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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 amort