6,090 8,854
Fair value adjustment for interest rate
swaps (Note 8) 19,553 36,885
Unamortized debt premium 27,682 19,004
---------- ----------
Total 1,415,986 1,403,743
Less: Current maturities of long-term debt 7,740 67,765
---------- ----------
Long-term debt $1,408,246 $1,335,978
========== ==========
The Partnership and Northern Border Pipeline have 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 Partnership entered
into a $275 million four-year credit agreement (2003 Partnership Credit
Agreement) with certain financial institutions in November 2003. The
2003 Partnership Credit Agreement replaced the 2001 Partnership Credit
Agreement. Both of the revolving credit facilities permit the
Partnership and 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. Both the Partnership and Northern Border Pipeline are
required to pay a fee on the principal commitment amounts.
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).
F-20
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
7. CREDIT FACILITIES, LONG-TERM DEBT AND CAPITAL LEASES (continued)
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.
In March 2001, the Partnership completed a private offering of $225
million of 7.10% Senior Notes due 2011 (2001 Partnership Senior Notes).
The 2001 Partnership Senior Notes were subsequently exchanged in
registered offerings for notes with substantially identical terms. The
proceeds from the Partnership's senior notes were used to fund its
acquisitions in 2001.
In June 2001, the Partnership repaid Black Mesa's 10.7% Secured Senior
Notes due May 2004. The total repayment of approximately $13.6 million
consisted of remaining principal and interest of $12.4 million and an
early payment premium of $1.2 million. The early payment premium is
reflected in other expense on the consolidated statement of income.
Interest paid, net of amounts capitalized, during the years ended
December 31, 2003, 2002 and 2001 was $86.7 million, $88.2 million and
$86.5 million, respectively.
Aggregate repayments of long-term debt required for the next five
years, excluding payments required under Bear Paw Energy's capital
leases, are as follows: $5 million, $136 million, $5 million, $276
million and $4 million for 2004, 2005, 2006, 2007 and 2008,
respectively.
The indentures under which the 1999, 2001 and 2002 Pipeline Senior
Notes were issued do not limit the amount of indebtedness or other
obligations that Northern Border Pipeline may incur, but do contain
material financial covenants, including restrictions on the incurrence
of secured indebtedness. 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 to
be 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.
At December 31, 2003, Viking Gas Transmission has four series of senior
notes outstanding. Transportation service agreements have been pledged
as security for these senior notes. Viking Gas Transmission's senior
notes indenture provides for certain restrictions on the payment of
cash dividends on common stock. The most restrictive of these is that
the payment of cash dividends on common stock is prohibited unless debt
service funds in an amount equal to all scheduled payments of principal
and interest for the 180-day period following the current month-end
would remain on deposit following the dividend payment. At December 31,
2003, the requirement for accumulation of debt service funds prior to
payment of dividends to the Partnership was $3.7 million, which is
included in other assets on the consolidated balance sheet. The senior
notes contain certain financial covenants and at December 31, 2003,
Viking Gas Transmission was in compliance with its financial covenants.
F-21
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
7. CREDIT FACILITIES, LONG-TERM DEBT AND CAPITAL LEASES (continued)
The indentures under which the 2001 and 2000 Partnership Senior Notes
were issued do not limit the amount of indebtedness or other
obligations that the Partnership may incur, but do contain material
financial covenants, including restrictions on the incurrence of
secured indebtedness. The indentures also contain a provision that
would require the Partnership to offer to repurchase the 2001 and 2000
Partnership Senior Notes if either Standard & Poor's Rating Services or
Moody's Investor Service, Inc. rate the notes below investment grade
and the investment grade rating is not reinstated for a period of 40
days. The 2003 Partnership Credit Agreement requires the maintenance of
a ratio of consolidated EBITDA (consolidated net income plus minority
interests in net income, consolidated interest expense, income taxes,
depreciation and amortization and all other non-cash charges) to
consolidated interest expense of greater than 3 to 1. The 2003
Partnership Credit Agreement also requires the maintenance of the ratio
of consolidated total debt to adjusted consolidated EBITDA (EBITDA
adjusted for pro forma operating results of acquisitions made during
the year) of no more than 4.5 to 1. If the Partnership consummates one
or more acquisitions in which the aggregate purchase price is $25
million or more, the allowable ratio of consolidated total debt to
adjusted consolidated EBITDA temporarily increases to 5 to 1. At
December 31, 2003, the Partnership was in compliance with these
covenants.
Bear Paw Energy has entered into non-cancelable capital leases on
compressors. The capital leases incorporate annual interest rates
ranging from 7.10% to 8.85% and are for a term of five years, after
which Bear Paw Energy receives ownership of the equipment. Future
minimum payments under Bear Paw Energy's capital leases are as follows
(in thousands):
Years ending December 31,
2004 3,348
2005 3,145
2006 117
-------
$ 6,610
Less amount representing interest 520
-------
Present value of lease payments 6,090
Less: current portion 2,980
-------
Long-term portion $ 3,110
=======
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, 2000 Partnership Senior Notes, 2001 Partnership Senior
Notes, 2001 Pipeline Senior Notes, 2002 Pipeline Senior Notes and
Viking Gas Transmission Senior Notes was approximately $1,306 million
and $1,367 million at December 31, 2003 and 2002, respectively. The
Partnership presently intends to maintain the current schedule of
maturities for the 1999 Pipeline Senior Notes, 2000 Partnership Senior
Notes, 2001 Partnership Senior Notes, 2001 Pipeline Senior Notes, 2002
Pipeline Senior Notes and Viking Gas Transmission Senior Notes, which
will result in no gains or losses on their respective repayment. The
fair value of the 2003 Partnership Credit Agreement, 2002 Pipeline
Credit Agreement and 2001 Partnership Credit Agreement approximates the
carrying value since the interest rates are periodically adjusted to
reflect current market conditions.
F-22
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
8. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
The Partnership reflects in consolidated accumulated other
comprehensive income its 70% share of Northern Border Pipeline's
accumulated other comprehensive income. The remaining 30% is reflected
as an adjustment to minority interests in partners' equity. The
Partnership also reflects in consolidated accumulated other
comprehensive income its ownership share of accumulated other
comprehensive income of its unconsolidated affiliates (see Note 9).
As a result of the adoption of SFAS No. 133, the Partnership
reclassified $22.7 million from long-term debt to accumulated other
comprehensive income and $3.3 million from long-term debt to minority
interests in partners' equity related to unamortized proceeds from
interest rate swap agreements terminated prior to 2001. 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, the Partnership recorded a
non-cash loss of $0.5 million in accumulated other comprehensive income
and $0.3 million as an adjustment to minority interests in partners'
equity. The $40 million interest rate swap agreement terminated in
November 2001.
Prior to the anticipated issuance of fixed rate debt, both the
Partnership and Northern Border Pipeline have entered into forward
starting interest rate swap agreements. The interest rate swaps have
been 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 does 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
amounts paid to terminate the swaps were recorded in accumulated other
comprehensive income and amortized to interest expense over the term of
the hedged debt. The Partnership also recorded an adjustment to
minority interests in partners' equity for Northern Border Pipeline's
terminated swaps.
For the year ended December 31, 2002, Northern Border Pipeline received
$2.4 million from terminated interest rate swaps, of which $1.6 million
was recorded in accumulated other comprehensive income and $0.8 million
was recorded as an adjustment to minority interests in partners'
equity. For the year ended December 31, 2001, the Partnership and
Northern Border Pipeline paid $4.3 million and $4.1 million,
respectively, to terminate interest rate swaps, of which $7.2 million
was recorded in accumulated other comprehensive income and $1.2 million
was recorded as an adjustment to minority interests in partners'
equity.
During the years ended December 31, 2003, 2002 and 2001, the
Partnership and Northern Border Pipeline amortized approximately $2.2
million, $2.1 million and $2.1 million, respectively, related to the
terminated derivatives, as a reduction to interest expense from
accumulated other comprehensive income. A comparable amount is expected
to be amortized in 2004.
At December 31, 2003 and 2002, the Partnership had outstanding interest
rate swaps with notional amounts totaling $150 million and $225
million, respectively. Under the interest rate swap agreements, the
Partnership
F-23
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
8. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (continued)
makes payments to counterparties at variable rates based on the London
Interbank Offered Rate and in return receives payments based on a 7.10%
fixed rate. In October 2002, the Partnership agreed to an increase in
the variable interest rate on two of its interest rate swap agreements
with notional amounts totaling $150 million. As consideration for the
change to the variable interest rate, the Partnership received
approximately $18.2 million, which represented the fair value of the
financial instruments at the date of the adjustment. In March 2003, the
Partnership terminated one of its interest rate swaps with a notional
amount of $75 million and received $12.3 million. The Partnership used
the proceeds to repay amounts borrowed under its credit facility. The
Partnership records in long-term debt amounts received or paid related
to terminated or amended interest rate swap agreements for fair value
hedges with such amounts amortized to interest expense over the
remaining life of the interest rate swap agreement. During the year
ended December 31, 2003 and 2002, the Partnership amortized
approximately $3.4 million and $0.5 million, respectively, as a
reduction to interest expense. The Partnership expects to amortize
approximately $3.7 million in 2004 for these agreements. At December
31, 2003 and 2002, the average effective interest rate on the
Partnership's interest rate swap agreements was 3.72% and 3.97%,
respectively.
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.
Both the Partnership's and 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
senior notes issued by the Partnership in 2001 and by Northern Border
Pipeline in 2002. The accompanying consolidated balance sheet at
December 31, 2003 and 2002, reflects a non-cash gain of approximately
$19.6 million and $36.9 million, respectively, in derivative financial
instruments with a corresponding increase in long-term debt.
Bear Paw Energy periodically enters into commodity derivatives
contracts and fixed-price physical contracts. Bear Paw Energy primarily
utilizes price swaps and collars, which have been designated as cash
flow hedges, to hedge its exposure to gas and natural gas liquid price
volatility. During the years ended December 31, 2003 and 2002,
respectively, Bear Paw Energy recognized losses of $8.5 million and
$2.8 million from the settlement of derivative contracts. During the
period from late March 2001 to December 2001, Bear Paw Energy
recognized gains of $4.7 million from the settlement of derivative
contracts. Bear Paw Energy recognized a loss of $0.1 million for
ineffective hedges in both 2003 and 2002, which is included in
operating revenues. At December 31, 2003 and 2002, the consolidated
balance sheet reflected non-cash losses of approximately $5.7 million
and $4.1 million, respectively, in derivative financial instruments
with
F-24
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
8. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (continued)
corresponding reductions of $5.5 million and $4.0 million,
respectively, in accumulated other comprehensive income. For 2004, if
prices remain at current levels, Bear Paw Energy expects to reclassify
approximately $5.5 million from accumulated other comprehensive income
as a reduction to operating revenues. However, this reduction would be
offset with increased operating revenues due to the higher prices
assumed.
At September 30, 2001, Bear Paw Energy had outstanding commodity price
swap arrangements with ENA, which had been accounted for as cash flow
hedges, and resulted in Bear Paw Energy recording a non-cash gain of
approximately $6.7 million in accumulated other comprehensive income.
During the fourth quarter of 2001, the Partnership determined that ENA
was no longer likely to honor the obligations it had to Bear Paw Energy
for these derivatives and terminated the swap arrangements (see Note
17). In accordance with SFAS No. 133, Bear Paw Energy ceased to account
for these derivatives as hedges. The gain previously recorded in
accumulated other comprehensive income is reflected in earnings in the
same periods during which the hedged forecasted transactions will
affect earnings. During the years ended December 31, 2003, 2002 and
2001, the Partnership recorded approximately $0.3 million, $4.6 million
and $1.4 million, respectively, in earnings and expects to record
approximately $0.2 million in earnings in 2004.
9. UNCONSOLIDATED AFFILIATES
The Partnership's investments in unconsolidated affiliates which are
accounted for by the equity method is as follows:
Net December 31,
Ownership --------------------
(In thousands) Interest 2003 2002
- ----------------- --------- -------- --------
Bighorn (a) $ 94,153 $ 96,151
Fort Union 33% 70,278 68,937
Lost Creek 35% 71,177 69,297
Guardian Pipeline 33% 32,558 --
Other Various -- 10,130
-------- --------
$268,166(b) $244,515
======== ========
(a) The Partnership held a 49% common membership interest in
Bighorn and 100% of the non-voting preferred A shares of
Bighorn at December 31, 2003 and 2002. Bighorn's ownership
structure consists of common membership interests and
non-voting preferred A and B shares. Both of the non-voting
classes of shares are subject to certain distribution
preferences and limitations based on the cumulative number of
wells connected to the Bighorn system at the end of each
calendar year. These shares will receive an income allocation
equal to the cash distributions received and are not entitled
to any other allocations of income or distributions of cash.
Ownership of these shares does not affect the amount of
capital contributions that are required to be made to the
operations of Bighorn by the owners of the common membership
interests.
(b) At December 31, 2003 and 2002, the unamortized excess of the
Partnership's investments in unconsolidated affiliates over
the underlying fair value of the net assets accounted for
under the equity method was $181.6 million and $180.1 million,
respectively.
F-25
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
9. UNCONSOLIDATED AFFILIATES (continued)
The Partnership's equity earnings (losses) of unconsolidated affiliates
is as follows:
(In thousands) 2003 2002 2001(a)
- ----------------- ------- ------- -------
Bighorn $ 6,467 $ 3,764 $ (875)
Fort Union 5,953 5,540 1,514
Lost Creek 4,403 3,678 188
Guardian Pipeline 1,992 -- --
Other -- 1,588 870
------- ------- -------
$18,815 $14,570 $ 1,697
======= ======= =======
(a) As discussed in Note 4, the Partnership has adopted SFAS No. 142 and
beginning January 1, 2002, the Partnership is no longer recording
amortization expense related to goodwill. The equity earnings (losses)
of unconsolidated affiliates included goodwill amortization of $6.3
million in 2001.
Summarized combined financial information of the Partnership's
unconsolidated affiliates is presented below:
December 31,
----------------------
(In thousands) 2003 (a) 2002
- ---------------------------------------- -------- ---------
Balance sheet
Current assets $ 34,136 $ 30,127
Property, plant and equipment, net 469,837 204,019
Other noncurrent assets 3,487 3,337
Current liabilities 24,552 14,549
Long-term debt 253,620 89,697
Other noncurrent liabilities 5,574 7,114
Accumulated other comprehensive income (4,958) (7,114)
Owners' equity 228,672 133,237
(In thousands) 2003(a) 2002 2001
- --------------------- ------- ------- -------
Income statement
Operating revenues $94,318 $57,364 $41,206
Operating expenses 31,922 17,976 15,458
Net income 42,588 33,065 19,312
Distributions paid to
the Partnership $16,262 $10,820 $ 7,083
(a) Includes results for Guardian Pipeline after it was acquired in January
2003.
10. PARTNERS' EQUITY
At December 31, 2003, partners' equity consisted of 46,397,214 common
units representing an effective 98% limited partner interest in the
Partnership (including 1.1% held by Northern Plains and 5.8% held by
Sundance Assets, L.P., an indirect subsidiary of Enron) and a 2%
general partner interest. At December 31, 2002, partners' equity
consisted of 43,809,714 common units representing an effective 98%
limited partner interest in the Partnership (including 1.1% held by
Northern Plains and 6.2% held by Sundance Assets, L.P., an indirect
subsidiary of Enron) and a 2% general partner interest.
F-26
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
10. PARTNERS' EQUITY (continued)
The dispositive power of Sundance Assets is shared by Enron and
Citibank, N.A. In conjunction with the issuance of additional common
units, the Partnership's general partners are required to make equity
contributions to the Partnership to maintain a 2% general partner
interest in accordance with the partnership agreements.
In May and June 2003, the Partnership sold 2,250,000 and 337,500 common
units, respectively. In July 2002, the Partnership sold 2,186,700
common units. In April and May of 2001, the Partnership sold 407,550
and 4,000,000 common units, respectively. The net proceeds from the
sale of common units and the general partners' contributions totaled
approximately $102.2 million in 2003, $75.4 million in 2002 and $172.2
million in 2001 and were primarily used to repay indebtedness
outstanding.
The Partnership will make distributions to its partners with respect to
each calendar quarter in an amount equal to 100% of its Available Cash.
"Available Cash" generally consists of all of the cash receipts of the
Partnership adjusted for its cash disbursements and net changes to cash
reserves. Available Cash will generally be distributed 98% to the
Unitholders and 2% to the General Partners. As an incentive, the
General Partners' percentage interest in quarterly distributions is
increased after certain specified target levels are met. Under the
incentive distribution provisions, the General Partners receive 15% of
amounts distributed in excess of $0.605 per common unit, 25% of amounts
distributed in excess of $0.715 per unit and 50% of amounts distributed
in excess of $0.935 per unit. Partnership income is allocated to the
General Partners and the limited partners in accordance with their
respective partnership percentages, after giving effect to any priority
income allocations for incentive distributions that are allocated to
the General Partners. For the years ended December 31, 2003, 2002 and
2001, incentive distributions to the General Partners totaled $7.7
million, $7.3 million and $4.3 million, respectively.
11. COMMITMENTS AND CONTINGENCIES
Firm Transportation Obligations and Other Commitments
Crestone Energy Ventures has firm transportation agreements with Fort
Union and Lost Creek. Under these agreements, Crestone Energy Ventures
must make specified minimum payments each month. Crestone Energy
Ventures recorded expenses of $11.7 million, $11.4 million and $8.6
million for the years ended December 31, 2003, 2002 and 2001,
respectively, related to these agreements. At December 31, 2003, the
estimated aggregate amounts of such required future payments were $11.6
million annually for 2004 through 2008 and $14.7 million for later
years.
At December 31, 2003, the Partnership has guaranteed the performance of
certain of its unconsolidated affiliates in connection with credit
agreements that expire in March 2009 and September 2009. Collectively,
at December 31, 2003, the amount of both guarantees was $4.4 million.
F-27
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
11. COMMITMENTS AND CONTINGENCIES (continued)
Operating Leases
Future minimum lease payments under non-cancelable operating leases on
office space, pipeline equipment, rights-of-way and vehicles are as
follows (in thousands):
Year ending December 31,
2004 8,035
2005 4,489
2006 4,024
2007 3,154
2008 2,978
Thereafter 3,928
-------
$26,608
=======
Expenses incurred related to these lease obligations for the years
ended December 31, 2003, 2002 and 2001, were $3.7 million, $2.0 million
and $1.1 million, respectively.
Cash Balance Plan
As further discussed in Note 17, 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. The Partnership
recorded charges associated with the termination of the cash balance
plan of $6.2 million in 2003. The Partnership believes this accrual is
adequate to cover the likely allocation of these costs to the
Partnership.
Capital Expenditures
Total capital expenditures for 2004 are estimated to be $29 million.
This includes approximately $19 million for interstate natural gas
pipeline facilities and $9 million for natural gas gathering and
processing facilities.
Funds required to meet the capital requirements for 2004 are
anticipated to be provided from credit facilities, issuance of
additional limited partnership interests in the Partnership and
operating cash flows.
Environmental Matters
The Partnership 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
F-28
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
11. COMMITMENTS AND CONTINGENCIES (continued)
principle on pipeline right-of-way lease and taxation issues, subject
to final documentation and necessary government approvals. 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 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 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. The Partnership believes that the resolution of
these issues will not have a material adverse impact on the
Partnership's results of operations or financial position.
12. INCOME TAXES
Components of the income tax provision applicable to continuing
operations and income taxes paid by the Partnership's corporate
subsidiaries are as follows (in thousands):
Year Ended December 31,
---------------------------
2003 2002 2001
------- ------- -------
Taxes currently payable:
Federal $ 900 $ 453 $ 430
State 311 87 116
Foreign 188 -- --
------- ------- -------
Total 1,399 540 546
------- ------- -------
Taxes deferred:
Federal 2,841 934 (60)
State 652 169 13
Foreign 473 -- --
------- ------- -------
Total 3,966 1,103 (47)
------- ------- -------
Total tax provision $ 5,365 $ 1,643 $ 499
======= ======= =======
Income taxes paid $ 1,544 $ 32 $ 1,122
======= ======= =======
The difference between the statutory federal income tax rate and the
Partnership's effective income tax rate is summarized as follows:
Year Ended December 31,
----------------------------------
2003 2002 2001
-------- -------- --------
Federal income tax rate 35.0% 35.0% 35.0%
Increase (decrease) as a result of:
Partnership earnings not subject
to tax (35.0) (35.0) (35.0)
Corporate subsidiary earnings
subject to tax (4.3) 1.2 0.4
State taxes (1.1) 0.2 0.2
Foreign taxes (0.8) -- --
-------- -------- --------
Effective tax rate (6.2%) 1.4% 0.6%
======== ======== ========
F-29
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
12. INCOME TAXES (continued)
Deferred tax assets and liabilities result from the following (in
thousands):
December 31,
-----------------
2003 2002
------- -------
Deferred tax assets:
Net operating loss $ 6,379 $ 8,824
Plant related differences 670 --
Joint venture income 675 --
Other 816 735
------- -------
Total deferred tax assets $ 8,540 $ 9,559
------- -------
Deferred tax liabilities:
Goodwill $ 4,383 $ 3,659
Accelerated depreciation and
other plant related differences 3,829 6,350
Partnership income 3,226 --
------- -------
Total deferred tax liabilities $11,438 $10,009
------- -------
Net deferred tax liabilities $ 2,898 $ 450
======= =======
The Partnership had available, at December 31, 2003, approximately $6.4
million of tax benefits related to net operating loss carryforwards,
which will expire between the years 2008 and 2023. The Partnership
believes that it is more likely than not that the tax benefits of the
net operating loss carryforwards will be utilized prior to their
expiration; therefore, no valuation allowance is necessary.
13. ACCOUNTING PRONOUNCEMENTS
In 2001, the 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, the Partnership's subsidiaries are obligated by
contractual terms or regulatory requirements to remove facilities or
perform other remediation upon retirement. The Partnership has, where
possible, developed its estimate of the retirement obligations.
Effective January 1, 2003, the Partnership adopted SFAS No. 143. The
implementation of SFAS No. 143 resulted in an increase in net property,
plant and equipment of $2.5 million, an increase in reserves and
deferred credits of $3.1 million and a reduction to net income of $0.6
million for the net-of-tax cumulative effect of change in accounting
principle. The impact of SFAS No. 143 on prior periods' results of
operations is immaterial. A reconciliation of the beginning and ending
aggregate carrying
F-30
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
13. ACCOUNTING PRONOUNCEMENTS (continued)
amount of the Partnership's asset retirement obligations for the year
ended December 31, 2003, is as follows (in thousands):
Balance at December 31, 2002 $ --
Cumulative effect of transition adjustment 3,496
Accretion expense 159
Liabilities transferred with asset sales (2,016)
-------
Balance at December 31, 2003 $ 1,639
=======
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 the Partnership's financial position or results of
operations.
In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 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 the Partnership's
financial position or results of operations.
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 the Partnership's
financial position or results of operations.
In May 2003, the Emerging Issues Task Force of the FASB issued EITF 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 the Partnership's financial position or results of
operations.
In December 2003, the FASB issued FIN 46 (revised December 2003), "Consolidation
of Variable Interest Entities," which addresses how a business enterprise should
evaluate whether it has a controlling financial interest in an entity through
means other than voting rights and accordingly should consolidate the entity;
such entities are known as variable interest entities. The Partnership will be
required to apply FIN 46 for periods ending after March 15, 2004. The
Partnership does not expect FIN 46 to have a material impact on its financial
position or results of operations.
F-31
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
14. BUSINESS SEGMENT INFORMATION
The Partnership's business is divided into three reportable segments,
defined as components of the enterprise about which financial
information is available and evaluated regularly by the Partnership's
executive management and the Partnership Policy Committee in deciding
how to allocate resources to an individual segment and in assessing
performance of the segment.
The Partnership's reportable segments are strategic business units that
offer different services. Each are managed separately because each
business requires different marketing strategies. The accounting
policies of the segments are the same as those described in the summary
of significant accounting policies in Note 2. The Partnership evaluates
performance based on EBITDA, earnings before interest, taxes,
depreciation and amortization less the allowance for equity funds used
during construction (AFUDC). Management uses EBITDA to compare the
financial performance of its segments and to internally manage those
business segments and believes that EBITDA is a good indicator of each
segment's performance. EBITDA should not be considered an alternative
to, or more meaningful than, net income or cash flow as determined in
accordance with GAAP. EBITDA calculations may vary from company to
company, so the Partnership's computation of EBITDA may not be
comparable to a similarly titled measure of another company. The
following table shows how EBITDA is calculated:
RECONCILIATION OF NET INCOME (LOSS) TO EBITDA
Natural
Interstate Gas
Natural Gathering
Gas and Coal
(In thousands) Pipelines Processing Slurry Other(e) Total
- ---------------------- ------------- ------------- --------- --------- ---------
2003
Net income (loss) $ 119,620 ($ 177,874) $ 3,658 ($ 33,858) ($ 88,454)
Cumulative effect of
change in accounting
principle, net of tax -- -- 434 209 643
Minority interest 44,460 -- -- -- 44,460
Interest expense, net 47,577 591 33 30,779 78,980
Depreciation and
amortization 66,245 233,185 1,848 699 301,977
Income tax 3,629 660 1,076 (936) 4,429
AFUDC (331) -- -- -- (331)
------------- ------------- --------- --------- ---------
EBITDA $ 281,200 $ 56,562 $ 7,049 ($ 3,107) $ 341,704
============= ============= ========= ========= =========
2002
Net income (loss) $ 107,510 $ 37,155 $ 4,136 ($ 35,125) $ 113,676
Minority interest 42,816 -- -- -- 42,816
Interest expense, net 51,525 794 33 30,546 82,898
Depreciation and
amortization 61,002 12,102 1,568 1,202 75,874
Income tax 730 -- 913 543 2,186
AFUDC (248) -- -- -- (248)
------------- ------------- --------- --------- ---------
EBITDA $ 263,335 $ 50,051 $ 6,650 ($ 2,834) $ 317,202
============= ============= ========= ========= =========
F-32
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
14. BUSINESS SEGMENT INFORMATION (continued)
RECONCILIATION OF NET INCOME (LOSS) TO EBITDA
Natural
Interstate Gas
Natural Gathering
Gas and Coal
(In thousands) Pipelines Processing Slurry Other(e) Total
- ----------------------- ------------- ------------- --------- --------- ---------
2001
Net income (loss) $ 102,325 $ 19,202 $ 4,490 ($ 38,231) $ 87,786
Minority interest 42,138 -- -- -- 42,138
Interest expense, net 55,351 706 717 33,134 89,908
Debt restructuring loss -- -- -- 1,213 1,213
Depreciation and
amortization 59,854 19,714 2,144 886 82,598
Income tax (411) -- 910 (213) 286
AFUDC (947) -- -- -- (947)
------------- ------------- --------- --------- ---------
EBITDA $ 258,310 $ 39,622 $ 8,261 ($ 3,211) $ 302,982
============= ============= ========= ========= =========
BUSINESS SEGMENT DATA
Natural
Interstate Gas
Natural Gathering
Gas and Coal
(In thousands) Pipelines Processing Slurry Other(e) Total
- ----------------------- ------------- ------------- ---------- ---------- ----------
2003 (a)
Revenues from
external customers $ 375,256 $ 159,263 $ 21,408 $ -- $ 555,927
Depreciation and
Amortization (b) 65,881 232,471 1,847 -- 300,199
Operating income (loss) 212,841 (199,012) 5,144 (7,036) 11,937
Interest expense, net 47,577 591 33 30,779 78,980
Equity earnings of
unconsolidated
affiliates 1,992 16,823 -- -- 18,815
Other income
(expense), net 453 5,566 57 (30) 6,046
Income tax expense 3,629 660 1,076 -- 5,365
Capital expenditures 19,497 8,981 1,804 -- 30,282
Identifiable assets 1,938,249 329,857 21,319 12,992 2,302,417
Investments in
unconsolidated
affiliates 32,558 235,608 -- -- 268,166
Total assets $ 1,970,807 $ 565,465 $ 21,319 $ 12,992 $2,570,583
F-33
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
14. BUSINESS SEGMENT INFORMATION (continued)
Natural
Interstate Gas
Natural Gathering
Gas and Coal
(In thousands) Pipelines Processing Slurry Other(e) Total
- ----------------------- ------------- ------------- ----------- ----------- -----------
2002
Revenues from
external customers $ 339,014 $ 126,622 $ 21,568 $ -- $ 487,204
Depreciation and
amortization 61,002 12,102 1,568 -- 74,672
Operating income (loss) 200,584 23,278 5,054 (5,557) 223,359
Interest expense, net 51,525 794 33 30,546 82,898
Equity earnings
unconsolidated
affiliates -- 14,570 -- -- 14,570
Other income
(expense), net 1,997 101 28 (129) 1,997
Income tax expense 730 -- 913 -- 1,643
Capital expenditures 16,579 33,718 441 -- 50,738
Identifiable assets 1,848,960 574,896 20,206 27,359 2,471,421
Investments in
unconsolidated
affiliates -- 244,515 -- -- 244,515
Total assets $ 1,848,960 $ 819,411 $ 20,206 $ 27,359 $ 2,715,936
2001 (c)(d)
Revenues from
external customers $ 322,584 $ 111,372 $ 22,041 $ -- $ 455,997
Depreciation and
amortization 59,854 13,426 2,144 -- 75,424
Operating income (loss) 199,822 17,400 5,953 (3,055) 220,120
Interest expense, net 55,351 706 717 33,134 89,908
Equity earnings
unconsolidated
affiliates -- 1,697 -- -- 1,697
Other income
(expense), net (419) 811 164 (1,534) (978)
Income tax expense
(benefit) (411) -- 910 -- 499
Capital expenditures 57,021 69,143 250 -- 126,414
Identifiable assets 1,858,902 552,520 22,009 14,195 2,447,626
Investments in
unconsolidated
affiliates -- 239,729 -- -- 239,729
Total assets $ 1,858,902 $ 792,249 $ 22,009 $ 14,195 $ 2,687,355
F-34
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
14. BUSINESS SEGMENT INFORMATION (continued)
(a) Includes interstate natural gas pipeline results of Viking Gas Transmission
commencing from the effective date of acquisition in January 2003 (see Note
3).
(b) Natural gas gathering and processing results includes goodwill and asset
impairment charges of $219,080 (see Note 4).
(c) Includes interstate natural gas pipeline results of Midwestern Gas
Transmission commencing from the effective date of acquisition in May 2001
(see Note 3).
(d) Includes natural gas gathering and processing results of Bear Paw Energy
and Border Midstream commencing from the date of acquisition in March and
April of 2001, respectively (see Note 3).
(e) Includes other items not allocable to segments.
15. OTHER INCOME (EXPENSE)
Other income (expense) on the consolidated statement of income includes
such items as investment income, nonoperating revenues and expenses,
foreign currency gains and losses, and nonrecurring other income and
expense items. For the year ended December 31, 2003, other income also
included a $3.3 million payment received for a change in ownership of
the other partner in Bighorn Gas Gathering. For the year ended December
31, 2001, other expense also 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 $1.2 million for a loss on restructuring of Black Mesa
Pipeline's debt.
16. QUARTERLY FINANCIAL DATA (Unaudited)
Income Per Unit
(Loss) Income(Loss)
Operating From From
(In thousands, except Operating Income Continuing Continuing
per unit amounts) Revenues (Loss) Operations Operations
- --------------------- --------- --------- ---------- ----------
2003
First Quarter $ 138,175 $ 59,037 $ 33,302 $ 0.70
Second Quarter 134,362 56,904 27,719 0.56
Third Quarter 138,008 (160,764) (183,570) (3.92)
Fourth Quarter 145,382 56,760 30,542 0.60
2002
First Quarter $ 115,956 $ 55,968 $ 27,452 $ 0.60
Second Quarter 121,327 60,566 30,147 0.67
Third Quarter 123,878 59,915 31,236 0.66
Fourth Quarter 126,043 46,910 23,734 0.49
17. 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 and NBP Services were not included in the bankruptcy
filing and management believes that Northern Plains and NBP Services
will continue to be able to meet their operational and administrative
service obligations under the existing operating agreements. ENA, a
subsidiary of Enron, was included in the bankruptcy filing.
F-35
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
17. RELATIONSHIPS WITH ENRON (continued)
At the time of the bankruptcy filing, ENA had firm service agreements
with Northern Border Pipeline 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
consolidated statement of income. 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, will 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.
Crestone had provided gas gathering and administrative services to ENA
under a master services agreement. This agreement was terminated for
ENA's failure to pay approximately $2.1 million, which was recorded as
bad debt expense in 2001. Subsequent to the termination of the
agreement, the services are being provided through contracts directly
with the producers.
Bear Paw Energy had also periodically entered into certain swap
arrangements with ENA to hedge risks of changes in commodity prices
(see Note 8). Bear Paw Energy terminated the swap arrangements with ENA
prior to December 31, 2001, and recorded bad debt expense of
approximately $5.4 million.
The Partnership and its subsidiaries have filed proofs of claims
regarding the amount of damages for breach of contract and other claims
in the bankruptcy proceeding. However, the Partnership cannot predict
the amounts, if any, that it will collect or the timing of collection.
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.
F-36
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
17. RELATIONSHIPS WITH ENRON (continued)
Enron management has informed Northern Plains and NBP Services 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 and NBP
Services have advised us that each is a member of the ERISA 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 6.2 million has been estimated for the Partnership's
share of Northern Plains and NBP Services proportionate share of the up
to $200 million estimated termination costs authorized by the
Bankruptcy Court order. Under the operating agreements with Northern
Plains and the administrative services agreement with NBP Services,
these increased costs may be the Partnership's responsibility. The
Partnership has accrued this amount to satisfy claims of reimbursement
for these termination costs. While the final amounts have not been
determined, the Partnership believes this accrual is adequate to cover
the allocation of these costs to the Partnership.
Management continues to monitor developments at Enron, to assess the
impact on the Partnership of its existing agreements and relationships
with Enron and to take appropriate action to protect the interests of
the Partnership.
18. 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 January 1, 2008, the cash distribution policy will be
adjusted to maintain a consistent capital structure. The Partnership
will be responsible for its ownership share of each equity cash call
(currently 70%). 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.
On February 9, 2004, the Partnership declared a cash distribution of
$0.80 per unit ($3.20 per unit on an annualized basis) for the quarter
ended December 31, 2003. The distribution is payable February 20, 2004,
to unitholders of record at February 17, 2004.
F-37
INDEPENDENT AUDITORS' REPORT ON SCHEDULE
Northern Border Partners, L.P.:
We have audited in accordance with auditing standards generally accepted in the
United States of America, the consolidated financial statements of Northern
Border Partners, L.P. and Subsidiaries 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 Partners,
L.P. and Subsidiaries listed in Item 14 of Part IV of this Form 10-K is the
responsibility of the Company's management and is presented for purposes of
complying with the Securities and Exchange Commission's rules and is not part of
the basic financial statements. This schedule has been subjected to the auditing
procedures applied in the audits of the basic financial statements and, in our
opinion, fairly states in all material respects, the financial data required to
be set forth therein in relation to the basic financial statements taken as a
whole.
KPMG LLP
Omaha, Nebraska
January 27, 2004
S-1
SCHEDULE II
NORTHERN BORDER PARTNERS, L.P. AND SUBSIDIARIES
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 $ 5,611 $ -- $ 10,261 $ 7,644
2002 $ 2,531 $ 9,763 $ -- $ -- $ 12,294
2001 $ 1,800 $ 731 $ -- $ -- $ 2,531
Allowance for
doubtful accounts
2003 $ 12,392 $ 52 $ -- $ -- $ 12,444
2002 $ 10,743 $ 3,463 $ 52 $ 1,866 $ 12,392
2001 $ -- $ 10,743 $ -- $ -- $ 10,743
S-2
INDEX TO EXHIBITS
*3.1 Form of Amended and Restated Agreement of Limited
Partnership of Northern Border Partners, L.P.
(Exhibit 3.1 No. 2 to the Partnership's Form S-1
Registration Statement, Registration No. 33-66158
("Form S-1")).
*3.2 Form of Amended and Restated Agreement of Limited
Partnership For Northern Border Intermediate Limited
Partnership (Exhibit 10.1 to Form S-1).
*4.1 Indenture, dated as of June 2, 2000, between the
registrants and Bank One Trust Company, N.A. (Exhibit
4.1 to the Partnership's Quarterly Report on Form
10-Q for the quarterly period ended June 30, 2000
("June 2000 10-Q")).
*4.2 First Supplemental Indenture, dated as of September
14, 2000, between the registrants and Bank One Trust
Company, N.A. (Exhibit 4.2 to Form S-4 Registration
Statement, Registration No. 333-46212 ("NBP Form
S-4")).
*4.3 Indenture, dated as of March 21, 2001, between
Northern Border Partners, L.P. and Northern Border
Intermediate Limited Partnership and Bank One Trust
Company, N.A., Trustee (Exhibit 4.3 to Northern
Border Partners, L.P. Form 10-K for the year ended
December 31, 2001).
*4.4 Indenture, dated as of August 17, 1999, between
Northern Border Pipeline Company and Bank One Trust
Company, NA, successor to The First National Bank of
Chicago, as trustee. (Exhibit No. 4.1 to Northern
Border Pipeline Company's Form S-4 Registration
Statement, Registration No. 333-88577 ("NB Form
S-4")).
*4.5 Indenture, dated as of September 17, 2001, between
Northern Border Pipeline Company and Bank Trust
Company, N.A. (Exhibit 4.2 to Northern Border
Pipeline Company's Registration Statement on Form
S-4, Registration No. 333-73282 ("2001 NB Form
S-4")).
*4.6 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 Northern Border Pipeline Company General Partnership
Agreement between Northern Plains Natural Gas
Company, Northwest Border Pipeline Company, Pan
Border Gas Company, TransCanada Border Pipeline Ltd.
and TransCan Northern Ltd., effective March 9, 1978,
as amended (Exhibit 10.2 to Form S-1).
*10.2 Form of Seventh Supplement Amending Northern Border
Pipeline Company General Partnership Agreement
(Exhibit 10.15 to Form S-1).
*10.3 Eighth Supplement Amending Northern Border Pipeline
Company General Partnership Agreement (Exhibit 10.15
to NB Form S-4).
*10.4 Ninth Supplement Amending Northern Border Pipeline
Company General Partnership Agreement (Exhibit 10.37
to 2001 Form S-4).
*10.5 Operating Agreement between Northern Border Pipeline
Company and Northern Plains Natural Gas Company,
dated February 28, 1980 (Exhibit 10.3 to Form S-1).
*10.6 Administrative Services Agreement between NBP
Services Corporation, Northern Border Partners, L.P.
and Northern Border Intermediate Limited Partnership
(Exhibit 10.4 to Form S-1).
10.7 Credit Agreement, dated as of November 24, 2003,
among Northern Border Partners, L.P., SunTrust Bank,
Harris Nesbitt Corp., Wachovia Bank, National
Association, Citigroup, N.A., SunTrust Capital
Markets, Inc., and the Lenders (as named therein).
*10.8 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).
*10.9 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).
*10.10 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).
*10.11 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).
*10.12 Operating Agreement between Midwestern Gas
Transmission Company and Northern Plains Natural Gas
Company dated as of April 1, 2001. (Exhibit 10.38 to
Northern Border Partners, L.P.'s Form 10-K for the
year ended December 31, 2001).
*10.13 Operating Agreement between Viking Gas Transmission
Company and Northern Plains Natural Gas Company dated
as of January 17, 2003.Exhibit 10.18 to Northern
Border Partners, L.P.'s Form 10-K for the year ended
December 31, 2002)
*10.14 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")).
12.1 Statement re computation of ratios
21 The subsidiaries of Northern Border Partners, L.P.
are Northern Border Intermediate Limited Partnership;
Northern Border Pipeline Company; Crestone Energy
Ventures, L.L.C.; Bear Paw Investments, LLC; Bear Paw
Energy, LLC; Border Midwestern Company; Midwestern
Gas Transmission Company; Border Viking Company; and
Viking Gas Transmission Company.
23.01 Consent of KPMG LLP.
31.1 Certification of principal executive office 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
Amendment No. 1 to Form S-8, 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.